Final Environmental Impact Statement 

FLORIDIAN NATURAL GAS 

STORAGE PROJECT 

Floridian Natural Gas Storage Company, LLC Docket No. CP08-13-000 

Pre-File No. PF07-03-000 

FERC/EIS 0221 

Federal Energy Regulatory Commission 

Office of Energy Projects 

Washington, DC 20426 

Cooperating Agencies 

July 2008 
Floridian Natural Gas Storage Project

Final Environmental Impact Statement

FERC/EIS 0221

Docket Nos.CP08-13-000PF07-03-000July 2008
FEDERAL ENERGY REGULATORY COMMISSION

WASHINGTON, D.C. 20426

OFFICE OF ENERGY PROJECTS 

In Reply Refer To: 

OEP/DG2E/Gas Branch 3 

Floridian Natural Gas Storage Company LLC 

Docket No. CP08-13-000 

FERC/EIS 0221 

TO THE PARTY ADDRESSED: 

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

prepared this Final Environmental Impact Statement (EIS) for the natural gas pipeline facilities 

proposed by the Floridian Natural Gas Storage Company LLC (FGS) under the above-referenced 

docket. FGS’s proposed Floridian Gas Storage Project (Project) would be located approximately 

two miles north of the unincorporated municipality of Indiantown in Martin County, Florida. 

The Final EIS was prepared to satisfy the requirements of the National Environmental 

Policy Act (NEPA). The FERC staff concludes that the proposed Project, with the appropriate 

mitigation measures as recommended, would have limited adverse environmental impacts. 

The U.S. Army Corps of Engineers, the U.S. Environmental Protection Agency, and the 

U.S. Fish and Wildlife Service are cooperating agencies for the development of this EIS. A 

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

impact involved with the proposal and is involved in the NEPA analysis. 

The general purpose of the proposed Project is to respond to the growing demand for 

natural gas and natural gas infrastructure in the United States, and, more specifically, in Florida. 

The Project would enhance access to additional, competitively-priced supplies of natural gas by 

providing liquefaction, storage, and vaporization services to customers in Florida and the 

southeastern United States. 
Docket No. CP08-13-000 -2-

The Final EIS addresses the potential environmental effects of construction and operation 

of the facilities listed below. 

FGS proposes to construct and operate: 

• an approximately 53.1 acre liquefied natural gas storage facility; 

• an approximately 4-mile-long, 12-inch-diameter receiving pipeline to interconnect 

with and receive natural gas from the Gulfstream and/or Florida Power & Light (FPL) 

pipelines; 

• an approximately 4-mile-long, 24-inch-diameter sendout pipeline that would parallel 

the 12-inch pipeline and interconnect with and deliver natural gas from the storage 

facility to the Gulfstream and the FPL lateral pipelines; 

• interconnection points with the Gulfstream pipeline at milepost (MP) 4.18 and with 

the FPL lateral at MP 4.05; and 

• a metering and regulating station. 

FGS proposes to have the facilities installed and operational within 36 months of 

commencing construction; however, based on market conditions at the time of construction, the 

storage facility construction may be separated into two phases. 

The Final EIS has been placed in the public files of the FERC and is available for public 

inspection at: 

Federal Energy Regulatory Commission 

Public Reference Room 

888 First Street N.E., Room 2A 

Washington, DC 20426 

(202) 502-8371 

CD-ROM copies of the Final EIS have been mailed to Federal, state, and local agencies; 

public interest groups; individuals and affected landowners who requested a copy of the Final 

EIS or provided comments during scoping; libraries and newspapers in the Project area; and 

parties to this proceeding. Hard copy versions of the Final EIS were mailed to those specifically 

requesting them. A limited number of hard copies and CD-ROMs are available from the Public 

Reference Room identified above. 

In accordance with the Council on Environmental Quality’s regulations implementing 

NEPA, no agency decision on a proposed action may be made until 30 days after the EPA 

publishes a notice of availability of a Final EIS. 

Additional information about the project is available from the Commission's Office of 

External Affairs, at 1-866-208-FERC (3372) or on the FERC Internet website 

(http://www.ferc.gov). Using the “eLibrary link,” select “General Search” and enter the project 

docket number excluding the last three digits (i.e., CP08-13) in the “Docket Number” field. Be 

sure you have selected an appropriate date range. For assistance, please contact FERC Online 

Support at FERCOnlineSupport@ferc.gov or toll free at 1-866-208-3676, or TTY (202) 502-
-3- Docket No. CP08-13-000 

8659. The eLibrary link on the FERC Internet website also provides access to the texts of formal 

documents issued by the Commission, such as orders, notices, and rule makings. 

In addition, the FERC now 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. To register for this 

service, go to http://www.ferc.gov/esubscribenow.htm. 

Kimberly D. Bose, 

Secretary 
ES-1 Executive Summary

EXECUTIVE SUMMARY 

This final Environmental Impact Statement (EIS) for the Floridian Natural Gas Storage 

Project (Project) has been prepared by the staff of the Federal Energy Regulatory 

Commission (FERC or Commission), in cooperation with the U.S. Fish and Wildlife 

Service (FWS), U.S. Army Corps of Engineers (COE), and U.S. Environmental 

Protection Agency (EPA), to fulfill the requirements of the National Environmental 

Policy Act (NEPA); the Commission’s implementing regulations under Title 18, Code of 

Federal Regulations (CFR) Part 380; and the Council on Environmental Quality 

regulations for implementing NEPA. The purpose of this document is to inform the 

public, Commission, and various federal and state agencies about the environmental 

effects resulting from the construction and operation of the Project; identify and discuss 

project alternatives; and to recommend practical, reasonable, and appropriate mitigation 

measures that would avoid or reduce adverse impacts. The FERC is the federal agency 

responsible for authorizing applications to construct and operate liquefied natural gas 

(LNG) storage and natural gas transmission facilities. 

PROPOSED ACTION 

On December 21, 2006, Floridian Natural Gas Storage Company, LLC (FGS) filed a 

request with the FERC to implement the Commission’s Pre-filing Process for the FGS 

Project. The purpose of the Pre-filing Process is to encourage the early involvement of 

interested stakeholders, facilitate interagency cooperation, and identify and resolve issues 

before an application is filed with the FERC. 

On January 10, 2007, the FERC granted FGS’ request and established a Pre-filing docket 

number (PF07-3-000) to place information relevant to the proposed Project into the 

public record. 

On October 31, 2007, FGS filed an application with the FERC, in Docket No. CP08-13-

000, pursuant to Section 7(c) of the Natural Gas Act, as amended, and Parts 157 and 284 

of the FERC’s regulations. FGS requests Commission authorization to construct, own, 

operate, and maintain a LNG storage facility on a 144.63-acre site approximately two 

miles northwest of the unincorporated town of Indiantown, in Martin County, Florida. 

As stated by FGS, the purpose of the proposed Project is to respond to the growing 

demand for natural gas and natural gas infrastructure in the United States, and, more 

specifically, in Florida. The Project would enhance access to additional, competitivelypriced supplies of natural gas by providing liquefaction, storage, and vaporization 

services to customers in Florida and the southeastern United States and provide added 

supply during peak demand periods. 
Executive Summary ES-2

Specifically, the LNG storage facility would include: 

• two full-containment LNG storage tanks, each with a nominal working volume of 

184,750 cubic meters; 

• a liquefaction system with the capacity to process 100 million standard cubic feet 

per day (MMscfd); 

• a vaporization system with the capacity to process 800 MMscfd; and 

• a natural gas liquids storage system that could store up to 240,000 gallons of 

heavy hydrocarbons. 

FGS would design, construct, operate, and maintain the LNG storage facility in 

accordance with governing federal and state regulations, including the U.S. Department 

of Transportation’s (DOT) Federal Safety Standards for Liquefied Natural Gas Facilities 

(49 CFR Part 193) and the National Fire Protection Association’s (NFPA) Standards for 

the Production, Storage, and Handling of LNG (NFPA 59A). 

FGS also requests authorization to construct, own, operate, and maintain the following 

natural gas pipeline facilities in order to receive and deliver natural gas from the 

Gulfstream and Florida Gas Transmission (via a Florida Power & Light [FPL] lateral) 

interstate pipeline systems: 

• an approximately 4-mile-long, 12-inch-diameter receiving pipeline to interconnect 

with and receive natural gas from the Gulfstream and/or FPL lateral pipelines; 

• an approximately 4-mile-long, 24-inch-diameter sendout pipeline that would 

parallel the 12-inch-diameter pipeline and interconnect with and deliver natural 

gas from the storage facility to the Gulfstream and the FPL lateral pipelines; 

• interconnection points with the Gulfstream pipeline at milepost (MP) 4.18 and 

with the FPL lateral at MP 4.05; and 

• a metering and regulating station. 

The pipeline facilities would be designed, constructed, operated, and maintained in 

accordance with DOT’s Transportation of Natural or Other Gases by Pipeline: Minimum 

Federal Safety Standards (49 CFR 192). 

PUBLIC OUTREACH AND COMMENTS 

As part of our1

 Pre-filing review, we issued a Notice of Intent to Prepare an 

Environmental Impact Statement for the Proposed Floridian Natural Gas Storage Project 

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

Meeting on February 15, 2007. This notice was published in the Federal Register and 

sent to affected landowners; federal, state, and local government agencies; elected 

officials; environmental and public interest groups; Native American tribes; local 

libraries and newspapers; and other interested parties (collectively referred to as the 

environmental mailing list). We also conducted a public scoping meeting in Indiantown, 

 

1

 “We,” “us” and “our” refer to the environmental staff of the FERC’s Office of Energy Projects. 
ES-3 Executive Summary

Florida and a public site visit on March 7, 2007. A transcript of the scoping meeting and 

all written comments provided at the meeting as well as all comments provided in 

response to the NOI have been entered into the public record for the Project. In response 

to our notice, public site visits, and scoping meeting, we received comments from 

landowners, concerned citizens, public officials, and government agencies regarding the 

Project. These comments expressed concerns about Project effects on alternatives, 

wetlands, threatened and endangered species, vegetation, water resources, waste 

management, land use, visual resources, socioeconomics, air quality, noise, and public 

safety. 

In addition to the public notice and scoping process discussed above, we consulted with 

other key federal and state agencies, including the EPA, COE, FWS, and Florida 

Department of Environmental Protection to identify issues that should be addressed in 

this EIS. Interagency meetings were held on March 8, 2007 and December 6, 2007 to 

discuss the Project and its associated environmental review process. 

On March 21, 2008 the FERC issued a Notice of Availability of the Draft Environmental 

Impact Statement for the Floridian Natural Gas Storage Project (NOA) in the Federal 

Register and a draft EIS was mailed to all parties on our environmental mailing list. In 

accordance with the Council on Environmental Quality regulations implementing NEPA, 

a 45-day comment period was allotted for public comment. On April 16, 2008 a public 

meeting to hear comments on the draft EIS was held in Indiantown, Florida. A transcript 

of the meeting and all written comments provided in response to the draft EIS have been 

entered into the public record for the proposed Project. All timely comments received on 

the draft EIS are addressed in this final EIS, either as revisions to the text as appropriate, 

and/or as direct responses to each comment in Appendix D. 

This final EIS has been mailed to agencies, individuals, and organizations on our 

environmental mailing list, and submitted to the EPA for the formal public notice of 

availability. 

ALTERNATIVES CONSIDERED 

We considered several alternatives to the proposed action including the no action and 

postponed action alternatives, LNG system alternatives, LNG storage facility site 

alternatives, and pipeline system and route alternatives. The proposed Project is not an 

energy source itself, but is needed to improve current electrical generating system 

reliability. To the extent that this Project could make gas-fired generating facilities more 

attractive because of improved reliability, we discussed the status of alternative energy 

sources and energy conservation in Florida. 

LNG system alternatives considered include alternative natural gas storage facilities (e.g., 

salt domes, depleted oil and gas reservoirs, and aquifer storage), LNG import terminals, 

and pipeline expansion, looping, and compression. We also considered six alternative 

LNG storage facility sites, three pipeline route alternatives and several minor pipeline 

route variations. The Florida Public Service Commission (PSC) concluded that energy 

demand forecasts continue to surpass current energy conservation and renewable energy 

programs offered by Florida’s utilities and that local utilities should continue 
Executive Summary ES-4

investigating natural gas supply and delivery options such as natural gas storage to 

maintain diversity in the face of unplanned supply or distribution disruptions (Florida 

PSC, 2007). 

Based on our review of the Project, we have determined that, as modified by our 

recommended mitigation measures, the proposed Project is the preferred alternative that 

can meet the Project purpose with the minimum amount of environmental impact. 

PROJECT IMPACTS AND MITIGATION 

Construction of the Project would affect up to a total of 127.03 acres of land. 

Specifically, construction of the LNG storage facility and pipeline facilities would 

temporarily affect 55.58 and 71.45 acres of land, respectively. 

Operation of the LNG storage facility would permanently affect 53.10 acres; the 

remainder of the storage facility site, including the 2.48-acre expansion of an existing 

stormwater pond, would be preserved as open space. The permanent pipeline right-ofway, metering and regulating station, and pipeline interconnects would permanently 

affect 25.30 acres. 

The Project would have no permanent wetland impacts, but pipeline construction would 

temporarily impact 3.91 acres of wetlands, none of which qualify as high quality, 

sensitive, or special-status wetlands. The LNG storage facility construction would not 

impact any wetlands. 

Pipeline construction would cross five waterbodies, all of which are intermittent drainage 

ditches. FGS would use open-cut methods to cross four drainage ditches and would 

restore the ditches in accordance with FERC Procedures. FGS would bore under the 

ditch at MP 0.99 avoiding impacts to 0.03 acre of wetlands. Construction of the LNG 

storage facility would not adversely affect any waterbodies. 

Construction and operation of the Project would result in temporary impacts to other 

environmental resources including soils, vegetation, wildlife, land use, visual, and air and 

noise quality. Soils at the Project would be disturbed, but topography is nearly level and 

the soils have only a slight erodibility potential. The Project-related clearing would 

decrease vegetative cover and wildlife habitat, but much of this land was previously 

disturbed and is dominated by invasive species. Further, the LNG storage facility site 

was previously contaminated and is currently undergoing EPA-supervised remediation. 

We have determined that the Project would have no effect or is not likely to adversely 

affect any federally-listed threatened and endangered species. We have informally 

consulted with the FWS, which is a cooperating agency in the preparation of this EIS, 

regarding Project effects on listed species. The FWS has concurred with our 

determination of effect relative to federally-listed species. Consequently, the 

Commissions required consultation under Section 7 of the Endangered Species Act is 

complete. The Florida Fish and Wildlife Conservation Commission indicated the project 

impact to state-listed species should be negligible. 

The Project would not affect residential areas and would be consistent with local zoning 

and future land use plans. The viewshed of the Project would not be significantly 
ES-5 Executive Summary

impacted since the LNG storage tanks, which would be the most prominent features, 

would be consistent with the existing industrial character of the area. Operation of the 

LNG storage facility would not result in a detectable increase in noise at the nearest noise 

sensitive area. Because Martin County is classified as an attainment area for all criteria 

pollutants, a General Conformity review of the Project is not required. Criteria pollutant 

emissions from operation of the Project are not expected to exceed annual threshold 

limits under EPA’s Prevention of Significant Deterioration (PSD) and is not considered a 

major source under the Title V program. Other environmental resources, including 

geology, groundwater, and recreation would not be significantly affected by the Project. 

Cultural resource surveys of the affected Project area did not identify any archaeological 

sites or historic structures and the State Historic Preservation Officer has concurred that 

the Project would have no effect on any properties listed in, or eligible for listing in, the 

National Register of Historic Places. The Seminole and Miccosukee tribal 

representatives also concurred that no further cultural investigations were needed. 

Consequently, the Commission’s required consultation under Section 106 of the National 

Historic Preservation Act is complete. 

The Project would have a beneficial effect on the local economy and socioeconomics by 

creating an average of 270 temporary jobs, with a peak of 450 jobs in months 14 and 15 

of the project construction, and generating approximately $120 million in local 

expenditures over the 36-month construction period. Once the first storage tank is in 

operation, the Project would also create up to 33 permanent positions; contribute about 

$19 million annually to the local economy from Project spending, sales, and payroll; and 

pay at least $1.6 million annually in property taxes to Martin County. With the second 

storage tank in operation these benefits would increase. The Project would also provide 

some benefits to the environment by removing all invasive and exotic plant species at the 

Project site. 

Our evaluation of the front-end engineering design of the proposed LNG storage facility 

included a review of materials in cryogenic environments; insulation systems; cryogenic 

safety; thermodynamics; heat transfer; instrumentation; cryogenic processes; and other 

relevant safety systems. As a result of the technical review of the proposed design and 

installation of the LNG storage facility, we identified a number of concerns relating to the 

reliability, operability, and safety of the proposed design. In response to these issues, 

FGS provided a list of corrections or modifications to be included in the final design of 

the facility. The final EIS identifies specific recommendations to address the remainder 

of these issues in the next phase of project development if authorization is granted by the 

Commission. Thermal radiation and vapor dispersion exclusion zones were calculated 

and determined to be in compliance with 49 CFR Part 193. 

To reduce potential Project-related environmental impacts, FGS would implement several 

impact minimization and mitigation measures and plans including the following: 

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

(Plan); 

• the FERC’s Wetland and Waterbody Construction and Mitigation Procedures 

(Procedures); 
Executive Summary ES-6

• Spill Prevention, Control, and Countermeasures Plan; 

• Stormwater Pollution Prevention Plan; 

• Unanticipated Hazardous Waste Discovery Plan; 

• Preserve Area Management Plan; 

• Procedures Guiding the Discovery of Unanticipated Cultural Resources and 

Human Remains; 

• Draft Seismic Design Guidelines and Data Submittal Requirements for LNG 

Facilities; and 

• Emergency Response Plan. 

To further minimize potential impacts resulting from Project-related activities, we 

recommended several mitigation measures. These recommendations would minimize the 

establishment of exotic and invasive plant species during restoration and ensure 

consistency with coastal zone management efforts. 

MAJOR CONCLUSION 

We conclude that with the use of FGS’ proposed mitigation and our recommended 

mitigation measures, construction and operation of the proposed facilities would have 

limited adverse environmental impact. 

The primary support for this conclusion reasons for our decision is: 

• FGS would construct the LNG storage facility on a former industrial site that 

primarily consists of disturbed land with invasive exotic species; 

• the majority of FGS’ proposed pipeline right-of-way would be co-located with 

or parallel to existing rights-of-way; 

• FGS would implement our Plan and Procedures and other plans, which would 

minimize and mitigate impacts to natural resources during Project 

construction and operation; 

• the proposed LNG storage facility would comply with the siting requirements 

of Title 49 CFR Part 193; 

• FGS would incorporate appropriate features and modifications, as specified by 

staff’s recommendations, into the facility design to enhance the safety and 

operability of the proposed LNG facility; and 

• FGS would implement an environmental inspection and monitoring program 

that would ensure compliance with all proposed and recommended mitigation 

measures. 
1-1 1.0 – Introduction

1.0 INTRODUCTION 

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

prepared this final Environmental Impact Statement (EIS) for public review and comment 

to assess the potential environmental effects that may occur as a result of the construction 

and operation of the Floridian Natural Gas Storage Project, which includes a proposed 

liquefied natural gas (LNG) storage facility and associated natural gas pipelines 

(collectively referred to as the Project or proposed action) in Martin County, Florida. 

Figure 1.0-1 shows the general location of the Project site. 

The vertical line in the margin identifies text that has been modified in this final EIS and 

differs substantially from the corresponding text in the draft EIS. 

On October 31, 2007, Floridian Natural Gas Storage Company, LLC (FGS) filed an 

application with the FERC, in Docket No. CP08-13-000 under Section 7(c) of the Natural 

Gas Act, as amended, and Parts 157 and 284 of the Commission’s regulations, seeking a 

Certificate of Public Convenience and Necessity (Certificate) to construct, own, and 

operate a LNG storage facility and associated natural gas pipelines and aboveground 

facilities. The application was noticed in the Federal Register on November 16, 2007. 

1.1 PROJECT PURPOSE AND NEED 

The purpose of the Project is to provide facilities necessary to liquefy, store, vaporize, 

and transport approximately four billion cubic feet (Bcf) of natural gas to: 

• meet the growing demand for natural gas and natural gas infrastructure in 

Florida; 

• increase the reliability and security of the energy supply in Florida and the 

region; 

• help stabilize and reduce the ultimate cost of fuel to consumers; 

• provide added supply during peak demand and an emergency physical reserve 

on occasions when supply is shut in; and 

• promote the more efficient use of the existing natural gas infrastructure within 

Florida. 

Between 1990 and 2004, over 90 percent of the new electric power generation 

constructed in Florida has been natural gas-fired. By 2014, the percentage of generation 

fueled by natural gas is projected to increase from about 30 percent to about 44 percent 

(Florida Public Service Commission, 2006). During this same period, the amount of 

electricity generated in Florida is expected to increase 30 percent, resulting in an overall 

increase in the demand for natural gas of 76 percent from today’s levels. At this time, 

natural gas pipelines serving the state are all fully subscribed and peak day demand is 

reaching the deliverability limits of the pipelines. As a result, there is a strong need 

within Florida for natural gas storage that will increase supply reliability and price 

stability. 
1.0 – Introduction 1-2 

Figure 1.0-1 

FGS Project 

General Location Map 
1-3 1.0 – Introduction

1.2 PURPOSE AND SCOPE OF THIS EIS 

The FERC is the federal agency responsible for authorizing applications to construct and 

operate onshore LNG storage facilities and interstate natural gas pipelines. The FERC is 

the lead federal agency for the preparation of this EIS in compliance with the 

requirements of the National Environmental Policy Act of 1969 (NEPA); the Council on 

Environmental Quality (CEQ) regulations for implementing NEPA (40 Code of Federal 

Regulations [CFR] 1500-1508); and FERC regulations implementing NEPA (18 CFR 

380). The FERC will use this EIS as an element in its review of FGS’ application to 

determine whether to authorize the Project and issue a Certificate. The Commission will 

consider the environmental issues, including our recommended mitigation measures, as 

well as non-environmental issues. Final authorization and issuance of a Certificate will 

be granted only if the Commission finds that the Project is in the public interest. The 

environmental impact assessment and mitigation discussed in this EIS are important 

factors in this final determination. 

The U.S. Fish and Wildlife Service (FWS), U.S. Army Corps of Engineers (COE), and 

U.S. Environmental Protection Agency (EPA) are federal cooperating agencies for the 

development of this EIS. A federal cooperating agency has jurisdiction by law or special 

expertise with respect to any environmental impact involved with the proposal and is 

involved with the NEPA analysis. 

Our principal purposes in preparing this EIS are to: 

• identify and assess potential effects on the natural and 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 impacts on the natural and human environment; 

• identify and recommend specific mitigation measures to minimize 

environmental impacts; and 

• facilitate public involvement in identifying significant environmental issues; 

and 

• respond to comments received on the draft EIS. 

Our1 analysis in this EIS focuses on facilities that would be under the FERC’s 

jurisdiction (i.e., the proposed LNG storage facility, natural gas pipelines, and 

aboveground facilities). Two nonjurisdictional facilities (water and wastewater pipelines) 

would also be constructed in association with the Project (see Section 2.2 of this EIS). 

This EIS describes the affected environment as it currently exists, discusses the 

environmental consequences of the proposed Project, and compares the proposed 

Project’s potential effects to those of other reasonable alternatives. This EIS also 

presents our conclusions and recommended mitigation measures. The environmental 

mailing list for this EIS is provided in appendix A. 

 

1

 “We,” “us” and “our” refer to the environmental staff of the FERC’s Office of Energy Projects. 
1.0 – Introduction 1-4 

1.3 PERMITS, APPROVALS, AND REGULATORY REQUIREMENTS 

As the lead federal agency responsible for the environmental review of the proposed 

Project, the FERC is required to comply with several federal laws and regulations 

including Section 7 of the Endangered Species Act of 1973 (ESA); Section 106 of the 

National Historic Preservation Act of 1966 (NHPA); and Section 307 of the Coastal Zone 

Management Act of 1972 (CZMA). The FERC encourages cooperation between 

applicants and state and local authorities, however, this does not mean that state and local 

agencies, through applications of state and local laws, may prohibit or unreasonably delay 

the construction or operation of facilities approved by the FERC. Any state or local 

permits issued with respect to jurisdictional facilities must be consistent with the 

conditions of any authorization issued by the FERC.2 Table 1.3-1 summarizes the status 

of major permits, approvals, and consultations for the Project, along with the status of 

FGS’ applications. 

Table 1.3-1 

Permits and Approvals 

Agency Permit/Approval/ Consultations Anticipated Filing Date and Status 

Federal 

Federal Energy 

Regulatory Commission 

Certificate (Section 7(c) of the 

Natural Gas Act) 

Application filed on October 31, 2007 

U.S. Department of the 

Army Corps of 

Engineers 

Section 404 of the Clean Water Act Application for an Environmental Resource 

Permit (ERP) filed on July 30, 2007. The 

ERP also serves as the §404 permit. The 

ERP was approved by the Florida 

Department of Environmental Protection on 

March 19, 2008. 

Federal Aviation 

Administration 

Permit for objects that may affect 

navigable airspace 

To be filed prior to construction 

U.S. Environmental 

Protection Agency 

Spill Prevention, Control and 

Countermeasure (SPCC) Plan 

approval 

To be filed prior to construction 

U.S. Fish and Wildlife 

Service 

Section 7 of ESA consultation Concurrence received June 2, 2008 

(storage facility site and pipeline) and June 

27, 2008 (Tampa Farms Construction 

Staging Area) 

State 

Florida Coastal 

Management Program 

Certification that the Project is 

consistent with the federal CZMA 

and Florida Coastal Management 

Program (FCMP) 

Application for an ERP filed on July 30, 

2007. The ERP also serves as the FCMP 

consistency determination. The ERP was 

approved by the Florida Department of 

Environmental Protection on March 19, 

2008. 

 

2

 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 (2n Cir. 1990); and Iroquois Gas Transmission System, L.P., et al., 52 

FERC 61,091 (1990) and 59 FERC 61,094 (1992). 
1-5 1.0 – Introduction

Table 1.3-1 (continued) 

Permits and Approvals 

Agency Permit/Approval/ Consultations Anticipated Filing Date and Status 

Florida Department of 

State 

Section 106 of the NHPA 

consultation 

Consultation with Florida Department of 

State and tribes completed. Florida 

Department of State – Division of Historic 

Resources concurred on January 14, 2008 

(storage facility site and pipeline) and June 

2, 2008 (Tampa Farms Construction 

Staging Area). 

Minor source air construction permit Filed August 2007; Permit issued March 

12, 2008 

National Pollutant Discharge 

Elimination System (NPDES) Permit 

to discharge industrial wastewater 

Filed January 2008 

Notice of Intent to discharge 

stormwater associated with 

construction activity 

To be filed at least two days prior to 

construction 

NPDES Notice of Intent to discharge 

hydrotest water 

To be filed prior to completion of the tank 

construction 

Environmental Resource Permit 

(ERP)/401 Water Quality 

Certification 

Application for the ERP for the pipelines 

filed July 30, 2007 FDEP issued notice of 

intent to issue the site permit on February 

14, 2008 and issued the ERP for the site 

on March 19, 2008 

Potable water interconnect Issued March 2008 

Florida Department of 

Environmental 

Protection 

Sanitary wastewater interconnect Filed February 2008 

South Florida Water 

Management District 

Water Use Permits Filed July 2007; Permits issued March 7, 

2008 (Landscape Irrigation Water Use) and 

April 21, 2008 (Hydrostatic Test Water 

Use)* 

Florida Fish and Wildlife 

Conservation 

Commission 

Relocation Permit (Gopher Tortoise) Prior to construction 

Local 

Martin County Major Development Master Site Plan Filed April 2007; approved May 6, 2008. 

Building Permit Prior to Construction 

* Potable water to be provided by the Indiantown Company, who have a Consumptive Use Permit covering the proposed 

FGS water use. 

Endangered Species Act 

Section 7 of the ESA, as amended, states that any project authorized, funded, or 

conducted by a federal agency (e.g., FERC) should not “jeopardize the continued 

existence of any endangered species or threatened species or result in the destruction or 

adverse modification of habitat of such species which is determined...to be critical” (16 
1.0 – Introduction 1-6 

United States Code [USC] §1536[a][2]). The FERC, or FGS as our non-federal 

representative, is required to consult with the FWS to determine whether any species 

federally listed or proposed for listing as endangered or threatened, or their designated 

critical habitat, occur in the vicinity of the proposed Project. If, upon review of existing 

data or data provided by FGS, the FERC determines that these species or habitats may be 

adversely affected by the proposed Project, the FERC is required to prepare a Biological 

Assessment to identify the nature and extent of the adverse impact and recommend 

measures that would avoid the habitat and/or species or reduce potential impacts to 

acceptable levels. If the FERC determines that no federally listed or proposed 

endangered or threatened species or their critical habitat would be affected by the 

proposed Project, no further action is necessary. See Section 4.6 for additional 

information regarding our ESA review. 

National Historic Preservation Act 

Section 106 of the NHPA requires the FERC to take into account the effects of its 

undertakings on properties listed in, or eligible for listing in, the National Register of 

Historic Places, 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. The FERC has requested that FGS, as our non-federal representative, assist 

in meeting the FERC’s obligations under Section 106 by preparing the necessary 

information and analysis as required by the ACHP procedures in 36 CFR 800. See 

Section 4.10 for additional information regarding Section 106 consultation. 

Coastal Zone Management Act 

The CZMA calls for the “effective management, beneficial use, protection, and 

development” of the nation’s coastal zone and promotes active state involvement in 

achieving those goals. As a means to reach those goals, the CZMA requires participating 

states to develop management programs that demonstrate how these states will meet their 

obligations and responsibilities in managing their coastal areas. In the state of Florida, 

the Florida Coastal Management Program (FCMP) has delegated the review of natural 

gas projects to the Florida Department of Environmental Protection (FDEP), which 

conducts the FCMP review as part of its overall permit application review. Because 

section 307 of the CZMA requires federal agency activities to be consistent to the 

maximum extent practicable with the enforceable policies of a state’s management 

program, the FERC has requested that FGS seek a determination of consistency with the 

FCMP. See Section 4.7.4 for additional information regarding the Project’s consistency 

with the FCMP. 

1.4 PUBLIC OUTREACH AND COMMENTS 

On December 21, 2006, FGS filed a request with the FERC to implement the 

Commission’s Pre-filing Process for the FGS Project. At that time, FGS was in the 

preliminary design stage of the proposed Project and no formal application had been filed 

with the FERC. On January 10, 2007, the FERC granted FGS’ request and established a 
1-7 1.0 – Introduction

Pre-filing docket number (PF07-3-000) to place information relevant to the proposed 

Project into the public record. The purpose of the Pre-filing Process is to encourage the 

early involvement of interested stakeholders, facilitate interagency cooperation, and 

identify and resolve issues before an application is filed with the FERC. 

As part of our Pre-filing review, we issued a Notice of Intent to Prepare an 

Environmental Impact Statement for the Proposed Floridian Natural Gas Storage 

Project, Request for Comments on Environmental Issues, and Notice of Public Scoping 

Meeting (NOI) on February 15, 2007. The NOI was published in the Federal Register 

and sent to affected landowners; federal, state, and local government agencies; elected 

officials; environmental and public interest groups; Native American tribes; local 

libraries and newspapers; and other interested parties (collectively referred to as the 

environmental mailing list). The NOI provided a summary of the proposed Project; 

outlined the NEPA-required environmental review process; provided a list of the then 

identified environmental issues; and requested comments on the scope of the analysis for 

the EIS. 

On March 7, 2007, the FERC conducted a public site visit and scoping meeting in 

Indiantown, Florida for the public to learn more about the proposed Project and provide 

comments on environmental issues to be addressed in this EIS. A transcript of the 

scoping meeting and all written comments received before, during, and after the scoping 

meeting are part of the public record for the Project and available on the FERC website 

(http://www.ferc.gov). Excluding representatives of FGS and the FERC, approximately 

20 people attended the public scoping meeting for the Project and we received verbal 

statements from seven individuals. During the Pre-filing and scoping periods for the 

Project, we received five written comment letters from members of the general public and 

federal and state resource agencies. 

In addition to the public notice and scoping process discussed above, the FERC consulted 

with other key federal and state agencies, including the EPA, COE, FWS, and FDEP to 

identify issues that should be addressed in this EIS. This agency consultation included 

participation in interagency meetings on March 8, 2007 and December 6, 2007 to discuss 

the Project and its associated environmental review process. 

In response to our notice, public site visits, and scoping meeting, we received comments 

from landowners, concerned citizens, public officials, and government agencies regarding 

the Project. These comments expressed concerns about Project effects on alternatives, 

wetlands, threatened and endangered species, vegetation, water resources, waste 

management, land use, visual resources, socioeconomics, air quality, noise, and public 

safety. All substantive comments received are addressed in the appropriate sections of 

this EIS. 

The FERC issued the draft EIS and a Notice of Availability (NOA) on March 21, 2008 

and filed it with the EPA. A formal notice indicating that the draft EIS was available was 

also published in the Federal Register and the document was mailed to approximately 

220 individuals and organizations on our environmental mailing list. The public had the 

opportunity to submit comments on the draft EIS until May 5, 2008. We received four 

comment letters from federal agencies; two from state agencies; one from FGS; and four 

from individuals. A public meeting to hear comments on the draft EIS was held in 
1.0 – Introduction 1-8 

Indiantown, Florida, on April 16, 2008. The location and time of the meeting was 

announced in the NOA. Statements were made by nine people at the public meeting and 

the majority was in support of the proposed Project. A transcript of the public meeting 

has been entered into the public record for the Project. All timely comments received on 

the draft EIS are addressed in this final EIS, either as revisions to the text as appropriate, 

and/or as direct responses to each comment (see appendix D). 

This final EIS has been mailed to the agencies, individuals, and organizations on our 

environmental mailing list, and submitted to the EPA for the formal public notice of 

availability. In accordance with CEQ regulations implementing NEPA, no agency 

decision on a proposed action may be made until 30 days after the EPA publishes a NOA 

of the final EIS. However, the CEQ regulations provide an exception to the rule when an 

agency decision is subject to a formal internal process that allows other agencies or the 

public to make their views known. In such cases, the agency decision may be made at 

the same time the notice of the final EIS is published, allowing both periods to run 

concurrently. Should the FERC authorize FGS’s proposed action, it would be subject to 

a 30-day rehearing period. Therefore, the FERC could issue its decision concurrently 

with the EPA’s notice of availability. 
2-1 2.0 – Description of the Proposed Action

2.0 DESCRIPTON FTHE PROSDACTIN 

As described previously, FGS is seeking: 

• a certificate to site, construct, and operate an LNG storage facility and associated 

facilities in Martin County, Florida; and 

• a certificate to construct and operate natural gas pipelines and associated 

aboveground facilities in Martin County, Florida. 

The Project would operate as follows: existing gas companies would deliver natural gas 

to the Project through interconnections with their existing pipelines during off-peak days. 

FGS would liquefy the gas and transfer the liquid (i.e., LNG) into full-containment 

storage tanks. On peak days, or during unexpected outages such as hurricanes, FGS 

would re-gasify the LNG and deliver the natural gas through a sendout pipeline back to 

the gas companies’ pipelines. 

The Project is proposed to be built in two phases. Section 2.5 (Construction Schedule) 

contains additional details regarding the phasing. For the purpose of this EIS, we have 

evaluated potential Project effects in terms of the full build-out of both phases. 

2.1 PROSED FACILTES 

This section describes the proposed LNG storage facility and the associated pipelines and 

aboveground facilities that would be located approximately two miles northwest of the 

unincorporated town of Indiantown, Florida. Figure 2.1-1 shows the location of Project 

facilities. Figure 2.1-2 shows the location of other land use and natural features in the 

Project area, which is defined herein as approximately a two-mile radius of the LNG 

storage facility site. 

2.1 LNG Storage FciltyDescripton 

The LNG storage facility would be located on a 144.63-acre site, which is bounded by 

State Route (SR) 710 (also known as Warfield Boulevard and as the Bee Line Highway), 

a CSX rail line, the Cogentrix 330 megawatt (MW) coal-fired power plant, a Florida 

Power & Light (FPL) electric transmission line right-of-way, the Louis Dreyfus citrus 

processing facility, the Tampa Farms wholesale egg production facility, and other 

agricultural uses. The storage facility would consist of the following major components: 

• two full-containment LNG storage tanks; 

• liquefaction system; 

• vapor handling system; 

• vaporization system; 

• natural gas liquids (NGL) storage; and 

• other miscellaneous facility buildings, utility systems, facilities, and safety 

controls. 
S R- 7 1 0

C S X R ailr o a d

St or a g e 

F a cilit y Sit e

Pr oj e ct 

Pi p eli n e

Pr o p o s e d 

M & R St ati o n

F P L 

I nt er c o n n e cti o n

G ulf str e a m

I nt er c o n n e cti o n

0. 0 0

0. 5 0

1. 0 0

1. 5 0

2. 0 0

2. 5 0

3. 5 0 3. 0 0

3. 9 5

4. 0 5

0. 2 5 0. 5 Mil e s

Fi g ur e 2. 1- 1

F G S Pr oj e ct

Pr oj e ct F a cilit y L o c ati o n M a p

L e g e n d

R o a d s

Mil e p o st

R ailr o a d

Pr oj e ct Pi p eli n e

St or a g e F a cilit y Sit e

M & R St ati o n

C o n str u cti o n St a gi n g Ar e a
FPL Martin 

Cooling Pond

FPL Martin 

Power Plant

Cogentrix Power Plant

and Cooling Pond

Indiantown

SR-710

Fox Brown Road

Allapattah Road

SR-76 Kanner Hwy

CSX Railroad

Indiantown Commerce 

and Technology Park

Proposed Secondary 

Access Road

St. Lucie Canal

Louis Dreyfus

Facility

Figure 2.1-2

FGS Project

Project Location Map

0 1 2 0.5

Miles

2-3

Legend Roads

Railroad

M&R Station

Proposed Access Road

Indiantown Commerce and Technology Park

Noise Sensitive Area 1 Project Area (2 mile radius 

from Project)

Hydrotest Water Pipeline

Project Pipeline

St orage Facility Site

Temporary Pump Houses

Construction Staging Are a
2.0 – Description of the Proposed Action 2-4 

The following sections describe these components. Figure 2.1-3 shows the plot plan of 

the storage facility site. 

2.1.1.1 Liquefaction System 

Natural gas would be delivered to the FGS site via a 12-inch-diameter receiving pipeline, 

which would allow delivery of natural gas from either the Gulfstream or Florida Gas 

Transmission (FGT) (via a FPL lateral) interstate pipeline systems. Once on-site, the gas 

would be converted through the proposed liquefaction system into a liquefied state. The 

mixed refrigerant (MR) required for cooling the natural gas is composed of methane (a 

greenhouse gas (GHG)), ethylene, propane, i-pentane, and nitrogen. The liquefaction 

system would consist of four MR trains, each sized to process up to 25 million standard 

cubic feet per day (MMscfd), for a total liquefaction capacity of 100 MMscfd. Each MR 

train would contain centrifugal refrigeration compressors rated at 13,000 horsepower (hp) 

that would refrigerate the gas to a temperature of -260 degrees Fahrenheit (°F), the point 

at which natural gas turns into liquid. 

2.1.1.2 LNG Storage Tank 

LNG transfer lines would transport the LNG to two, full-containment storage tanks 

designed to store a gross volume of 190,000 and a nominal working volume of 184,750 

cubic meters (m3

) of LNG at a temperature of -260°F and a design pressure of 2.5 pounds 

per square inch gauge (psig) (Figure 2.1-4). The storage tank would have a primary nine 

percent nickel steel inner container and a secondary pre-stressed concrete outer container 

wall; a reinforced concrete foundation; a concrete domed roof; and an aluminum 

insulated support deck suspended from the outer container roof over the inner container. 

The tank is designed and would be constructed so that both the primary and secondary 

containers are capable of independently containing the stored LNG. The primary 

container holds the cryogenic liquid under normal operating conditions. The secondary 

container would be capable of containing the cryogenic liquid and controlling boiloff 

vapors resulting from heat leak into the inner container. The outside diameter of the 

outer container would be approximately 280 feet and the height of the top of the dome 

would be approximately 174 feet above grade. The storage tanks would be enclosed 

within a tertiary earthen berm designed to contain the entire contents of one tank plus any 

displacements. 
Land Vault

Existing FPL 

Substation

SR 710

CSX Railroad

Spray Irrigation 

Field

0.1 0.05 0 0.1

Miles

Legend

Storage Facility Site

Stormwater Management Pond

Figure 2.1-3

FGS Project

Storage Facility Plot Plan

2-5
2-6

Figure 2.1-4 

FGS Project 

Typical Full Containment Storage Tank 

Suspended roof 

(insulated) 

Pre-stressed concrete 

outer tank wall 

Carbon steel liner 

Bottom heater 

Base Insulation 

Inner tank 

Reinforced concrete 

roof 

Perlite 

insulation 
2-7 2.0 – Description of the Proposed Action

The tank foundation slab would be set on grade and include an electric heating system to 

prevent freezing of the earth below the foundation slab. The space between the inner 

container and outer container walls would be insulated with a fiberglass resilient blanket 

and expanded perlite compacted to reduce long-term settling. This insulation would 

allow the LNG to be stored at -260°F while maintaining the outer container at near 

ambient temperature. The inner container’s bottom would be underlain by a cellular 

glass load-bearing insulation. The outer concrete container above the approximately 16-

foot-high thermal corner protection system (nine percent nickel) would be lined inside 

with carbon steel plates. This carbon steel liner would serve as a vapor barrier and to 

keep atmospheric moisture from reaching the insulation inside the outer container. To 

increase the safety of the tank, there would be no penetrations through the inner container 

or outer container sidewalls or bottom. All piping into and out of the tank would be 

located at the top of the tank. 

2.1.1.3 Vapor Handling System 

During normal operation, ambient heat input into the storage tanks and liquid-filled lines 

would cause a small amount of LNG to be vaporized. Some vaporization of LNG would 

also be caused by other factors, such as barometric pressure changes, heat input from 

pumping, and solar heat input from the piping system and tank walls. The vapor 

handling system would recover and compress these vapors (boil-off gas, or BOG) and 

combine them with the sendout natural gas when the liquefaction system is not operating. 

During liquefaction, BOG would be recovered from the storage tanks, warmed, and sent 

to the BOG compressors to be compressed up to the pressure required for regeneration of 

the pretreatment system. During an upset condition, all of the vapor would be directed to 

the interconnecting Gulfstream and FPL lateral pipelines to prevent over-pressuring of 

the storage tanks using the tail gas compressors. The vapor handling system would use 

five reciprocating BOG compressors rated at 1,700 hp coupled with five reciprocating tail 

gas compressors rated at 650 hp. 

2.1.1.4 Vaporization System 

LNG from the storage tanks would be pressurized and vaporized (i.e., returned to a 

gaseous state) so that natural gas could be sent out via the natural gas pipeline system. 

Each of the storage tanks would have three in-tank pumps to deliver the LNG from the 

storage tank to the natural gas booster pumps. The pressurized LNG discharged from the 

booster pumps would flow to the vaporizers. 

Four shell and tube vaporizers would be used to vaporize the LNG. Each vaporizer 

would be capable of vaporizing 200 MMscfd of natural gas, for a total vaporization 

capacity of 800 MMscfd. Hot water-ethylene-glycol (WEG) would be used as an 

intermediate heat transfer fluid to supply heat for the shell and tube vaporizers and the 

fuel gas heat exchangers. In this closed circulating system, the WEG would be pumped 

from the water baths in the fire-tube heaters prior to delivery to the vaporizers and fuel 

gas heat exchangers. The WEG system consists of direct fuel-gas fire-tube WEG heaters, 

an expansion drum, and hot WEG circulation pumps. The WEG heaters, each rated for a 

heat output duty of 83 million British thermal units per hour (MMBtu/hr), would heat the 
2.0 – Description of the Proposed Action 2-8 

WEG to 200°F. These pumps and vaporizers would be located within the earthen tertiary 

berm around the LNG storage tanks. 

After leaving the vaporizers, the high-pressure gas would pass through the 24-inchdiameter sendout pipeline to the metering and regulating (M&R) station and then to the 

Gulfstream and FPL lateral pipelines. 

2.1.1.5 NGL Storage System 

FGS proposes to install a NGL storage system that would be constructed in accordance 

with all applicable design codes and standards, including the Liquefied Petroleum Gas 

Code (NFPA 58). The NGL storage system would consist of four 60,000-gallon 

horizontal pressurized storage vessels. The stored NGLs would consist of heavy 

hydrocarbons (primarily n-butane, propane, and hexane) removed from the feed gas prior 

to the liquefaction process. 

The NGL extraction system would be designed to remove high molecular weight 

components typically present in the feed gas. During normal operations, FGS would reinject NGLs back into the sendout gas to meet pipeline tariff requirements and for Btu 

adjustment. During the aftermath of a hurricane or other natural gas supply interruption, 

however, excessive high molecular weight components would be present in the feed gas. 

Therefore, FGS proposes to install a NGL storage system to accommodate the additional 

NGLs that would accumulate during an upset condition. In addition, FGS proposes to 

use a NGL truck loading station to remove the excessive NGLs stored on-site. 

2.1.1.6 Other LNG Storage Facility Components 

The LNG storage facility would include safety controls (see Section 2.8) and several 

buildings (i.e., administration, maintenance, control, and electrical). The storage facility 

would also include the following utility systems: 

• Electrical power - An existing on-site FPL 230 kilo-Volt substation main 

power transformers and 13.8 kilo-Volt switchgear would provide electrical 

power. The anticipated peak operating load of the Project would be 

approximately 60 MW. 

• Redundant emergency generators – These generators would provide backup 

power for critical operations, including lighting and the control/hazard system. 

These generators would be diesel engine-driven and have two 60,000 gallon 

diesel fuel tanks, sufficient for five days of run time. A concrete containment 

dike, capable of holding the full capacity of a single diesel fuel tank plus any 

displacements, would contain any spills from the diesel fuel tanks. 

• Utility nitrogen - A liquid nitrogen dewar with ambient vaporizer would 

support maintenance purging of equipment and pipelines and operational 

blanket purges for certain equipment. 

• Instrument and plant air - An air compressor, instrument air dryer, and 

instrument air receiver would provide dry air for operation of control 
2-9 2.0 – Description of the Proposed Action

instruments and service air for operation of pneumatic tools and other 

maintenance needs. 

• Potable water and wastewater service – These services would be extended to 

the site by the Indiantown Company (a private utility company). 

The LNG storage facility would also include a truck loading station to allow for the 

transfer of LNG to other facilities by truck only during emergency situations such as 

hurricanes and other outages that disrupt the existing natural gas distribution 

infrastructure. The station would be capable of loading two trucks simultaneously. 

2.1 Pipelns adAbovegrund Faciltes 

In addition to the LNG storage facility, FGS proposes to construct and operate the 

following natural gas pipeline facilities in order to receive and deliver natural gas from 

the Gulfstream and Florida Gas Transmission (via a FPL lateral) interstate pipeline 

systems: 

• An approximately 4-mile-long, 12-inch-diameter receiving pipeline to 

interconnect with and receive natural gas from the Gulfstream and/or FPL lateral 

pipelines. 

• An approximately 4-mile-long, 24-inch-diameter sendout pipeline that would 

parallel the 12-inch-diameter pipeline and interconnect with and deliver natural 

gas from the storage facility to the Gulfstream and the FPL lateral pipelines. 

• Interconnection points with the 30-inch-diameter Gulfstream pipeline at milepost 

(MP) 4.18 and with the 20-inch-diameter FPL lateral to the FGT pipeline system 

at MP 4.05.1 Each interconnection would include a tap into the pipeline for a 

receiving and a sendout pipeline. Each of these interconnection would occur 

within an approximately 50- by 100-foot (0.11 acre each) graveled, fenced area. 

• A 2.75-acre aboveground M&R station, which would also include an odorant 

system. The liquefaction process would remove odorants from incoming gas 

prior to storage, and therefore, odorant would need to be added to the sendout gas. 

• Valves would be located on the LNG storage facility site, at the M&R station, and 

at the interconnection points. 

Due to the short length of each of the proposed pipelines, no compressor stations would 

be needed along the pipeline route. Figure 2.1-1 depicts the general location of these 

facilities. 

 

1

 Throughout this EIS, the location of specific features along the proposed pipelines, such as Project 

facilities and environmental resources, are identified by milepost (MP). Both Project pipelines begin at MP 

0.0 on the LNG storage facility site. 
2.0 – Description of the Proposed Action 2-10 

2. NOJURISDCTONAL FCITES

In addition to the facilities discussed in Section 2.1, the Project would require 

construction of facilities that do not fall under the jurisdiction of the FERC. These 

facilities include the extension of a potable water main and a sanitary sewer line by the 

Indiantown Company (a private utility company). The extension of the water and sewer 

lines to the Project would be completed as part of a larger utility improvement program 

designed to serve multiple customers. The portion of the program specifically for the 

Project includes the extension of approximately 2,305 feet of an 8-inch-diameter 

polyvinyl chloride (PVC) sanitary sewer line connecting to a sewer force main, and a 

similar length of 8-inch-diameter PVC water main. These utility lines would extend from 

the Indiantown Company system south of the property parallel to the CSX and SR 710 

rights-of-way, connecting to the northeast corner of the LNG storage facility site. The 

Indiantown Company has initiated the permitting process for the system extensions with 

the South Florida Water Management District (SFWMD), Martin County, and FDEP. 

Since these utility lines are subject to review by various state and local agencies and 

would occur in or parallel to existing highway or rail right-of-ways, we believe the 

construction of the nonjurisdictional water and sewer lines would have no significant 

impacts. 

2.3 LAND REQUIMNTS 

The construction and operational land requirements of the Project are summarized in the 

following sections. 

2.31 LNG Storage Fcilty

The proposed LNG storage facility site has a gross acreage of 144.63 acres. The storage 

facility site excludes a 6.88-acre area (referred to as the “land vault”) that would be 

retained by the current property owners (i.e., Gerdau Ameristeel). The land vault 

includes a mound of contaminated soil that has been remediated. FGS has an agreement 

with Gerdau Ameristeel that limits any potential future land use, occupancy, and 

assembly of persons in the vault area. Section 4.7.5 provides additional information 

regarding the land vault. Figure 2.1-3 shows the location of the vault relative to the 

storage facility site. 

Construction and operation of the storage facility (excluding the on-site pipeline 

facilities) would require 55.58 acres and 53.10 acres of land, respectively. 

The LNG storage facility site also includes the initial 0.59 mile of the pipeline and would 

affect 7.82 acres of land during construction. In order to avoid double counting of 

acreage, those areas on the storage facility site affected by pipeline construction are 

discussed in the pipeline section. Therefore, the storage facility site has a net acreage of 

136.81 acres (144.63 – 7.82 acres). 

Access to the LNG storage facility site would be from SR 710 via a driveway that crosses 

the CSX railway. This driveway would serve as the primary access to the facility for 

both construction and operations traffic. FGS is working on an agreement for a 
2-11 2.0 – Description of the Proposed Action

secondary access between the Indiantown Commerce and Technology Park and the 

storage facility site that would allow construction or operations access to the site if the 

primary access was blocked by a train on the CSX railway (see Figure 2.1-1). 

2.3 Pipelns adAbovegrund Faciltes 

2.3.2.1 Pipelines and Aboveground Facilities 

The proposed pipeline route originates at the LNG storage facility vaporizers (MP 0.00), 

traverses approximately 0.59 mile on the storage facility site, then follows the FPL 230 

kV transmission line right-of-way northwest until approximately MP 2.70, where it turns 

west and follows the FPL 500 kV transmission line right-of-way until reaching the 

proposed M&R station at MP 3.95. After the M&R station, the proposed route splits with 

the southern route connecting with the FPL lateral pipeline at MP 4.05 and the northern 

route connecting with the Gulfstream pipeline at MP 4.18. 

Construction of the proposed pipelines, including extra work areas, the construction 

staging area, the M&R station, and the interconnections with the FPL lateral and 

Gulfstream pipelines would affect 71.45 acres of land (including the 7.82 acres on the 

storage facility site). The proposed permanent pipeline right-of-way, M&R station, and 

interconnections with the FPL lateral and Gulfstream pipelines total 25.30 acres 

(including 3.55 acres on the storage facility site). Table 2.3-1 summarizes the affected 

land areas. 
2.0 – Description of the Proposed Action 2-12 

Table 2.3-1 

Locations and Land Requirements for the Proposed Pipeline Facilities 

Facility Milepost 

Land Affected by 

Construction 

(acres)1

Land Affected 

by Operation 

(acres)1

Pipeline Facilities 0.0-4.18 48.57 22.33 

Construction Staging Area 1.60 10.50 0.00 

M&R Station 3.95 2.75 2.75 

Interconnect with FPL Lateral 4.05 0.11 0.11 

Interconnect with Gulfstream 4.18 0.11 0.11 

Extra Work Areas 

1. Bore Entry East of Cogentrix Entry Road 0.99 0.75 0.00 

2. Bore Exit West of Cogentrix Rail Spur 1.02 0.23 0.00 

3. Temporary Work Space for Wetland Crossing 0.38 0.30 0.00 

4. Temporary Work Space for Wetland Crossing 0.46 0.53 0.00 

5. Temporary Work Space for Wetland Crossing 1.23 0.99 0.00 

6. Temporary Work Space for Wetland Crossing 1.50 0.87 0.00 

7. Temporary Work Space for Wetland Crossing 1.65 1.42 0.00 

8. Temporary Work Space for Wetland Crossing 2.12 1.51 0.00 

9. Temporary Work Space for Wetland Crossing 2.90 0.90 0.00 

10.Temporary Work Space for Wetland Crossing 3.45 0.87 0.00 

11.Temporary Work Space for Wetland Crossing 3.76 0.66 0.00 

12.Temporary Work Space for Wetland Crossing 4.01 0.07 0.00 

13.Temporary Work Space for Wetland Crossing 4.06 0.31 0.00 

Total: 71.45 25.30 1

 Acreages reflect a nominal 100-foot-wide construction right-of-way in uplands, 65-foot-wide construction right-of-way 

in wetlands, and 50-foot-wide permanent easement to be maintained along the pipeline route following construction. 

2.3.2.2 Pipeline Right-of-Way and Temporary Extra Workspaces 

Pipeline Right-of-Way Cross Section 

FGS proposes to construct the two pipelines (i.e., receiving and sendout) within a 100-

foot-wide construction right-of-way in the upland portion of the pipeline route and 65-

foot-wide construction right-of-way in wetland areas. These construction widths would 

encompass a 50-foot-wide permanent right-of-way offset from the centerline by five feet. 

Figures 2.3-1 and 2.3-2 show the typical pipeline construction right-of-way and wetland 

cross sections, respectively. 

Additional Temporary Workspaces 

Additional temporary workspaces would be required at entry and exit points of the pipe 

bore, as well as at each wetland crossing, as indicated in Table 2.3-1 above. Temporary 

workspaces would affect 9.41 acres, which would be restored and allowed to revert to 

pre-construction conditions upon completion of construction activities. Although FGS 
2-13 2.0 – Description of the Proposed Action

has identified areas where extra workspaces would be required, additional or alternative 

areas could be identified in the future due to changes in site-specific construction 

requirements. FGS would be required to file information on each of those areas for 

review and approval prior to use. 

Construction Staging Area 

A pipe receipt and temporary storage and contractor yard would be located at the off-site 

Tampa Farms property and require a total area of approximately 10.50 acres, which is 

already heavily disturbed from its prior use as a mulch yard. This property would only be 

used during construction and would be restored in accordance with FGS’ agreement with 

the property owners. 

Access Roads 

No new access roads (temporary or permanent) would be required for the pipelines and 

aboveground facilities. All construction access would be from the proposed pipeline 

right-of-way and existing private and electric transmission line access roads without any 

improvements. 
2-14

Figure 2.3-1 

FGS Project 

Proposed Pipeline Right-of-Way Section 

24’ – 29’ 52’ – 57’
2-15

Figure 2.3-2 

FGS Project 

Proposed Wetland Crossing Pipeline Right-of-Way Section 

15 
2.0 – Description of the Proposed Action 2-16 

2.4 CONSTRUI POCEDURS 

The Project would be designed and constructed in accordance with federal standards 

intended to protect the public by preventing or mitigating LNG and natural gas pipeline 

failures or accidents. Under provisions of the Natural Gas Pipeline Safety Act of 1968, 

as amended, FGS would design, construct, operate, and maintain the LNG storage facility 

in accordance with U.S. Department of Transportation’s (DOT) Federal Safety Standards 

for Liquefied Natural Gas Facilities at 49 CFR 193 and the National Fire Protection 

Association’s (NFPA) Standards for the Production, Storage, and Handling of LNG 

(NFPA 59A). The proposed pipeline facilities would be designed, constructed, operated, 

and maintained in accordance with DOT regulations at 49 CFR 192, Transportation of 

Natural or Other Gas by Pipeline: Minimum Federal Safety Standards. Among other 

items, these regulations specify material selection, design criteria, corrosion protection, 

and qualifications for welders and operation personnel. In addition, FGS would comply 

with the Commission’s regulations at 18 CFR 380.15 regarding the siting and 

maintenance of pipeline rights-of-way. 

To minimize construction-related effects, FGS has agreed to adopt the January 2003 

versions of our Upland Erosion Control, Revegetation, and Maintenance Plan (Plan) and 

our Wetland and Waterbody Construction and Mitigation Procedures (Procedures). The 

FERC Plan and Procedures are available for review on the FERC website at 

www.ferc.gov/industries/gas/enviro/guidelines.asp. The intent of the Plan is to identify 

baseline mitigation measures to minimize erosion and enhance revegetation in upland 

areas. The intent of the Procedures is to identify baseline mitigation measures to 

minimize the extent and duration of construction-related disturbance on wetlands and 

waterbodies. FGS would construct and operate the Project in accordance with our Plan 

and Procedures. 

In addition to accepting our Plan and Procedures, FGS has developed a Project-specific 

Spill Prevention, Control, and Countermeasures (SPCC) Plan that describes the 

management of hazardous materials and/or wastes such as fuels, lubricants, and coolants 

used or stored during construction and operation. The SPCC Plan was filed by FGS in its 

certificate application in October 2007 and can be found on the FERC’s eLibrary website 

at www.ferc.gov under Docket No. CP08-13-000. 

2.41 LNG Storage FciltyConsruction Prcedus 

Construction of the LNG storage facility would include site preparation, storage tank 

construction, and construction of other associated aboveground facilities. 

2.4.1.1 Site Preparation 

FGS would remove the existing structures at the storage facility site, which include the 

former rolling mill building, an existing small office building, and rail siding. Scrap 

metal would be disposed of off-site or sold at the contractor’s discretion. Concrete 

foundations would be crushed and used in place of gravel for the on-site roads. The 

railroad siding is still useable and may be used for material deliveries, but the rails would 

ultimately be removed prior to the completion of construction and either offered to CSX 
2-17 2.0 – Description of the Proposed Action

or sold as scrap. The wooden ties would be removed from the site and either offered to 

local landscape companies or properly disposed of in a landfill permitted to accept them. 

The remaining stone ballast would be gathered and stockpiled for use in the on-site roads. 

The area affected by Project construction is relatively flat with little vegetation. 

Construction areas would be cleared of vegetation, grubbed, and rough graded. The 

underground pipeline and electrical trenching would be at a depth of approximately three 

feet below finish grade. The approximate grade elevation for the storage tank and 

process areas would be six to 18 inches above finish grade. 

Following clearing and grading, the structurally inadequate soils or fill would be overexcavated and filled with structural fill. Temporary ditches, sediment fences, and silt 

traps would be installed as required and in accordance with our Plan. All settlementsensitive equipment, buildings, and structures would be supported on engineered, 

improved soil as specified in the Geotechnical Report (Golder, 2007). Following 

completion of foundations, the site would be filled, compacted, and brought to final 

grade. 

The majority of the construction materials would be delivered via truck. FGS may use 

the existing rail infrastructure to transport some large materials. 

2.4.1.3 Storage Tank Construction 

Storage tank construction is the most schedule-sensitive element in the Project. Each 

tank would take approximately 32 months to construct with an additional four months for 

performance testing. After installation of the foundation, FGS would construct the posttensioned outer concrete container wall including nine percent nickel and carbon steel 

insert strips; install the bottom carbon steel vapor liner; construct and raise the steel dome 

roof and suspended deck; install roof nozzles, penetrations, studs, and steel 

reinforcement; and pour the concrete roof. FGS would install vapor barriers and 

insulation in the inner container; install the nine percent nickel steel “secondary bottom;” 

erect the inner tank shell with a temporary opening into the inner container at the same 

location as the outer tank opening; install the internal tank accessories; and then close the 

temporary opening in the outer tank. 

FGS would fill the inner container of the storage tank with water for hydrostatic testing 

and settlement monitoring and conduct pneumatic testing after closure of the outer 

opening. After the testing, FGS would wash, clean, and dry the inner tank and install a 

resilient blanket on the outside of the inner tank shell; install the instrumentation inside 

the tank and annular space; close the temporary opening; and install the perlite insulation. 

After visual inspection and cleaning, FGS would purge the storage tank with nitrogen. 

Due to the duration and complexity of the tank construction, emphasis would be placed 

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

respective foundations so that the equipment can be placed in its foundation when it 

arrives. Some on-site fabrication may occur, however, some tank erectors have partial 

off-site fabrication, such as sections of the inner plate and steel, which would be 

delivered by train or truck. Large items such as tank shell plates would be delivered to 

the site. 
2.0 – Description of the Proposed Action 2-18 

2.4.1.4 LNG Storage Facility Performance Testing 

All testing, including hydrotesting, pneumatic testing, and pipework testing would be 

carried out in accordance with applicable codes and requirements. 

Hydrotesting 

The inner container of the storage tank would be hydraulically tested (i.e., hydrotested) in 

accordance with the requirements of API Standard 620. Hydrotesting of each tank would 

involve filling the inner tank with approximately 32 million gallons of water, with an 

additional 1.5 million gallons assumed for transmission losses. The hydrotest water 

would be withdrawn from the St. Lucie Canal, pumped using either electrically- or 

engine-driven pumps at a rate of approximately 1,500 gallons per minute (gpm), and 

delivered to and from the site via 1.86 miles of temporary, six-inch-diameter irrigation–

type aluminum pipe. Figure 2.4-1 shows the proposed route for the water pipeline used 

to transport the hydrotest water, which generally follows existing drainage ditches and 

utility rights-of-way. Vehicular access would be maintained at the one public road 

crossing. 

 
St. Lucie Canal

Storage Facility 

Site

Hydrotest Water

Pipeline

Temporary 

Pump House

Temporary 

Pump House

Temporary 

Pump House

0 0.25 0.5 1

Miles

Figure 2.4-1

FGS Project

Hydrotest Pipeline Route Location Map

2-19

Legend

Hydrotest Water Pipeline

Project Pipeline

Storage Facility Site 

Temporary Pump House
2.0 – Description of the Proposed Action 2-20 

Before filling the tank, the hydrotest water source would be tested to ensure that the water 

would meet all applicable code requirements. No biocides or other water additives would 

be used. Water would be introduced into the inner tank container through a manhole in 

the top of the tank at a rate that would not exceed the limitations specified in API 620. 

The duration that the water remains in the tank would be strictly limited and controlled. 

On completion of hydrotesting, the water would be pumped from inside the inner tank 

using electrically-driven submersible pumps suitably sized for the required lift height out 

of the tank, as there are no bottom or side outlets in the storage tank. The temporary 

piping used to initially fill the tank would then be used to return the test water to the St. 

Lucie Canal. The total duration of the hydrotest, from start of filling to completion of 

emptying, would be approximately five weeks. 

Pneumatic Testing 

A pneumatic test of the storage tank outer container would be performed in accordance 

with API 620, which would hold the outer container at 1.25 times the design pressure for 

one hour. 

Pipework Testing 

Piping would be tested using hydrostatic or pneumatic testing. In general, cryogenic 

piping would be pneumatically tested with dry air or nitrogen at 1.1 times design 

pressure. Non-cryogenic piping would be hydrotested using clean water at 1.5 times 

design pressure. Testing would be performed in accordance with the American Society 

of Mechanical Engineers (ASME) B31.3. 

2.4.1.5 Construction of Other Facilities 

Construction of the foundations and pipe racks, together with installation of major 

mechanical equipment, process and utility piping, and electrical instrumentation, would 

consist of the following steps: 

• installation of the fire water, potable water, and other underground piping; 

• construction of foundations, including engineered improved soils as required, 

for the major equipment and pipe racks; 

• delivery of equipment and components to the site, either by trucks using 

nearby highway routes or by rail, as required by the construction schedule and 

equipment manufacturing durations; 

• installation of the process and utility piping and cable trays; 

• installation of piping and electrical and instrumentation systems; 

• installation of pipe insulation; and 

• testing of instrumentation and electrical loops and start of pre-commissioning 

activities. 
2-21 2.0 – Description of the Proposed Action

Ancillary facilities such as the office, control, workshop/warehouse, electric, and security 

buildings would be constructed in a sequence to enable the facilities to be inspected prior 

to the commissioning of the LNG storage tank. 

2.4.1.6 Restoration 

Areas disturbed by Project construction would be stabilized with temporary erosion 

controls until construction is complete unless covered by equipment, gravel, or other 

covering. Following construction, the on-site areas affected by construction of Project 

facilities would be returned to pre-construction conditions or maintained as landscaping. 

2.4 Pipeln adAbovegrund Faciltes 

2.4.2.1 General Pipeline Construction Techniques 

The majority of the proposed pipeline construction process would be accomplished using 

conventional open-cut methods, which is best represented as a moving assembly line with 

a construction spread proceeding along the construction right-of-way in a continuous 

operation. This operation includes survey and staking of the right-of-way; clearing and 

grading; trenching; pipe stringing, bending and welding; and lowering-in and backfilling. 

Due to the short length and homogeneous makeup of the soils of the pipeline, FGS 

proposes to use one construction spread (crew and equipment). After the backfilling, the 

pipeline would be hydrotested and the right-of-way restored and revegetated. The entire 

process would be coordinated to limit the time of disturbance to an individual area, 

minimizing the potential for erosion and loss of normal use. The trench generally would 

not remain open for more than five days in any one area; there would be about 30 days 

between initial grading and final backfilling. 

Survey and Staking 

Before the start of construction, FGS would finalize surveys and stake the centerline and 

exterior boundaries of the construction right-of-way, including additional temporary 

workspaces. The stakes would be consistent with the alignment sheets, mark the limit of 

approved disturbance area, and be maintained throughout the construction period. 

Sensitive resources such as wetlands and protected species habitat would also be marked. 

Prior to the commencement of any ground-disturbing activities, a standard utility line 

survey would be conducted to identify existing utility lines within the proposed pipeline 

right-of-way. 

Clearing and Grading 

The construction right-of-way and temporary extra workspaces would be cleared and, 

where needed, graded to provide a relatively level surface for trench-excavating 

equipment and a sufficiently wide work space for the passage of heavy construction 

equipment and safety of the pipeline workers. In grassy areas where grading is not 

required, vegetation would be mowed to avoid damage to root systems. Generally, 

stumps would be cut flush with the surface of the ground and left in place, except where 

removal is necessary to create a safe and level work surface. Cleared vegetation and 

stumps would be burned (in accordance with state and local burning requirements), 
2.0 – Description of the Proposed Action 2-22 

chipped (in accordance with applicable local restrictions, regulatory requirements, and 

landowner agreements), except in wetlands, or hauled off-site to a commercial disposal 

facility. 

Topsoil would be stripped and segregated according to our Plan and Procedures. Topsoil 

would be removed to its actual depth, up to a maximum of 12 inches, and stockpiled 

separately from the subsoil excavated from the pipeline trench. To contain disturbed 

soils in upland areas and minimize the potential for sediment loss to wetlands and water 

bodies, temporary erosion controls would be installed immediately after initial 

disturbance of the soils and maintained throughout construction. 

Trenching 

The trench would be excavated to a depth sufficient to provide the minimum cover 

required by DOT specifications. Typically, the trench would be about five or six feet 

deep to allow for a minimum of three feet of cover; about 14-feet-wide in stable soils; 

and up to 24-feet-wide at the top in any unstable soils. Additional trench width may be 

required to maintain stability of trench walls for the safety of pipeline workers and 

equipment. Spoil would be stored within the construction right-of-way, next to the trench 

on the opposite (non-working) side of the right-of-way. Temporary trench plugs or 

barriers would be used to create segments within the open trench to reduce erosion and 

allow access across the trench. Trench plugs would typically consist of either compacted 

subsoil or sandbags placed across the ditch (soft plugs) or short, unexcavated portions of 

the trench (hard plugs). FGS does not anticipate the need for any trench dewatering. 

Areas of bedrock that might be encountered along the pipeline route should be easily 

workable with standard construction equipment and techniques. FGS does not anticipate 

the need for blasting associated with trench excavation; however, if blasting were to be 

required, such work would be accomplished in accordance with applicable state 

regulations. 

Pipe Stringing, Bending, and Welding 

After trenching, the pipe would be delivered to the job site and temporarily placed or 

“strung” along the excavated pipeline trench within the right-of-way. Individual sections 

of pipe would be bent in the field where necessary to fit the contours of the trench; 

aligned; welded together into long strings; and placed on temporary supports along the 

edge of the trench. Pipe would be bent at the mill when necessary for sharp bends. The 

pipe would be pre-coated at the mill with a fusion-bonded epoxy external coating (or 

other coating technique) to protect it from corrosion. 

All welds would be X-rayed to ensure structural integrity and compliance with applicable 

DOT regulations. Those welds that do not meet established specifications would be 

repaired or removed. Once the welds are approved, the welded joints would be coated 

with a protective coating and the entire pipeline visually and electronically inspected for 

any faults, scratches, or other damage, including coating defects. Any damage would be 

repaired before lowering the pipe into the trench excavation. 
2-23 2.0 – Description of the Proposed Action

Lowering-in and Backfilling 

If dewatering becomes necessary, the trench would be dewatered and cleaned of debris 

before the pipeline is lowered into the trench. In rocky areas, the bottom of the trench 

may be padded with sand gravel, screened soils, sandbags, or support pillows to protect 

the pipe coating. No topsoil would be used for pipeline padding. The pipelines would be 

lowered into the trench and trench barriers or breakers installed at specified intervals 

before backfilling to prevent water movement or subsurface erosion. The trench would 

then be backfilled, using the excavated materials, to existing grade or higher to 

accommodate future soil settlement. If the excavated material could damage the pipe 

coating, the pipeline would be protected with a rock shield and/or covered with select fill 

obtained from commercial borrow areas or by separating suitable material from the 

existing trench spoil to prevent damage to the pipe and pipe coating. 

Hydrotesting 

After the trench is backfilled, and before Project operation, the pipeline would be 

hydrotested in accordance with DOT safety standards (49 CFR Part 192) to verify its 

integrity. Approximately one million gallons of water would be needed to test the 

pipelines. Some water used for hydrotesting the 24-inch pipeline would be reused to test 

the 12-inch pipeline. The test water would be pumped into the pipeline or section of 

pipeline pushing a foam pig to ensure a positive displacement of air. The pipeline or 

segments would then be pressurized to the design test pressure and maintained at that 

pressure for a minimum of eight hours. If during the eight-hour test period any leaks are 

detected, the leaks would be repaired and the test section re-pressurized until the DOT 

specifications are met. 

After successfully hydrotesting each section, the new pipelines would be cleaned and 

dried using pipeline pigs propelled through the pipelines with compressed air. The 

hydrotest water would be discharged back to the St. Lucie Canal in accordance with 

NPDES permit requirements. 

Cleanup and Restoration 

Following hydrotesting, the trenches would be compacted to minimize future settling, all 

work areas would be final-graded and restored as closely as possible to pre-construction 

contours. Permanent erosion control measures would be installed during this phase in 

accordance with our Plan and Procedures. Restoration would begin as soon as possible 

upon completion of final grading. Topsoil previously segregated from the trench material 

would be spread uniformly across the construction right-of-way. Pipeline markers and/or 

warning signs would be installed along the pipeline centerlines at specified intervals to 

identify the location of the pipes. Any remaining construction material or debris would 

be removed and disposed of at an appropriate disposal site. Revegetation would be 

accomplished by seeding disturbed areas in accordance with recommendations of the 

local office of the Natural Resources Conservation Service (NRCS) or as requested by 

the landowner. 
2.0 – Description of the Proposed Action 2-24 

Post-Construction Monitoring 

FGS would monitor all areas disturbed by construction in accordance with our Plan and 

Procedures to identify any areas that require additional restoration work, noxious weed 

treatment, or erosion controls. FGS would repair and correct any areas identified as 

needing additional work in consultation with the landowner. The FERC would conduct 

periodic independent inspections to monitor the Project for compliance with the 

Commission’s environmental conditions. 

2.4.2.2 Special Pipeline Construction Procedures 

Pipeline construction would not affect any agricultural lands residential or commercial 

areas; therefore, no special procedures are required for these areas. Special construction 

procedures are proposed for road, railroad, overhead piping, waterbody, and wetland 

crossings. 

Roads and Railroads 

The pipeline route crosses a paved road (i.e., Silver Fox Lane) and a rail spur to the 

Cogentrix power plant. FGS proposes to use a single-hole bore to cross these features 

from MP 0.99 to MP 1.02. The two pipelines would be bundled and pulled through the 

bore. Unpaved roads would be open-cut. 

Overhead Piping

The pipeline route crosses existing aboveground piping related to operations at the 

Cogentrix power plant. FGS proposes to use a single-hole bore to cross these features 

from MP 0.66 to MP 0.69. The two pipelines would be bundled and pulled through the 

bore hole. The temporary workspaces would be contained within the existing pipeline 

easement and would not impact any wetlands or waterbodies. 

Wetlands and Waterbodies 

The pipeline route would not cross any major, navigable, or sensitive water bodies. Four 

minor ditches would be crossed by the open cut/conventional lay method and one would 

be bored. Rubber tire backhoe-type excavators would be used to open a trench across a 

flowing ditch. During these operations, flow would be maintained at all water crossings 

in accordance with the Procedures. Trench spoil would be placed on the bank above the 

high water mark for use as backfill. A prefabricated segment of pipeline, concrete coated 

as needed to provide negative buoyancy, would be placed below scour depth. Standard 

backfill cover requirements would be met. Once the trench is backfilled, the banks would 

be stabilized by seeding or use of riprap materials. Excavated material not required for 

backfill would be removed and disposed of at an upland disposal site. 

FGS would use a reduced construction right-of-way width of 65 feet for its 2,620 linear 

feet of wetland crossings. For conventional wetland crossings in stable soil conditions, 

the construction technique would be similar to that used in dry upland areas, except that 

the temporary workspace during construction through wetlands would be reduced and 

limited to adjacent upland areas as much as possible. 
2-25 2.0 – Description of the Proposed Action

Construction in wetlands with wet, saturated soils and/or standing water could require the 

push/pull method to install pipelines. This method involves equipment pushing 

prefabricated pipe from the edge of the wetland and/or pulling the pipe from the opposite 

bank of the wetland into an excavated trench. The trench would be excavated using 

either a backhoe working on equipment support in the wetland or a dragline or clamshell 

dredge working either in the wetland or from the edge of the wetland, depending on 

wetland size and extent of soil saturation. Floats may be attached to the pipe to give it 

positive buoyancy, allowing it to be floated into place in the trench. Once the pipe is 

positioned, these floats would be removed, the pipe would settle to the bottom of the 

trench; and the trench would be backfilled. The push/pull method would enable the 

pipeline to be installed with minimal equipment operation in the wetland. No dewatering 

is proposed, but would be undertaken as necessary (e.g., in the case of rain filling an open 

ditch). 

FGS proposes one bore, at the road and rail spur crossing from MP 0.99 to MP 1.02 to 

avoid 0.03 acre of wetlands (i.e., the roadside ditches). The bore would require 

additional temporary workspaces at the entry and exit points (0.75 and 0.23 acre, 

respectively). To avoid or minimize impacts on water quality and wetlands, FGS would 

implement measures outlined in our Procedures during the construction and operation of 

the pipeline facilities. Sections 4.3 and 4.4 provide a more detailed description of 

waterbody and wetland protection measures. 

2.4.2.3 Aboveground Facilities Construction Procedures 

Construction of the M&R station and interconnections would begin with clearing and 

grubbing. After site grading, foundations would be poured; piping and valves assembled; 

and equipment mounted on the foundations. The sites would be stabilized with gravel or 

pavement and a security fence installed. Pipe sections within the M&R station and 

interconnections would be tested at the same time as the pipelines. 

2.5 CONSTRUI CHEDL

FGS proposes a phased construction schedule. At a minimum, Phase 1 would include the 

construction of at least one storage tank with a nominal working volume of 184,750 m3

and a storage capacity of 4 Bcf, liquefaction systems with a 50 MMscfd capacity, two 

60,000 gallon NGL storage vessels, vaporization systems with a design sendout capacity 

of 400 MMscfd, and the two approximately 4-mile-long parallel pipelines to connect the 

facility with the existing interstate pipeline systems northwest of the site. 

Phase 2 would include the construction of a second, identical LNG storage tank and 

additional 50 MMscfd of liquefaction capacity, 400 MMscfd of vaporization capacity, 

and 120,000 gallons of NGL storage capacity. Phase 2 would be in service no later than 

March 2016; this date may be advanced based on market demand, and it is possible that 

the two LNG storage tanks would be constructed simultaneously. 

FGS anticipates construction of Phase 1 to take approximately 36 months. Upon 

initiating construction, FGS would begin with the LNG storage tank(s), which would take 

approximately 32 months to complete. Construction of the pipeline would be 
2.0 – Description of the Proposed Action 2-26 

accomplished with a single construction spread over about 4 to 6 weeks, with activities 

proceeding at an average rate of about 1,500 feet per day. M&R station construction 

would require approximately 17 weeks and would shortly follow pipeline construction. 

2.6 ENVIROMTAL CPINEAD MOITRNG 

FGS would implement environmental compliance and monitoring measures from our 

Plan and Procedures during Project construction. FGS would also incorporate 

compliance and monitoring measures as required by the federal, state, and local permits 

obtained for the Project. 

In accordance with our Plan and Procedures, FGS would conduct environmental training 

for construction and contractor personnel before construction and periodically during 

construction. FGS would employ at least one environmental inspector (EI). The EI 

would be responsible for monitoring construction activities for compliance with the 

conditions of the FERC certificate and all other applicable federal, state, and local 

permits. The EI would have independent status, but would report to FGS’s Chief 

Inspector, submit bi-weekly status reports to the FERC, and would have stop-work 

authority in the event of a noncompliance issue that requires corrective action. 

In addition, the FERC would conduct independent quarterly inspections to monitor the 

Project for compliance with the Commission’s environmental conditions. 

2.7 OPERATIN DMEAC

The following sections summarize the operation and maintenance procedures for the 

Project. FGS would incorporate post-construction environmental requirements into a 

LNG storage facility Operation and Maintenance Plan and a pipeline Emergency Plan 

and Procedures. 

2.71 LNG Storage Fcilty

FGS would operate and maintain its facilities in compliance with 49 CFR 193, NFPA 

59A, and other applicable federal and state regulations. In accordance with 49 CFR 

193.2503 and 193.2605 and Sections 11.3.1 and 11.5.2 of NFPA 59A, FGS is required to 

prepare and submit manuals that address specific procedures for the safe operation and 

maintenance of the LNG storage and processing facilities. These manuals would address 

startup, shutdown, cool-down, purging, and other routine operation, maintenance, and 

monitoring procedures. These manuals would also include training requirements and 

programs for operation and maintenance personnel. 

During emergency events (i.e., the aftermath of a hurricane or other supply interruption) 

when pipeline delivery is not possible, LNG would be transported from the FGS facility 

by truck to FGS capacity holders. Any trucks accessing the facility would be required to 

be in compliance with all codes and regulations pertaining to the design, construction and 

operation of vehicles used to transport LNG. 
2-27 2.0 – Description of the Proposed Action

2.7 Pipelns adAocite bvground Faciltes 

FGS would operate and maintain the proposed facilities in accordance with the applicable 

safety standards established by the DOT Minimum Federal Safety Standards as specified 

in 49 CFR 192 and in accordance with the Natural Gas Act. Pipeline markers would be 

placed and maintained along the right-of-way at road crossings, railroad crossings, and 

other highly visible places to alert construction workers and the general public to the 

presence of the buried pipelines. The pipelines would be patrolled on a periodic basis. 

This patrol would provide information on possible leaks, encroachments into the right-ofway, third-party construction activity near the pipeline, erosion, waterbody crossings, 

exposed pipe, or population density changes in the vicinity of the pipeline. FGS would 

also monitor the cathodic protection units installed for corrosion control (see Section 

2.8.2) along the pipeline to ensure proper functioning. 

Maintenance activities would include regularly scheduled gas leak surveys and measures 

necessary to repair any leaks. All fencing, signs, marker posts, and decals would be 

painted or replaced as necessary to ensure the pipeline location remains visible from the 

air and ground. Maintenance would also include routine (no more frequently than every 

three years) vegetation clearing; annual mowing of a corridor not exceeding 10-feet-wide 

centered on each pipeline to facilitate periodic corrosion and leak surveys; and vegetation 

control around aboveground facilities. Safety equipment such as pressure relief devices, 

fire detection and suppression systems, and gas detection systems would be maintained 

throughout the life of the facilities. Valves would also be inspected, serviced, and tested 

to ensure proper function. Qualified personnel would conduct routine monitoring and 

maintenance at the M&R station. 

2.8 SAFETY CONRLS

2.81 LNG Storage Fcilty

The LNG storage facility would be sited, designed, constructed, operated, and maintained 

in compliance with federal safety standards. Table 2.8-1 summarizes the federal siting 

and design requirements for LNG facilities. 
2.0 – Description of the Proposed Action 2-28 

Table 2.8-1 

Federal Siting and Design Requirements for LNG Facilities 

Requirement Description 

Thermal Radiation Protection (49 CFR 

193.2057 and Section 2.2.3.2 of NFPA 59A) 

This requirement is designed to ensure that certain public land uses 

and structures outside the LNG facility boundaries are protected in the 

event of an LNG fire. 

Flammable Vapor-Gas Dispersion Protection

(49 CFR 193.2059 and Sections 2.2.3.3 and 

2.2.3.4 of NFPA 59A) 

This requirement is designed to prevent a flammable vapor cloud 

associated with an LNG spill from reaching a property line of a 

property suitable for building. 

Wind Forces (49 CFR 193.2067) This requirement specifies that all facilities be designed to withstand 

wind forces of not less than 150 miles per hour without the loss of 

structural integrity. 

Proximity to Airport Runways (49 CFR 

193.2155)

This requirement specifies that an LNG storage tank must not be 

located within a horizontal distance of 1 mile from the ends of, or 0.25 

miles from the nearest point of, an airport runway, whichever is longer. 

Impounded Liquid (Section 2.2.3.8 of NFPA 

59A) 

This requirement specifies that liquids in spill impoundment basins 

cannot be closer than 50 feet from the property line of a property 

suitable for building or a navigable waterway. 

Container Spacing (Section 2.2.4.1 of NFPA 

59A) 

This requirement specifies that LNG containers with capacities greater 

than 70,000 gallons must be located a minimum distance of 0.7 times 

the container diameter from the property line or buildings. 

Vaporizer Spacing (Section 2.2.5.2 of NFPA 

59A) 

This requirement specifies that integral heated vaporizers must be 

located at least 100 feet from the property line of a property suitable 

for building and at least 50 feet from other select structures and 

equipment. 

Process Equipment Spacing (Section 2.2.6.1 

of NFPA 59A) 

This requirement specifies that process equipment containing LNG or 

flammable gases must be located at least 50 feet from sources of 

ignition, a property line of property suitable for building, control rooms, 

offices, shops, and other occupied structures. 

Seismic and Foundation Design (Sections 

4.1.3 and 4.1.7 of NFPA and Appendix B 59A)

This requirement specifies seismic events and use of ASCE 7 for 

foundation design. 

Seismic Design (Section 4.1.3 of NFPA 59A) This requirement specifies that the critical safety related components 

of an LNG facility must be designed to withstand, without loss of 

containment capability, earthquake ground motion having a mean 

return interval of 4,975 years 

2.8.1.1 Spill Containment 

The Project’s spill containment systems are designed and would be constructed to comply 

with DOT regulations 49 CFR Part 193. These regulations require that each container of, 

and each transfer system for, LNG be provided with a means of secondary containment 

sized to hold the quantity of LNG that could be released as a result of a design spill, as 

defined in NFPA 59A, for the area and equipment. FGS proposes full containment LNG 

storage tanks in which the outer tank wall serves as the impoundment system. These 

concrete outer tanks would be designed to hold the contents of 110 percent of one 

nominal 190,000 m3 LNG storage tank. 

A spill containment system would be provided that consists of a system of concrete 

transmission troughs that would direct any spillage, whether from the storage tank or the 

liquefaction-to-tank and tank-to-vaporization transfer systems, to spill impoundment 

sumps. The collection troughs would be approximately three-feet-wide by two-feet-deep 

and as long as necessary to direct any spill to the spill containment sumps. Two LNG 

containment sumps would be installed. The usable volume of the sump would provide 
2-29 2.0 – Description of the Proposed Action

for containment of a 10-minute spill from a single full-bore pipe rupture that would 

produce the highest release rate. 

FGS would also construct an NGL spill containment system. This system would consist 

of a concrete curbed area directly underneath the entire NGL storage tank area. The 

curbed area would slope towards the NGL spill impoundment sump, which would be 

sized to impound a 10-minute design spill from the area. 

The facility stormwater drainage system would consist of low lift stations for the 

collection and transfer of stormwater runoff within the tertiary impoundment berms 

around the storage tank areas, plus a system of swales, ditches, and culverts for collection 

of clean stormwater from outside the bermed areas. Non-contact stormwater runoff 

within the process areas would be discharged to existing outfalls. The spill containment 

sumps would contain pumps that pump the stormwater out of the respective areas and 

into the outer stormwater runoff system for the facility. The sumps would be equipped 

with a low temperature switch to prevent LNG from being pumped into the stormwater 

drainage system. Stormwater runoff from around the administrative offices, access roads, 

parking areas, and related infrastructure would be temporarily retained within on-site 

retention areas, with eventual discharge through existing outfalls. 

2.8.1.2 Hazard Detection System 

Hazard detectors would be installed throughout the LNG storage facility to give 

operations personnel a means for early detection and location of released flammable 

gases or fires. The hazard detection system would consist of separate detection units for 

combustible gas, fire, and high and low temperatures, and would be hard-wired to the 

main alarm control system. Smart area gas detectors would be provided to monitor 

flammable gases within the storage facility. Each of these detectors would trigger visual 

and audible alarms at specific on-site locations and in the control room areas to enable 

effective and immediate response. 

Smart ultraviolet/infrared fire and flame detectors would be located throughout the 

storage facility. High temperature detectors to detect fire would be located on the vent 

pipes of the storage tank relief valves. 

2.8.1.3 Fire Protection System 

The LNG storage facility would have a fire protection system for extinguishing fires, 

cooling structures and equipment exposed to thermal radiation, and dispersing flammable 

vapors. The main components of the system include a 500,000 gallon firewater tank and 

two 4,000 gpm pumps, one electric motor-driven and one diesel engine-driven. The 

looped underground firewater distribution system would include monitors, hydrants, and 

hose reels, as follows: 

• Firewater monitor nozzles would be adjustable from straight stream to full fog 

and generally rated for 750 gpm. In locating firewater monitors, an effective 

coverage range of 200 feet was used. 
2.0 – Description of the Proposed Action 2-30 

• Dry barrel, compression-type fire hydrants offer the opportunity for direct 

action by means of 2.5-inch hose lines, as well as the capability to deliver 

pressurized firewater to automotive fire apparata equipped with a fire pump. 

Hydrant spacing is approximately 300 to 500 feet around the storage tank. 

Each fire hydrant is provided with a six-inch gate valve installed in the lateral 

between the hydrant and fire main. The valve is fitted with a two-piece 

adjustable roadway box, with cover at grade, to permit T-wrench access to the 

valve's operating nut. 

• A hose reel with mounting, including 100 feet of hard rubber non-collapsible 

1.5-inch fire hose and adjustable fog nozzle for a rapid first response with fire 

water. 

The firewater tank would normally be filled from on-site wells. The municipal water 

system would serve as backup for the wells. 

In addition to the firewater system, several other types of fire suppression agents would 

be available to control potential fires at the storage facility, including fixed, handportable, and wheeled fire extinguishers employing dry chemical and carbon dioxide. 

The type of agent used in a specific situation would depend on the characteristics of a 

particular event and the relative effectiveness of the various agents on that particular type 

of fire. Dry chemical fire suppression systems would be provided for the storage tank 

relief valves and would be manually activated (remotely or locally) to extinguish any 

potential fires at the valves. Portable dry chemical units would be strategically located 

throughout the facility. 

2.8.1.4 Emergency Shutdown System 

The Project would have an emergency shutdown (ESD) system to allow the safe, 

sequential shutdown and isolation of equipment designed to leave the facilities in a safe 

state during an emergency. The ESD system would be used for major incidents and 

result in shutdown of either the total plant or individual pieces of equipment, depending 

on the type of incident. 

The basic ESD system consists of strategically placed instruments that would alert the 

plant operators of an incident. Emergency shutdown procedures would typically be 

initiated by operators pushing strategically placed ESD push buttons; however, where 

necessary, some instruments could automatically begin equipment shutdown sequences. 

2.8.1.5 Security Systems 

The Project facilities would include sirens with a distinctive tone for easy differentiation 

between alarms and emergency events. 

The LNG storage facility would have a security fence completely surrounding its 

perimeter. Guards based at the main entrance guardhouse would control personnel access 

to the facility and conduct periodic security sweeps of the grounds. In addition, closed 

circuit television cameras with 360-degree pan, tilt, and zoom capabilities would be 

located throughout the facility for remote monitoring of activities in local areas. 
2-31 2.0 – Description of the Proposed Action

For the Project, including the pipeline, FGS has committed to preparing a Security 

Procedures Plan and Manual. The plan and manual would establish a written program for 

physical security for all Project facilities including security inspections and patrols as 

well as a liaison with local law enforcement officers. The plan, which would comply 

with DOT regulations, would provide for risk-based levels of security carried out by 

trained personnel during all operation shifts and, if necessary, by government law 

enforcement offices that may respond to serious threats. 

2.8 Pipelns adAocite bvground Faciltes 

The pipelines and aboveground facilities associated with the Project would be designed, 

constructed, operated, and maintained in accordance with DOT Minimum Federal Safety 

Standards in 49 CFR 192. 

Corrosion Protection and Detection Systems 

The pipelines would be constructed of welded carbon steel that meets or exceeds industry 

standards and covered with a protective epoxy coating to minimize rust and corrosion. 

During construction, FGS would install a cathodic protection system to further prevent or 

minimize corrosion of the buried pipelines and aboveground facilities. The cathodic 

protection system impresses a low-voltage current on the pipeline to offset natural soil 

and groundwater corrosion potential. The condition of the pipe coating and effectiveness 

of the cathodic protection system would be monitored during regularly scheduled surveys 

in accordance with federal standards and regulations. Cathodic protection surveys 

usually require walking the pipeline right-of-way with monitoring instruments. Repairs 

to the pipe, the pipe coating, or the cathodic protection system would be made as 

appropriate. 

Emergency Response Procedures 

Under 49 CFR 192.615, each pipeline operator must establish an emergency plan that 

includes procedures to minimize hazards in a natural gas pipeline emergency. Key 

elements of the plan include procedures for: 

• receiving, identifying, and classifying emergency events, gas leakage, fires, 

explosions, and natural disasters; 

• establishing and maintaining communications and coordinating emergency 

response with local fire, police, and public officials; 

• making personnel, equipment, tools, and materials available at the scene of an 

emergency; 

• protecting people first and then property, and making them safe from actual or 

potential hazards; and 

• emergency shutdown of the system and safe restoration of service. 

Part 192 also requires that each operator must establish and maintain a liaison with 

appropriate fire, police, and public officials to learn the resources and responsibilities of 
2.0 – Description of the Proposed Action 2-32 

each organization that may respond to a natural gas pipeline emergency, and coordinate 

mutual assistance. The operator must 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. FGS 

indicated it would participate in the “One Call” program. This program provides 

telephone numbers for excavation contractors to call prior to commencing any excavation 

activities. The One Call operator would notify FGS of any planned excavation in the 

vicinity of the pipelines so that FGS could flag the location of pipelines and assign staff 

to monitor the activities, if required. 

Prior to commencing operations, FGS would also have to prepare emergency procedures 

manuals, as required by 49 CFR Part 193.2509, 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. 

2.9 FUTRE PLANSDBOMET 

There are no FERC jurisdictional facilities to be abandoned as part of the Project. 

The only future plans include Phase 2, which, as discussed previously, would include a 

second LNG storage tank with with a nominal working volume of 184,750 m3

, associated 

liquefaction (50 MMscfd) and vaporization (400 MMscfd) equipment to increase the 

liquefaction and vaporization rates, and additional NGL storage. Facilities included as 

part of Phase 2 are considered as part of the proposed action that is evaluated in this EIS. 
3-1 3.0 – Alternatives

3.0 ALTERNATIVES 

We evaluated a number of alternatives to the proposed Project to determine whether any 

would be reasonable and environmentally preferable to the proposed action. Alternatives 

described in the following sections include the no action or postponed action alternatives, 

LNG storage facility site and system alternatives; and pipeline system and route 

alternatives. 

The evaluation criteria for selecting potentially reasonable and environmentally 

preferable alternatives include whether they would: 

• be technically and economically feasible and practical; 

• offer significant environmental advantage over the proposed Project or its 

components; and 

• meet the Project purpose as described in Section 1.1. 

3.1 NO ACTION OR POSTPONED ACTION ALTERNATIVES 

If the Commission selects the no action alternative (i.e., denies the Project), the 

environmental impacts and benefits of the Project identified in Section 4.0 would not 

occur and the purpose of the Project would not be met. If the Commission postpones 

action on the application, the environmental impacts and benefits identified in Section 4.0 

would be delayed. 

If natural gas supplies are not available when needed, users (including electric generators 

and industrial users) would likely switch to alternate fuels or face supply shortages. 

Because the demand for energy in Florida is predicted to continue to increase, natural gas 

users, particularly those at the end of the supply line, may have fewer and potentially 

more expensive options for obtaining and managing natural gas supplies in the near 

future. Failure to provide natural gas during peak demand periods in Florida could cause 

increased prices or supply shortages for industrial use and electricity generation. 

It is possible that energy conservation in the future could lessen the need for additional 

supplies of natural gas. Florida has an active energy conservation program that has 

reduced peak demand by approximately 5,000 MW since its inception in 1980. The 

Florida Public Service Commission (PSC) plans to continue to encourage energy 

conservation in the future (PSC, 2006); however, energy conservation alone would not 

eliminate the need for additional generation or additional natural gas sources and 

infrastructure projects to meet peak demand due to substantial economic and population 

growth in Florida. 

3.2 ALTERNATIVE ENERGY SOURCES 

The proposed Project is not an energy source itself, it simply is a storage facility to 

improve the overall reliability of the electrical generating system in Florida. The Project 
3.0 – Alternatives 3-2 

is needed to improve current system reliability. To the extent that this Project could 

make gas fired generating facilities more attractive because of improved reliability, we do 

discuss below the status of alternative energy sources in Florida. 

The following four alternative energy sources were evaluated and are addressed below: 

• Use of other non-renewable fuels (Section 3.2.1); 

• Renewable energy sources (Section 3.2.2); 

• Energy conservation (Section 3.2.3); and 

• Renewable energy combined with energy conservation (Section 3.2.4). 

In December 2007, the Florida PSC published the Review of 2007 Ten-Year Site Plans 

for Florida’s Electric Utilities. The PSC reviewed the future of electrical utility 

development in Florida in light of the state goal to diversify fuel dependency, including 

development of non-renewable, (e.g. natural gas, coal, and nuclear), and renewable fuel 

sources (e.g. solar, wind, landfill gas, biomass, and solid waste). 

3.2.1 Other Non-Renewable Fuels 

The Florida PSC predicts that, by 2016, natural gas will provide approximately 45 

percent of the state’s energy production. Based on our assessment of natural gas demand 

and supply (see Section 1.1), the market area would likely experience a shortage of 

natural gas for power generation if the FGS Project, or a similar new-source project, is 

not implemented. Shortages in the availability of natural gas could in turn lead to an 

increased reliance on fuel oil and other non-renewable fuel supply sources for power 

generating facilities. Natural gas is the cleanest burning of the fossil fuels, and reliance 

on coal or oil to fuel power generation for the region may result in an increased output of 

air pollutants such as NOx, SO2, mercury, and greenhouse gases (EIA, 2005). Increased 

emissions of these pollutants would degrade air quality in the region. In addition, like 

natural gas, secondary impacts are associated with production (coal mining and oil 

exploration and drilling), transportation (oil tankers, rail cars, and pipelines), and 

processing of other fossil fuels. 

Coal power is not considered to be a viable energy source in Florida. Over 4,000 MW of 

proposed coal-fired capacity has been cancelled or denied certification since 2006. The 

only generating facility to receive approval has since reduced operations to be solely gasfired. 

A traditional non-renewable fuel source alternative to natural gas for electric generation 

is nuclear power. There are currently three licensed nuclear power facilities in Florida 

(Crystal River 3), Ft. Pierce (St. Lucie), and Miami (Turkey Point) (EIA, 2008). All 

three facilities received license extensions from the U.S. Nuclear Regulatory Commission 

so nuclear energy will continue to be a viable energy source in Florida over the next 

decade. There are currently several proposals for increasing nuclear power capacity in 

Florida. Florida Power and Light is considering uprates to the Turkey Point facility and 

Progress Energy is proposing uprates to its Crystal River facility as well as construction 

of a light water reactor. The Florida PSC approved the need for the FPL and Progress 
3-3 3.0 – Alternatives

Energy uprates; however, the determination of need for the light water reactor has not 

been filed. Due to the extended permitting and construction periods associated with 

nuclear generating plants, the PSC determined that gas generation is the most feasible 

energy option to meet immediate energy demands. Consequently, the use of nuclear 

power, while currently providing a portion of Florida’s energy, does not appear to be a 

practical alternative to meet the increased energy demands for the market that the FGS 

Project proposes to serve. 

3.2.2 Renewable Energy Sources 

Nationwide, renewable energy sources have included wind, solar, tidal, and hydroelectric 

power; geothermal sources; and energy or fuel from municipal solid wastes, wood, and 

other biomass. Although new geothermal and traditional hydroelectric power projects are 

unlikely to be permitted and constructed in Florida, other forms of renewable energy 

sources are likely to play an increasing role in meeting energy demands in the coming 

years. Further, while the potential for solar and wind power exists within the state, largescale thermal utility systems from solar power and wind farms are not proven to be 

effective (DOE, 2008) for the market that the FGS Project proposes to serve. Currently, 

approximately 600 MW of non-firm energy is generated from renewable sources (e.g., 

solid waste, biomass, landfill gas, hydro, and waste heat) with plans for potentially 308 

MW to be constructed including solar power. The State of Florida has adopted goals and 

incentives for increased energy conservation and the use of renewable energy sources. 

These programs include Florida’s Solar Energy Systems Incentives Rebate Program, 

Renewable Energy Technologies Grant Program, and the Florida Green Lodging 

Program (FDEP, 2008a). 

On March 13, 2008, Red Circle Systems filed preliminary permit applications with the 

FERC for the SeaGen projects to construct and operate underwater turbines to generate 

tidal energy from the currents offshore of West Palm Beach and Ft. Lauderdale. These 

projects would have the potential of providing up to 40 MW each of electric power. 

These projects would consist of a series of “free-flow” hydro turbines located at least 60 

feet below the surface of the water and would generate power from tidal currents. Cables 

from the undersea portions of the projects would extend into Florida. Studies are in 

progress to evaluate the effects of the projects on marine resources, particularly fish. It is 

not clear whether or not all the projects could be approved, constructed, and operated, or 

if the full capacity of each project could be reached. If all projects were implemented at 

full capacity, they would provide the region with up to about 80 MW of additional power. 

FERC is awaiting study results before issuing or denying licenses for any or all of these 

projects. 

One wind energy project has been proposed in the St. Lucie area. The St. Lucie Wind 

Energy Project, which would be located on Hutchinson Island in St. Lucie County, was 

proposed by FPL. The St. Lucie wind energy project is a pilot wind farm that would 

consist of six 415-foot-high wind turbines. The project is currently under initial zoning 

review by the St. Lucie County Board of County Commissioners (FPL, 2008). 

Proposed renewable energy projects in Florida would account for only a portion of the 

energy demand of the region. Further, these sources tend to be less reliable during 
3.0 – Alternatives 3-4 

emergencies and less able to rapidly increase generation to meet peak demand. In 

summary, use of renewable energy sources would not offset the need for the proposed 

Project. 

3.2.3 Energy Conservation 

Energy conservation measures likely will play an increasingly prominent role in 

offsetting some of the projected energy demand for the region. The State of Florida has 

adopted goals and incentives for increased energy conservation and the use of renewable 

energy sources (such as the Solar Energy Systems Incentives Rebate Program, 

Renewable Energy Technologies Grant Program, the Florida Green Lodging Program, 

the Utility Report Card program for select school system (FDEP, 2008a), and Florida’s 

Demand-Side Management (DSM program)). The Green Lodging Program was 

established in 2004 with the intent of recognizing and rewarding environmentally 

conscientious lodging facilities in the state. Through this rapidly growing program FDEP 

encourages the lodging industry to conserve and protect Florida’s natural resources 

(FDEP, 2008b). The Utility Report Cards is a web-based Energy Information System 

that reports and graphs monthly utility data for schools. Each month, a web-based report 

is automatically generated and emailed to school principals and staff to compare their 

school's electricity usage (energy efficiency) and to identify schools with high energy 

consumption for further investigation and exploration of energy conservation programs 

(UTC, 2008). 

The DSM program reduces peak energy demands through both utility-dependent 

measures such as load management and interruptible service, to consumer-dependent 

measures such as stricter energy efficiency requirements. These strategies reduce per 

capita energy demand; however, overall demand is still predicted to rise by 0.84 percent 

per year over the next decade resulting in a continually growing need for energy supply. 

Although energy conservation measures will be important elements in addressing future 

energy demands for the region, energy conservation will reduce the energy demands of 

the region by only a small fraction of the projected energy demand for the region within 

the foreseeable future. Further, energy conservation does not address system reliability 

issues during peak demand or emergencies. Thus, energy conservation alone would not 

replace the need for the Project. 

3.2.4 Renewable Energy Combined with Energy Conservation 

As noted above, use of either renewable energy sources or energy conservation would 

individually reduce energy demands in the region by only a small amount. While current 

public sentiment supports conservation and green energy, current market behavior does 

not support the assertion that conservation and renewable energy sources are viewed by 

most consumers as providing significant advantages over natural gas. We have 

concluded that conservation combined with renewable energy would reduce the need for 

natural gas, but it is clear that this would not meet the projected increase in energy 

demand for the region. The gains achieved collectively through better management, 

increased efficiency, and renewable energy use could only moderate, not reverse, the 
3-5 3.0 – Alternatives

projected increases in gas consumption for the region. Further, these measures alone do 

not address the need for improved system reliability during emergencies. 

3.2.5 Conclusions Regarding Alternative Energy Sources 

Considered both individually and in combination, specific alternative energy sources or 

conservation measures would not meet the projected energy needs of the target markets. 

The alternative energy source alternatives considered in our evaluation could reduce 

some environmental impacts associated with the proposed Project, but could not 

individually or cumulatively meet the projected future energy needs of the Florida 

market. Renewable energy sources, including wind, tidal, and solar power along with 

existing and proposed energy conservation measures, will continue to play an 

increasingly important role in power generation for the Florida market; however, these 

sources represent only a small fraction of the projected energy demands for these markets 

for the foreseeable future, whether considered alone or in combination. 

In the Review of the 2007 Ten-Year Site Plans for Florida’s Electrical Utilities, the 

Florida PSC concluded energy demand forecasts continue to surpass current 

conservation, DSM, and renewable energy programs offered by Florida’s utilities and 

that local utilities should continue investigating natural gas supply and delivery options 

such as natural gas storage to maintain diversity in the face of unplanned supply or 

distribution disruptions. Therefore, we have considered the use of alternative sources of 

energy only to meet the region’s energy needs in conjunction with the use of natural gas 

from other LNG projects and from existing approved, proposed, or planned pipeline 

systems (see Section 3.3.3). 

3.3 STORAGE FACILITY ALTERNATIVES 

3.3.1 System Alternatives 

System alternatives are options to the proposed action that would make use of other 

existing natural gas facilities to meet the stated objectives of the proposed Project. A 

system alternative would make it unnecessary to construct all or part of the proposed 

Project even if some modifications or additions to existing or proposed facilities would 

still be necessary. These modifications or additions would result in environmental 

impacts that could be less, similar to, or greater than those associated with construction of 

the Project. Ultimately, the purpose of identifying and evaluating system alternatives is 

to determine whether potential environmental impacts associated with the construction 

and operation of the Project could be avoided or reduced by using another system. Our 

analysis of system alternatives considered the use of other LNG storage options, other 

approved or proposed LNG projects in the region, and potential expansion of existing 

natural gas pipelines to replace all or part of the proposed Project. 

Alternative Storage Facilities 

There are three major types of “reservoirs” common to the storage of natural gas, all of 

which are underground: 
3.0 – Alternatives 3-6 

• Salt dome cavern storage: Salt domes are naturally-occurring underground 

formations of block salt. These storage facilities are created by drilling a well 

into a massive salt formation and injecting water to turn the salt into a 

solution, which is pumped out and disposed of. This “brining” process creates 

an underground cavern capable of holding natural gas at very high pressures. 

A typical salt dome storage cavern can hold 4 to 8 Bcf of natural gas. An 

advantage of salt dome storage is that it can be designed for flexible rates of 

injection and withdrawal to meet changing market conditions. 

• Depleted reservoir storage: Depleted reservoirs reuse existing underground 

oil- and gas-producing formations that have been commercially developed. 

By connecting to delivery pipeline networks and installing compression 

equipment, natural gas can be injected into the old formations and held until 

needed by the market. There are a limited number of suitable formations, but 

they are an important resource for the natural gas industry. The injection and 

withdrawal rates are slower than salt dome projects, but the volumes are 

usually larger, typically 10 to 80 Bcf. 

• Aquifer storage: Aquifer storage is similar to reservoir storage, but uses 

underground water aquifers instead of depleted oil and gas formations. 

Natural gas is taken from the pipeline system, compressed to high pressure, 

and injected into the underground formation. The water is pumped out or 

displaced by injecting natural gas into the water formation. This is the leastused method of storing natural gas. 

Due to the geology of the state, very few suitable underground storage caverns exist 

within Florida. The only underground storage in Florida is in the western panhandle 

section of the state, a considerable distance from southern Florida. Existing caverns in 

that area would not meet the Project purpose of serving most of Florida via interconnects 

to the two major interstate pipeline systems. Oil reserves, such as those being rapidly 

depleted within the Florida Everglades, have been eliminated from further consideration 

because they do not have the “tight” characteristics desired for natural gas storage. The 

Everglades are also an environmentally sensitive area where any work could have 

significant environmental consequences. Aquifer storage is also not a viable alternative. 

It is not common in Florida due to significant cost and environmental impediments, 

which make aquifer storage typically the alternative of last resort for storing natural gas 

in this area. As such, the typical underground storage options are not viable system 

alternatives to meet the Project’s objectives and have been eliminated from further 

analysis. 

Existing, Approved, or Proposed LNG Terminal Projects 

There are no existing LNG import terminals in Florida, although there are several 

proposed projects in various stages of development off the coast of Florida. These 

include: 

• Ocean Cay LNG import terminal by AES Corporation (AES); 

• Calypso Freeport LNG import terminal by SUEZ Energy North America; 
3-7 3.0 – Alternatives

• Calypso Deepwater Port by SUEZ Energy North America; and 

• Port Dolphin Deepwater Port by Port Dolphin Energy, LLC. 

SUEZ Energy North America (Suez) submitted an application to build and operate an onshore LNG import terminal near Freeport in The Bahamas. The terminal would sendout 

natural gas to Florida via the Calypso pipeline. The government of The Bahamas has not 

yet acted on the application. 

In September 2002, AES submitted an application for approval to build and operate an 

on-shore LNG import terminal on Ocean Cay in The Bahamas. The terminal would 

sendout natural gas to Florida via the approximately 54-mile-long Ocean Express 

pipeline extending from The Bahamas and interconnecting with the FGT pipeline system 

in Broward County. On February 21, 2002, AES filed an application with the FERC for 

the Ocean Express pipeline (FERC Docket CP02-90). The FERC issued a certificate 

authorizing the pipeline on January 22, 2004. The government of The Bahamas has not 

yet acted on the application. 

On July 20, 2001, Suez filed an application with the FERC for the Calypso pipeline 

(FERC Docket CP01-409). Suez received conditional authorization from the FERC on 

March 24, 2004 (and subsequently amended) for the 42-mile-long pipeline extending 

from The Bahamas Exclusive Economic Zone to an interconnection with the FGT 

pipeline system in Broward County. Construction of the Calypso pipeline is conditional 

upon receipt of evidence that all authorizations and approvals have been received, either 

from the Commonwealth of The Bahamas for the Bahamian portions of the project, or 

from the U.S. Coast Guard (USCG) for the proposed deepwater port. 

On March 1, 2006, Suez submitted an application to the USCG for a deepwater port 

license to allow the import of natural gas to Florida's east coast. This proposed Calypso 

deepwater port (USCG Docket No. 26009) would be located approximately 10 miles 

offshore from Port Everglades. It would send out natural gas to Florida via the Calypso 

pipeline. The USCG issued a draft EIS in November, 2007 and the project is still 

undergoing review. 

On March 29, 2007, Port Dolphin Energy submitted an application to the USCG for a 

deepwater port license to allow the import of natural gas to Florida's west coast. The 

proposed Port Dolphin deepwater port (USCG Docket No. 28532) would be located 

approximately 28 miles offshore from Tampa Bay. It would sendout natural gas via a 

new 42-mile-long sub-sea pipeline. This proposal is still under review by the USCG. 

The purpose of the FGS Project is to store natural gas so it is available during periods of 

peak demand or emergencies when supply is shut in. These proposed LNG import 

terminals could partially meet this goal by providing increased natural gas supply, but 

these import terminals primarily function as base-load facilities and often have little 

capability to “peak.” In fact, two of the four proposed terminals are offshore deepwater 

ports that would typically shut down during hurricanes and other major storms and would 

be unable to deliver gas during some of the very periods the FGS Project is intended to 

serve. In addition, it appears that the two onshore terminal proposals in The Bahamas 

cannot be in service within the needed timeframe. Because of the inability to meet the 
3.0 – Alternatives 3-8 

Project purpose, LNG terminals were eliminated as system alternatives to the proposed 

Project. 

Pipeline Expansion, Looping, and Compression 

Pipeline expansions involving the construction of large diameter lines, looping of 

constrained portions of the lines, or additional compression could be used to deliver more 

gas to the region during normal and peak operating scenarios. We reviewed the 

possibility that one or both of the existing Florida interstate pipelines (i.e., FGT and 

Gulfstream) could be expanded as a system alternative to the proposed Project. The 

Gulfstream Pipeline is already being expanded within Florida to give access to new 

market areas. The FGT system has had six major expansions to allow for greater 

deliverability and further increases are limited. Pipeline expansions can have significant 

environmental impacts depending on the length of pipe and location, and would not 

satisfy the Project objective of having supply available in Florida to serve the region 

during weather-related shut-ins when pipeline deliveries are curtailed or disrupted. 

Therefore, expansion of existing interstate pipelines was not considered a viable system 

alternative. 

3.3.2 LNG Storage Facility Site Alternatives 

Several other LNG storage facility sites were identified and evaluated as possible 

alternatives to the proposed storage facility site using the following criteria: 

• site area (i.e., must be able to accommodate Project needs); 

• extent of wetlands and protected areas; 

• compatibility with surrounding land use; (i.e., existing land use and number of 

residences within 50-feet of proposed facilities); 

• compatibility with existing zoning and local future land use plans; and 

• proximity to one or both of the Gulfstream and FGT pipelines. 

Based on these criteria, six alternative sites were identified in south Florida: 

• Site 1 - FPL’s Martin Power Plant Property, Martin County; 

• Site 1A - Adjacent to FPL’s Martin Powerplant Property, Martin County; 

• Site 2 - Pratt & Whitney Property, Palm Beach County; 

• Site 3 - Adjacent to FPL’s West County Energy Center, Palm Beach 

 County; 

• Site 4 - Turkey Point Vicinity, Miami-Dade County; and 

• Site 5 - Allapattah Flatts. 

Figure 3.3-1 shows the location of each alternative site. Table 3.3-1 compares the six 

alternative sites with the proposed LNG storage facility site using the siting criteria listed 

above. Five of the alternative sites (sites 1, 1A, 2, 3, and 4) were not located near 

protected natural or residential areas; however, site 5 was located in the Allapattah Flatts 
3-9 3.0 – Alternatives

Management Area. Five of the alternative sites (sites 1, 1A, 2, 3, and 4) were all smaller 

in area than the proposed site and, depending on site specific conditions, may or may not 

have sufficient area to satisfy the required thermal radiation and vapor dispersion 

exclusion zones on-site. 

Alternative Site 1 - FPL Martin Powerplant Property 

Alternative Site 1 is located at the Martin Power Plant owned by FPL, in unincorporated 

Martin County, on land owned by FPL. The primary disadvantages of this site were the 

presence of a relatively large (65 percent) proportion of natural forest and wetlands and 

FPL’s unwillingness to sell the property. Therefore, we believe that Alternative Site 1 

does not offer an environmental advantage over the proposed site. 

Alternative Site 1A – Adjacent to the FPL Martin Powerplant 

Alternative Site 1A is located adjacent to the FPL Martin Powerplant in unincorporated 

Martin County. The primary disadvantages of this site were the proximity of residences 

(several within 0.25 miles of the site) and compatibility with future surrounding land uses 

as future land use plans propose agricultural ranchettes. Therefore, we believe that 

Alternative Site 1A is less preferable than the proposed site. 

Table 3.3-1 

Comparison of Alternative LNG Storage Facility Sites 

Alternative Site Locations 

Criteria 

Proposed 

Site Site 1 Site 1A Site 2 Site 3 Site 4 Site 5 

Site Area (acres) 145 ~80 ~80 ~80 ~60 ~80 Unknown3

Wetlands (percentage)1 ~10 ~15 ~1 ~75 ~1 ~50 Unknown3

Protected Areas 0 0 0 0 0 0 100% 

Existing Land Use1 Industrial 

Forest, 

Open Land Agriculture 

Sparsely 

Forested Open Land 

Power 

Generation, 

Open Land Open Land 

Residences2 0 0 0 0 0 0 0 

Zoning Designation Industrial Agricultural Agricultural Industrial Agricultural Industrial Agricultural 

Future Land Use Industrial 

Power 

Generation 

Agriculture 

Ranchette Industrial Agriculture 

Institutional, 

Utilities, and 

Communicat

ion 

Conservation 

and recreation 

land 

Pipeline FGT ~4 <1 <1 <1 19 ~5 ~12 

lateral length 

(miles) Gulfstream ~4 <1 <1 ~8 <1 ~75 ~12 

Notes: 

1

 Based on 2004 FDEP Land Boundary Information System Aerials 

2

 Within 50-feet of proposed site 

3

 During scoping, the Allapattah Flats (approximately 21,000 acres) were generally identified as potential alternative sites. No specific 

location within this area was identified, therefore detailed information is unavailable. The area is currently part of the South Florida Water 

Management District (SFWMD) Allapattah Flats Management Area and Indian River Lagoon South restoration project. 

Sources:

Martin County Growth Management Department Future Land Use and Zoning Map; Palm Beach County Planning, Zoning & Building 

Department Future Land Use and Zoning Map; Miami-Dade County Planning and Zoning Department Future Land Use and Zoning Map 
3-10 3.0 –Alternatives

Figure 3.3-1 

FGS Project 

Alternative Storage Facility Sites Location Map 

Alternative Site 5 
3-11 3.0 – Alternatives

Alternative Site 2 - Pratt Whitney Property 

Alternative Site 2 is located near a major pipeline lateral owned by FPL in 

unincorporated western Palm Beach County. The existing lateral is a dual fuel pipeline 

that carries both fuel oil and natural gas approximately 20 miles northeast to the FPL 

Martin Plant. The primary disadvantages of this site were the relatively large percentage 

of wetlands (75 percent), the proximity (0.2 miles) of the site to the William P. Gwinn 

private airport (see Table 2.8-1 for proximity to airport runway siting criteria), and the 

potential access limitations to the FPL lateral due to the lateral’s dual fuel capabilities. 

Therefore, we believe that Alternative Site 2 does not offer an environmental advantage 

over the proposed site. 

Alternative Site 3 - Adjacent to FPL’s West County Energy Center 

Alternative Site 3 is located in unincorporated northern Palm Beach County. The 

primary disadvantages of this site were its proximity to the Loxahatchee National 

Wildlife Refuge, which provides habitat for a large number of threatened and endangered 

species; relatively small size (approximately 60 acres); and a relatively long pipeline 

(approximately 19 miles). Therefore, Alternative Site 3 was eliminated from further 

consideration. 

Alternative Site 4 - Turkey Point Vicinity 

Alternative Site 4 is located in unincorporated Miami-Dade County. The primary 

disadvantages of this site were the presence of a relatively large (50 percent) proportion 

of wetlands and the ability to only connect to the FGT pipeline. The Gulfstream 

interconnection is more than 75 miles north of the site. Therefore, we believe that 

Alternative Site 4 does not offer an environmental advantage over the proposed site. 

Alternative Site 5 – Allapattah Flats 

During scoping, the Allapattah Flats area was suggested as a potential alternative site for 

the LNG storage facility. The Allapattah Flats are undeveloped lands located 

approximately nine miles northeast of the proposed Project site along SW Allapattah 

Road. The area was placed on the South Florida Water Management District (SFWMD) 

Save Our Rivers and the State’s Conservation and Recreational Lands acquisition list in 

1996. This area was described in the SFWMD Allapattah Flats Land Management Plan 

(2004-2009) as having high quality natural systems and wildlife habitat and was 

identified as a key component of the Indian River Lagoon South Restoration Project. The 

SFWMD and Martin County have acquired 21,000 acres of land within the Allapattah 

Flats, and the Natural Resource Conservation Service has a conservation easement over 

15,000 acres of that acquisition under the Wetland Reserve Program. The suggested site 

is also outside the Primary Urban Service Boundary for Martin County, and, therefore, 

industrial use is not an allowed land use under the Martin County Comprehensive Plan. 

Based on the Allapattah Flats land management policies, existing conservation 

easements, and the inconsistency with Martin County Comprehensive Plan, we 
3.0 – Alternatives 3-12 

determined that the Allapattah Flats were not a reasonable alternative and were not 

carried forward for analysis in this EIS. 

Proposed Site 

The proposed LNG storage facility would be located in unincorporated Martin County. 

The site contains a small percentage of wetlands (i.e., about 10 percent) and is close (i.e., 

approximately four miles) to both the Gulfstream and FGT pipelines. This site, formerly 

an industrial facility operated by Florida Steel, is zoned industrial, is compatible with 

surrounding land uses, and is available for sale. This is the largest of the sites evaluated 

with sufficient area to satisfy all required exclusion zones on-site. 

3.4 PIPELINE AND ABOVEGROUND FACILITY ALTERNATIVES 

3.4.1 Pipeline Route Alternatives 

Based on the location of the proposed LNG storage facility site, one proposed and three 

alternative routes were identified for the two natural gas pipelines. Alternative natural 

gas pipeline routes were evaluated using the following criteria: 

• total pipeline length; 

• presence of existing rights-of-way; 

• availability of sufficient easement width (at least 50-feet-wide); 

• compatibility with existing zoning and future land use plans; 

• compatibility with adjacent land use (i.e., number of residences within 50-feet 

of construction right-of-way); 

• extent of wetlands and waterbody crossings; 

• presence of federal or state protected areas; and 

• presence of public recreation areas. 

Based on these criteria, three pipeline route alternatives were identified for connecting 

the proposed LNG storage facility with the Gulfstream and FGT pipelines: 

• Route 1 - Adjacent to or north of SR 710 right-of-way 

• Route 2 - Adjacent to or within the CSX railroad right-of-way 

• Route 3 - Along the SR 710 right-of-way and FPL transmission line 

 right-of-way 

All of the natural gas pipeline alternatives are located in unincorporated western Martin 

County, Florida. Figure 3.3-1 shows each alternative pipeline route and the proposed 

route. In addition to the primary alternative routes, three route variations were each 

evaluated for Alternatives 1 and 2: 
3-13 3.0 – Alternatives

Alternative Route 1: 

1a - Adjacent to and north of SR 710 right-of-way on private land; 

1b - Within the northern SR 710 right-of-way; and 

1c - Within the southern SR 710 right-of-way. 

Alternative Route 2: 

2a - Within the northern CSX railroad right-of-way; 

2b - Within the southern CSX railroad right-of-way; and 

2c - Adjacent to the CSX railroad on private land. 

Table 3.4-1 compares the alternative routes and their variations with the proposed route. 

Table 3.4-1 

Comparison of Pipeline Route Alternatives 

Natural Gas Pipeline Route Alternatives 

Criteria Proposed Alternative Route 1 Alternative Route 2 

Route Route 1a Route 1b Route 1c Route 2a Route 2b Route 2c 

Alternative 

Route 3 

Total Pipeline 

Length 

(miles) 

4.2 6.3 6.3 6.3 6.3 6.3 6.3 4.5 

Right-of-Way 

(ROW) Type 

Transmission 

line 

None - 

Private land 

Highway Highway Rail Line Rail Line None - 

Private 

land 

Highway 

Zoning 

Designation 

Planned unit 

development

-industrial, 

General 

industrial, 

Heavy 

industrial, 

Agricultural 

Agricultural, 

Planned unit 

development, 

industrial 

SR 710 

ROW 

SR 710 

ROW 

CSX ROW CSX ROW General 

industrial, 

Heavy 

industrial, 

Agricultural 

SR 710 

ROW 

Agricultural 

Future Land 

Use 

Designation 

Industrial, 

Power 

generation 

Industrial, 

Ranchette, 

Agricultural, 

Commercial 

SR 710 

ROW 

SR 710 

ROW 

CSX ROW CSX ROW Industrial, 

Power 

generation 

SR 710 

ROW Power 

generation 

Residences 

within 50 feet 

of 

construction 

easement 

0 0 0 0 0 0 0 0 

Waterbody 

Crossings 

0 0 0 0 0 0 0 0 

Wetlands Marshes and 

prairies 

Ditches and 

ponds 

Ditches 

and ponds 

Forest/ 

scrubshrub/ 

wetlands 

Forest/ 

scrubshrub/ 

wetlands 

Forest/ 

scrubshrub/ 

wetlands 

Forest/ 

scrubshrub/ 

wetlands 

Marshes 

and prairies 

Federal and 

State 

Protected 

Lands 

0 0 0 0 0 0 0 0 

Recreation 

Areas 

0 0 0 0 0 0 0 0 
! ! !

! !

! !

! ! !

! ! !

S R- 7 1 0 C S X R ailr o a d

St or a g e F a cilit y 

Sit e

Pr o p o s e d Pi p eli n e 

R o ut e

0. 2 5 0. 5 Mil e s

L e g e n d R o a d s

R ailr o a d

M & R St ati o n

St or a g e F a cilit y Sit e

Pr o p o s e d Pi p eli n e R o ut e

Alt er n ati v e Pi p eli n e R o ut e 1

Alt er n ati v e Pi p eli n e R o ut e 2

Alt er n ati v e Pi p eli n e R o ut e 3

Fi g ur e 3. 4- 1

F G S Pr oj e ct

Alt er n ati v e Pi p eli n e R o ut e s
3- 1 5 3. 0 – Alter n atives

All of t he alter nati ve r o utes are l o n ger t ha n t he pr o p ose d r o ute. Alter nati ve R o ute 1a was 

eli mi nate d beca use a lar ge p orti o n of t he al i g n me nt w o ul d be t hr o u g h wetla n ds or o pe n 

water. Alter nati ve R o utes 1 b a n d 1c were eli mi nate d beca use t he a vaila ble wi dt h wit hi n 

t he S R 7 1 0 ri g ht- of- wa y w o ul d be i na de q uate (i.e., a p pr o xi matel y 1 8 feet), ot her utilities 

(e. g., electric, ca ble) are alread y prese nt i n t he ri g ht- of- wa y, a n d t he Fl ori da D O T pla ns 

t o wi de n S R 7 1 0 n ort h of C o u nt y R oa d 6 09 w o ul d c o nflict wit h t he pi peli nes. 

Alter nati ve R o utes 2a a n d 2 b were eli mi nate d beca use C S X state d t hat a n y u n use d la n d 

i n its ri g ht- of- wa y was slate d f or f ut ure rail uses, a n d a ca ble utilit y li ne a n d F P L’s 1 8-

i nc h- dia meter d ual f uel pi peli ne are alrea d y prese nt i n t he ri g ht- of- wa y. Alter nati ve 

R o ute 2c was eli mi nate d beca use it w o ul d affect m ore wetla n ds a n d pri vate pr o pert y 

o w ners t ha n t he pr o p ose d r o ut e. Alter nati ve R o ute 3 w o ul d ha ve si milar ri g ht- of- wa y 

a n d utilit y c o nflicts as Alte r nati ve R o ute 1 b a n d 1c, al beit f or a s h orter dista nce, a n d 

t heref ore was eli mi nate d. 

Pr o p ose d R o ute 

T he pr o p ose d r o ute is t he s h orte st of t he alter nati ves c o nsi dere d a n d c o-l ocate d wit h 

e xisti n g utilit y ri g hts- of- wa y. T he pr o p ose d r o ute w o ul d n ot tra verse a n y pr otecte d la n ds 

or ot her desi g nate d areas, is n ot wit hi n 5 0 feet of a n y resi de nces, a n d w o ul d ha ve 

mi ni mal effects o n wetla n ds. Of t he r o utes c o nsi dere d, t he pr o p ose d r o ute w o ul d ha ve 

t he least e n vir o n me ntal i m pact. T heref ore, we belie ve t he pr o p ose d r o ute is 

e n vir o n me ntall y prefera ble a n d d o n ot rec o m me n d use of a n y alter nati ve pi peli ne r o utes. 

3. 4. 2 A b o v e gr o u n d F acilit y Alt er n ati v es 

F G S pr o p oses a n a b o ve gr o u n d M & R stati o n a n d i nterc o n necti o ns wit h t he G ulfstrea m 

a n d F G T pi peli nes. O ur re vie w of t he pr o p ose d M & R stati o n a n d i nterc o n necti o n sites 

raise d n o iss ues (i.e., pr o xi mit y t o resi dences, i m pacts t o wetla n ds, t hreate ne d a n d 

e n da n gere d s pecies, or c ult ural res o urces). We c o ncl u de t here are n o practical alter nati ve 

sites offeri n g a clear e n vir o n me ntal ad va nta ge t o t he pr o p ose d M & R stati o n. 

3. 4. 3 H y dr ot est W at er Pi p eli n e Alt er n ati v es

F G S pr o p oses t o use a te m p orar y h y dr otest li ne t o c o n ve y test water t o t he L N G st ora ge 

facilit y site. T he pr o p ose d r o ute is t he m ost direct, f oll o ws e xisti n g drai na ge ditc hes a n d 

tra ns missi o n li ne ri g hts- of- wa y, re q uires n o a d diti o nal ease me nts, a n d w o ul d n ot res ult i n 

a n y per ma ne nt i m pacts. T he 1. 8 6- mile-l o n g te m p orar y pi peli ne wo ul d be lai d o n t he 

gr o u n d s urface f or t he d urati o n of t he h y dr otes t peri o d (a p pr o xi matel y 5 wee ks) a n d t he n 

re m o ve d. We c o ncl u de t here are n o practical alter nati ve sites offeri n g a clear 

e n vir o n me ntal a d va nta ge t o t he pr o p ose d h y dr otest pi peli ne r o ute. 
4-1 4.0 – Environmental Analysis

4.0 ENVIRONMENTAL ANALYSIS 

4.1 GEOLOGY 

4.1.1 Geological Setting 

The proposed plant site is relatively level with grade elevations varying between 33 and 

38 feet about sea level (National Geodetic Vertical Datum of 1929). A steel 

manufacturing facility (now abandoned) was previously located on the site. The facility 

has been closed for many years and was the subject of a remedial action under the EPAsupervised Superfund program. There continues to be some groundwater remediation ongoing at the site. A lined and capped containment facility (land vault) for contaminated 

soils is adjacent to the site (see Figure 2.1-3). Many large shallow foundations and 

building remains exist on the site from the abandoned facility. 

The Project site is underlain by a mix of sand, shell, limestone, and clay. From ground 

level to a depth of approximately 5 to 10 feet, the site geology is dominated by various 

soils, including Urban Land, Lawnwood fine sand, Myakka fine sand, Waveland sand, 

Immokalee sand. Below the surficial soil horizons are the Plio-Pliestocene-aged sands, 

sandy limestone, clay, and shell beds present to a depth below ground level of 135 feet to 

175 feet. The upper six feet of these sediments is a dense hardpan layer. These 

sediments are representative of the Pamilco sand, Calooshatchee Marl, and the Tamiami, 

Anastasia and Fort Thompson Formations. The Plio-Pliestocene sediments 

unconformably overlie the dense, phosphatic clays of the Miocene-aged Hawthorn Group. 

The Hawthorn Group sediments extend from between 175 feet and 763 feet below the 

ground surface. The Hawthorn Group is a complicated unit consisting of interbedded and 

intermixed carbonate and siliciclastic sediments containing varying percentages of 

phosphate grains. The upper portion of the Group is typically well indurated and 

contains primarily interbedded sands and clays. The lower portion of the Group is more 

indurated and contains primarily carbonates. The exact composition of the Hawthorn 

Group is of considerable importance to the proposed project structures due to the overall 

compressibility of the Formation. Lying below the Hawthorn Group and Suwanee 

Limestone sediments at depths of approximately 700 to 900 feet below the ground 

surface is the Ecoene-aged Ocala Limestone. Below the Ocala Limestone, Avon Park 

Formation extends to a depth of approximately 1,900 feet below the ground surface and 

below the Avon Park Formation then the Oldsmar Formation extends to depth of 

approximately 3,500 feet below the ground surface. 

4.1.2 Seismic Design Requirements 

The seismic design requirements for LNG facilities are contained in the U.S. DOT 

regulations at 49 CFR Part 193, which adopts the seismic design provisions of the NFPA 

59-A 2001. A detailed geotechnical site investigation and a site-specific seismic hazard 

analysis are required. 
4.0 – Environmental Analysis 4-2 

NFPA 59-A 2001 defines two levels of earthquake motions, the Operating Basis 

Earthquake (OBE) and the Safe Shutdown Earthquake (SSE). The OBE and SSE ground 

motions must be determined by site-specific evaluations and are defined in terms of 5 

percent damped response spectra with the following probability levels: 

The OBE ground motions at the site are defined as the lesser of: 

1. ground motion with a 10% probability of exceedance within a 50 year period 

(475 year return period); or 

2. two-thirds (2/3) of the Maximum Considered Earthquake (MCE) ground 

motion. 

The SSE ground motions at the site are defined as the lesser of: 

1. 1% probability of exceedance within a 50 year period (4975 year return 

period); or 

2. two times the OBE. 

In NFPA 59-A 2001 the MCE is defined as future potential ground motion with a two 

percent probability of exceedance within a 50 year period (2,475 year return period) with 

deterministic limits. 

These motions would be used as the basis for the earthquake-resistant design of the LNG 

facility, applied to the following limited specific list of critical safety-related structures, 

systems, and components per NFPA 59-A-2001 section 4.1.3: 

1. LNG storage containers and their impounding systems; 

2. System components required to isolate the LNG container and maintain it in a 

safe shutdown condition; and 

3. Structures and systems, including fire protection systems, the failure of which 

could affect the integrity of (1) or (2) above. 

NFPA 59-A-2001 specifies that the above-referenced structures, systems, and 

components must be designed to remain operable during and after an OBE, and must 

provide for no loss of containment capability of the primary container during and after an 

SSE. The facility design must also provide for the ability to isolate and maintain the 

LNG container during and after a SSE. After a SSE event, the container must be emptied 

and inspected prior to resumption of container filling operations. As a minimum, the 

impounding system must be designed to withstand a SSE while empty and an OBE while 

holding the maximum operating volume of the LNG container. Seismic recording 

instrumentation is also required. 

4.1.3 FERC Seismic Design Guidelines for LNG Facilities 

There are areas where NFPA 59-A 2001 does not provide specific seismic design 

requirements to enable a comprehensive philosophical approach to the overall seismic 

safety of an LNG facility. Consequently there can be a wide range of opinions by 

technical experts on how various requirements are to be applied. In our “Draft Seismic 

Design Guidelines and Data Submittal Requirements for LNG Facilities” (FERC Seismic 
4-3 4.0 – Environmental Analysis

Guidelines), January 2007, we provide specific guidance to applicants on FERC Staff’s 

interpretation of the requirements of NFPA 59-A 2001, providing consistent design 

specifications throughout the U.S., and a basis for uniform reviews of various LNG 

terminal sites, structures, components, and systems under FERC jurisdiction. 

In general, the FERC Seismic Guidelines are based on existing rules and procedures 

found in ASCE 7-05, ASCE 4-98, API 650 Appendix E, and other current standards 

documents applicable to LNG facilities. The guidelines also rely on the National Seismic 

Hazard Maps and the 2006 International Building Code (IBC 2006) MCE Ground Motion 

Maps, which were developed specifically for use in the design of buildings and other 

structures in the United States by the United States Geological Survey. 

The FERC Seismic Guidelines classify the structures, components, and systems identified 

in NFPA 59-A 2001 section 4.1.3.3 -- ((1), (2), and (3) above), as “Seismic Category I.” 

The remaining structures, systems, and components are classified as either Seismic 

Category II or III. 

Seismic Category II and III structures, systems, and components are to be designed in 

accordance with the seismic design requirements of ASCE 7-05 (i.e., IBC 2006). 

Category II structures, systems, and components must meet the seismic performance 

goals for “essential” facilities. Category II facilities are expected to survive the Design 

Earthquake (DE) (which is 2/3 the MCE) with potential structural damage that would not 

be so severe as to preclude continued occupancy and function of the facility. An 

“Importance Factor” (“I” or “Ip”) of 1.5 is specified for design of Category II facilities. 

Category III facilities are considered “non-essential.” Normal, non-essential facilities 

would be designed for the DE in accordance with ASCE 7-05 and are expected to sustain 

repairable damage when subjected to DE ground motions, although it may not be 

economical to do so. An “Importance Factor” (“I” or “Ip”) of 1.0 is specified for design 

of Category III facilities. 

The FERC Seismic Guidelines provide guidance on lower permitted limits for site 

specific design ground motions. It also provide guidance in determining the appropriate 

Site Class spectral amplification values and long-period spectra displacement cutoff 

transition period per ASCE 7-05, inelastic reduction factors for the SSE, minimum safety 

factors for tank foundation loadings and maximum permitted foundation settlements, 

minimum freeboard requirements for LNG sloshing heights and the selection and 

location of seismic recording devices. Finally, it provides guidance on the seismic design 

criteria and foundation design criteria to be used for the design of Seismic Category II 

and III facilities. 

4.1.4 Geological Hazards, Site-Specific Geotechnical Investigation and 

Seismic Hazard Analysis 

Golder Associates, Inc. (2007) conducted a detailed geotechnical site investigation and 

site-specific seismic hazard analysis for the proposed Project. The findings and 

conclusions regarding geological hazards, foundation design requirements, and seismic 

design are summarized below. 
4.0 – Environmental Analysis 4-4 

The two most significant geologic hazards at the site are associated with the potential for 

sinkhole activity or subsidence. Based on lack of active sinkholes in vicinity of the site, 

published information, and the fact that clayey silt of the Hawthorn Formation was 

encountered at depth in all borings, sinkhole potential at the site is considered low. 

Anticipated subsidence and settlements associated with consolidation of clays within the 

Hawthorn Group are considered manageable through surcharging and engineering 

improvements of the subsurface soils. 

The site is located in the Atlantic Coast province of the U.S. that extends along the 

eastern parts of Georgia and Florida. The geomorphic province is characterized generally 

as having one of lowest seismic hazards within the conterminous 48 states. Due to the 

relative stability in Florida, the 2006 IBC assigns structures that are located at the project 

site Seismic Category A which is the lowest seismic design requirements assignment. 

Generally, there are no known major fault systems beneath the Florida Platform and there 

is no evidence of major active faulting or deformation in Florida during the Holocene 

Epoch or the Neogene Epoch. No faults are known to be active in Pleistocene time in 

Martin County. Therefore, the potential for surface faulting at the site is considered 

extremely remote. 

Along the Gulf and Atlantic coasts, the potential wave run-up due to hurricane storm 

surge is far greater than any potential tsunami wave run-ups. The distance of the site and 

its elevation above sea level indicate therefore a negligible probability of significant 

impacts from tsunamis or hurricane storm surge at the site. 

The site is located approximately eight miles to the east of Lake Okeechobee. The 

normal water elevation of the lake is approximately 14 feet above mean sea level. The 

distance of site from Lake Okeechobee, its elevation of the site above the lake level, and 

the low probability of strong earthquake ground motions indicate a negligible probability 

of significant site impacts from seiches. 

Based on medium to very dense soils at the site and the low SSE design ground motions, 

it was concluded that liquefaction of the soils below the LNG tank foundations and at 

other portions has a negligible probability of occurring. 

Because liquefaction is not expected to occur during the SSE, liquefaction induced 

settlements or lateral spreading ground movements are not expected at the site. 

Because of the low level of SSE shaking and the medium to very dense soils at the site, 

significant seismic compaction settlements are not expected at the site. 

The measured shear wave velocity of the soil profile at the site increases nonlinearly from 

approximately 260 feet per second (fps) from the ground surface to about 1,000 fps at a 

depth 100 feet below the ground surface. The weighted shear wave velocity in the upper 

100 feet of the soil profile is about 750 fps. This characterizes the soil profile as Site 

Classification D (stiff soil) in accordance with provisions of the 2006 IBC and ASCE 7-

05. 

The site would be cleared, grubbed, and stripped of vegetation and existing foundations 

will be broken up and removed. Surficial soils will be stripped and engineering fill 

recompacted to a depth determined during detailed design. In the foundation areas of the 
4-5 4.0 – Environmental Analysis

LNG tanks surcharging with soil will be applied for a limited period. The surcharge, 

which would require approximately 75,000 cubic yards of earthfill, would be configured 

as the frustum of a cone that is 20 feet in height with a surcharge footprint of 

approximately 3.2 acres. Surcharge material would have a dry unit weight of no less than 

110 pounds per cubic foot after placement and compaction. The expected duration of 

constructing the surcharge for the first tank is estimated to be about one month, and the 

surcharge would remain in place for at least one month after it is constructed. The 

surcharge for the second tank would be applied using the same material during 

construction of the first tank, and the duration of the second surcharge would be longer 

than one month. About twelve settlement plates would be installed along the tank 

perimeter and two horizontal inclinometers would be installed on perpendicular diameters 

of the surcharge footprint. The induced stresses would be measured using stress cells 

installed at the base of the surcharge. The instrumentation would be monitored regularly 

to measure settlement. The material used for the surcharge could thereafter be used onsite as structural fill. The major equipment and facility’s foundation (including the LNG 

tanks) are proposed to be supported by shallow reinforced concrete mat foundations. The 

foundations will in turn be supported by engineered fill. The fill elevation of all areas of 

the Project will be several feet above the water table and it is expected that few excavated 

areas will require extensive dewatering. The LNG tank mat will be 300 feet in diameter, 

three to four feet thick at the edge and taper to two feet thick at the center. The LNG tank 

foundation has the following settlement tolerances (which satisfy the recommendations in 

the draft FERC Seismic Design Guidelines): 

• Tilting settlement of less than 6 inches; 

• Out of plane settlement of the outer tank shell of less than 1.25 inches 

in a 100-foot arc length; 

• Center to edge dishing settlements of less than 6 inches; and 

• After connections to the tank are made, a total settlement of less than 1 

inch. 

Controlling Seismic Events 

Generally, there are no known major fault systems beneath the Florida Platform and there 

is evidence of major active faulting or deformation in Florida during the Holocene Epoch 

or the Neogene Epoch. Deaggregation of the seismic hazard from a probabilistic seismic 

hazard assessment indicates that local moderate magnitude earthquakes (M 4.5 - 5.0) 

contribute most of the earthquake hazard in the region of the site. A small contribution to 

the hazard derives from the occurrence of large magnitude earthquakes in the 

southeastern United States (e.g. Charleston, South Carolina). The local earthquakes are 

not associated with any specific faults or seismic source zones but instead the very small 

possibility that moderate earthquakes could occur anywhere in the region. 

Input Ground Motions 

Input ground motions for the site (also called Design Ground Motions) were determined 

based on probabilistic seismic hazard maps developed by the USGS in 2002. These maps 

also form the basis of the MCE mapped values found in the 2006 IBC and ASCE 7-05. 
4.0 – Environmental Analysis 4-6 

The values have been adjusted to account for soil amplification effects based on Site 

Classification D. The ground motions have been determined in a manner that 

conservatively satisfy recommendations found in the draft FERC Seismic Design 

Guidelines and requirements of NFPA 59-A 2001. 

• The MCE ground motion parameters (not adjusted for site effects) are 

Ss = 0.069 g and S1 = 0.027 g. The value of TL is 8 seconds. When 

adjusted for site effects, the MCE ground motion parameters are SMS = 

0.111g and SM1 = 0.064g.

• The DE ground motion parameters adjusted for site effects (which are 

2/3rds of the MCE value adjusted for site effects) are SDS = 0.074g and 

SD1 = 0.043g. 

• The OBE was conservatively taken as equal to the DE. The OBE peak 

horizontal ground acceleration for the site is 0.034g. The vertical OBE 

design ground spectra is the OBE horizontal ground motion spectra 

multiplied by 2/3rds resulting in an OBE peak vertical ground 

acceleration for the site of 0.023g.

• The SSE was taken as equal to twice the OBE. Since the OBE was 

taken as the DE, the SSE conservatively satisfies the minimum SSE 

limitations provided in the draft FERC Seismic Design Guidelines. 

Therefore, the SSE design ground motion response spectra is twice the 

OBE design response spectra with an SSE peak horizontal ground 

acceleration of 0.067g. The vertical SSE design ground motion is the 

SSE horizontal ground motion spectra multiplied by 2/3rds resulting 

an SSE vertical ground acceleration for the site of 0.045g. 

Final designs and supporting documentation for all critical structures and foundations 

(Seismic Category I) will be required prior to FERC approval to proceed with 

construction. We recommend the following conditions to any approval the 

Commission might issue for the proposed project: 

1. File a detailed plan, including calculations, for the LNG tank foundation 

surcharge, prior to construction. 

2. File a list of all structures, systems, and components that are assigned 

Seismic Category I prior to construction for review as described in section 

3.6 of Part II of the FERC Seismic Guidelines. 

3. Seismic Design Criteria should be provided for all Seismic Design Category 

I structures, systems, and components as described in section 3.7 of Part II 

of the FERC Seismic Guidelines prior to construction. The Seismic Design 

Criteria should satisfy Part I of the FERC Seismic Guidelines. 

4. LNG Tank and Foundation Design should comply with Part I of the FERC 

Seismic Guidelines. Submittals that demonstrate compliance should be 

provided prior to construction. 
4-7 4.0 – Environmental Analysis

5. Final foundation design recommendations for all other Seismic Category I 

structures should be submitted for review and approval prior to 

construction.

6. All items identified in the submitted geotechnical/seismic reports which 

were proposed to be addressed during the detailed design should be 

submitted for review and approval prior to construction. 

7. Seismic specifications to be used in conjunction with the procuring 

equipment as described in section 3.10 of Part II of the FERC Seismic 

Guidelines should be submitted for review prior to the issuing of requests 

for quotations. 

8. Quality Control and Assurance procedures as described in section 3.11 of 

Part II of the FERC Seismic Guidelines that will be used for design and 

construction should be submitted for review prior to construction of the 

project. 

9. A seismic instrumentation plan as described in section 3.12 of Part II of the 

FERC Seismic Guidelines should be provided prior to commissioning. 

10. The results of the hydrostatic load tests on the LNG storage tanks, 

including settlement data as described in section 7.4.1 of the FERC Seismic 

Guidelines should be provided prior to commissioning. 

4.1.5 Extractive Resources 

Florida has a variety of non-fuel minerals and isolated pockets of fossil fuel resources. 

Important non-fuel minerals include heavy minerals (i.e., ilmenite, rutile, zircon, and 

leucoxene), phosphate rock, sand and gravel, and peat (FDEP, 2006). 

According to McClellan and Eades (1997), Martin County does not possess mineral 

resources in economic quantities; state mapping does not show any mines within 0.25 

mile of the Project area (FDEP, 1996). The fossil fuel resources of Florida are generally 

concentrated in two areas of the state: the Sunniland Oil and Gas Field in southwestern 

Florida (Collier, Hendry, and Lee counties) and the Jay Oil and Gas Field in northwestern 

Florida (Santa Rosa and Escambia counties) (McClellan and Eades, 1997). No fossil fuel 

resources are found in Martin County. Therefore, the Project would not affect extractive 

resources. 

4.1.6 Paleontological Resources 

Paleontological resources are the fossilized remains of prehistoric plants and animals as 

well as impressions left in rock or other materials as indirect evidence of the forms and 

activities of such organisms. The surficial deposits at the LNG storage facility site are 

Quaternary (i.e., Holocene and Plio-Pleistocene-aged) deposits, which are generally 

unconsolidated and have poor fossil preservation potential. The major fossil-bearing 

units are deeply buried in the Project area and are inaccessible (Jones, 1997; MacFadden, 

1997); therefore, the Project would be unlikely to affect any fossil caches of scientific 

significance. 
4.0 – Environmental Analysis 4-8 

4.2 SOILS 

Soils at the Project were analyzed using the Web Soil Survey, which provides soil data 

and information produced by the U. S. Department of Agriculture - NRCS as part of the 

National Cooperative Soil Survey. In general, Project soils formed in sandy marine 

sediments of the Atlantic Coastal Plain. These soils typically occur on flatwoods where 

the landscape is zero to two percent slope and in depressions and drainage ways in 

flatwoods where slopes are five to six percent. 

Table 4.2-1 provides the general soil characteristics for each of the soil map units in the 

Project area. None of the Project soils are classified as Prime Farmland or considered to 

have a high erosion potential by the NRCS. 

The LNG storage facility site consists of fine sandy soils (four separate soil mapping 

units) that are very poorly to poorly drained, primarily because of shallow depth to 

groundwater and zero to two percent slopes, and considered partially hydric. Most (53 

percent) of the storage facility site was disturbed by the former Florida Steel 

manufacturing plant that operated from 1970 to 1982 that left much of the site 

contaminated with polychlorinated biphenyls (PCBs), lead, and zinc (see Section 4.7.5 

for additional information). As part of the EPA-supervised remediation, much of the 

surface soils on the site were removed, treated, and placed in an on-site landfill. The 

landfill (referred to as the “land vault”) would not be included in the Project. 

The pipeline, construction staging area, M&R station, and the pipeline interconnections 

primarily traverse sandy soils with small inclusions of loamy sands and muck, which 

encompass over 15 separate soil mapping units. These soils are generally very poorly to 

poorly drained and considered hydric or partially hydric. 

Major soil characteristics and limitations for the LNG storage facility, pipeline and 

aboveground facilities, and construction staging area are summarized in Table 4.2-1. 

4.2.1 Soil Composition and Limitations 

Drainage Class 

The drainage class of a soil is the range of its relative wetness under natural conditions. 

Soils with good drainage lose water and have low wetness, while soils with poor drainage 

retain water and have high wetness. Differences in drainage properties are typically 

attributed to grain size and sorting. Well-sorted or coarse-grained soils have more pore 

space and thus are better drained. Poorly-sorted or fine-grained soils have less pore space 

and prevent water from draining. Six classes of drainage, ranging from very poorly 

drained to excessively drained, are used to describe the relative wetness of a soil (NRCS, 

1994). 
4-9

Table 4.2-1 

Soils at the FGS Project

Soil Unit Acreage 

Erosion 

Potential 

Revegetation 

Potential 

High Compaction 

Potential 

Drainage 

Characteristics Hydric 

Prime 

Farmland 

LNG Storage Facility 

Lawnwood and Myakka fine sands (L&M) 0.56 Slight Fair No Very poorly, poorly Partially No 

Waveland and Immokalee fine sands 71.63 Slight Fair No Very poorly, poorly Partially No 

Placid and Basinger fine sands (P&B) 6.73 Slight Fair No Very poorly, poorly Partially No 

L&M and P&B 48.64 Slight Fair No Very poorly, poorly Partially No 

Open Water 9.26 NA NA NA NA NA NA 

 

Pipeline 

Arents, 0 to 2 pct slopes 0.77 Slight Very poor No Somewhat poorly No No 

Chobee loamy sand, depressional 1.85 Slight Poor No Very poorly Yes No 

Floridana fine sand, depressional 0.87 Slight Very poor No Very poorly Yes No 

Holopaw fine sand 6.31 Slight Fair No Very poorly Partially No 

Jupiter sand 0.56 Slight Poor No Very poorly Partially No 

Lawnwood and Myakka sands 2.15 Slight Fair No Very poorly Partially No 

Placid and Basinger fine sands 2.87 Slight Fair No Very poorly, poorly Partially No 

L&M and P&B 3.38 Slight Fair No Very poorly, poorly Yes No 

Malabar fine sand, high 0.72 Slight Poor No Very poorly, poorly Partially No 

Oldsmar fine sand 3.13 Slight Fair No Very poorly, poorly Partially No 

Pineda and Riviera fine sands 1.44 Slight Fair No Very poorly, poorly Partially No 

Samsula muck 0.72 Slight Very poor No Very poorly Yes No 

Sanibel muck 1.03 Slight Poor No Very poorly Yes No 

Wabasso sand 0.72 Slight Poor No Very poorly, poorly Partially No 

Waveland and Immokalee fine sands 22.05 Slight Fair No Very poorly, poorly Partially No 

 

Temporary Workspaces 

Waveland and Immokalee fine sand 5.09 Slight Fair No Poorly Partially No 

Holopaw and Oldsmare fine sands 1.51 Slight Fair No Poorly Partially No 

Lawnwood and Myakka Fine Sand 1.77 Slight Fair No Poorly Partially No 

Chobee Loamy Sand, Depressional 0.66 Slight Poor No Very poorly Yes No 

Oldsmar Fine Sand 0.38 Slight Fair No Poorly Partially No 

 

M&R Station 

Oldsmar fine sand 1.50 Slight Fair No Poorly Partially No 

Pineda and Riviera fine sands 1.25 Slight Fair No Poorly Partially No 

 

Interconnection

Holopaw Fine Sand 0.11 Slight Fair No Poorly Partially No 

Oldsmar fine sand 0.11 Slight Fair No Poorly Partially No 

 

Construction Staging Area 

Waveland and Immokalee fine sand 10.46 Slight Fair No Poorly Partially No 

Waveland and Lawnwood fine sands, depressional 0.04 Slight Fair No Poorly Partially No 

* Partially hydric soils are those soils in which only portions of the mapped soil unit display hydric characteristics. This is caused by changes in topography within a mapped soil unit. 
4.0 – Environmental Analysis 4-10 

All the Project soils contain high water tables leading to very poor to poor drainage 

classes. Project construction would, therefore, temporarily impact 127.03 acres of soils 

with high water tables. If active drainage tiles, culverts, or other drainage facilities are 

damaged during construction, FGS would replace or repair them to a condition equal to 

or better than their pre-construction condition. In addition, FGS would be responsible for 

ensuring that all areas affected by construction activities were final-graded and restored 

as closely as possible to pre-construction contours. Although damage to drainage 

structures and patterns would result in short-term impacts, the corrective procedures to be 

implemented by FGS would avoid or minimize any long-term effects. 

Hydric Soils 

Hydric soils are defined as “soils that formed under conditions of saturation, flooding or 

ponding long enough during the growing season to develop anaerobic conditions” (NRCS 

2006). Soils that formed under hydric conditions in their unaltered state are still 

considered hydric when artificially drained or altered for such purposes as agricultural 

use. Hydric soils are typically poorly drained; the presence of hydric soils is one of the 

criteria used for defining wetlands. Hydric soils may also be prone to compaction and 

rutting. With the exception of the small Arents inclusion along the pipeline corridor, all 

Project soils are considered to be at least partially hydric. 

Project construction would temporarily impact approximately 126.24 acres of hydric soils. 

Project operations would affect 78.40 acres for the LNG storage facility and pipeline 

right-of-way. 

Shallow Bedrock 

Rock can be introduced into the surface layers of soils during various construction 

activities such as blasting and trenching. Such introductions can reduce moisture-holding 

capacity, thereby reducing soil productivity and creating poor revegetation potential. The 

presence of shallow bedrock, defined as bedrock within 60 inches of the land surface, is 

often used as an indicator of the potential for introduction of rock to surface layers of soil. 

Approximately 0.56 acre of the pipeline corridor crosses soil with bedrock located within 

60 inches of the ground surface. According to the NRCS, the Jupiter sand soil series has 

hard fractured limestone bedrock beginning approximately 14 to 16 inches below the 

ground surface. FGS anticipates using mechanical methods to trench through this 

bedrock to the desired trench depth. No blasting is anticipated. Any limestone 

encountered would be removed, crushed, and used for fill for the internal roads at the 

LNG storage facility site. There is no shallow bedrock at the storage facility site. 

Erosion Potential 

Erosion potential is the potential for soil to erode when unprotected from erosive forces 

such as wind or water. Many factors influence the erodibility of soil such as soil 

structure, drainage characteristics, texture, slope, climate, and vegetation. Project 

construction can contribute to soil sensitivity to water and wind erosion. Soils are most 
4-11 4.0 – Environmental Analysis

susceptible to erosion after vegetation is removed and before the reestablishment of 

vegetative cover after the pipeline is installed. 

Severe erosion is not anticipated across the Project due to the relatively flat topography 

and sandy-textured soils. Project construction would not affect any highly erodible soils. 

During construction and operation, FGS would implement our Plan; therefore, we do not 

anticipate permanent impacts to soils from erosion hazards. 

Revegetation Potential 

Revegetation potential is a rating of the ability of a soil to support revegetation efforts 

following construction-related disturbances. The potential for revegetation of each soil 

type that would be affected by construction of the Project was assessed based on such 

factors as soil texture, drainage properties, wetness, and slope. Taking these factors into 

account, four general classes were defined for revegetation potential ranging from very 

poor to good. A poor rating includes soils with coarse-textured surface textures (i.e., fine 

sand or coarser) that are well drained, somewhat excessively drained, excessively drained, 

or soils in depressions with ponded conditions for most of the year. The majority of the 

soils in the Project area have a “fair” revegetation potential, including all soils at the LNG 

storage facility site. 

Pipeline construction would temporarily impact 7.90 acres of soils classified as 

containing poor to very poor revegetation potential. FGS would implement the 

requirements in our Plan for revegetation of disturbed areas, including consultation with 

the NRCS and appropriate state and local land management agencies regarding Projectspecific restoration measures. We conclude that if revegetation is conducted in 

accordance with these measures, areas disturbed by construction would be successfully 

revegetated. Section 4.4.2 further discusses revegetation. 

4.2.2 Contaminated Soils 

Section 4.7.5 discusses issues related to the inclusion of the LNG storage facility site in 

the Superfund Program pursuant to the Comprehensive Environmental Response, 

Compensation, and Liability Act. Contaminated soils on the storage facility site have 

been removed, treated, and placed in a secure landfill (land vault) pursuant to the 

conditions of the EPA-approved Record of Decision under the Superfund Program (see 

Figure 2.1-3). No other sites with contaminated soils are known in the Project area. 

4.2.3 Mitigation 

In order to minimize and mitigate the impacts to soil resources described above, FGS 

would adopt and follow the guidelines described in our Plan during Project construction 

and operation. The intent of our Plan is to identify baseline mitigation measures for 

minimizing erosion and enhancing revegetation in upland areas. Mitigation measures 

identified in our Plan include using erosion controls (e.g., slope breakers, silt fencing, and 

mulch) during construction to control runoff, reducing the time of soil disturbance, and 

reestablishing contours and vegetative cover as soon as practicable. 
4.0 – Environmental Analysis 4-12 

FGS would also develop and implement a Stormwater Pollution Prevention (SWPP) Plan 

in compliance with federal and state regulations, including those of the SFWMD. The 

SWPP Plan would incorporate the requirements for mitigating upland erosion and 

revegetation described in our Plan and would further detail the erosion control best 

management practices, inspection procedures, and reporting protocols to be implemented 

during construction of the Project. FGS indicates that its SWPP Plan would also include 

an Erosion and Sedimentation Control Plan and incorporate best management practices 

for stormwater systems at the LNG storage facility. 

Other potential impacts during construction would include the accidental release of 

petroleum hydrocarbons or other hazardous materials such as fuels, lubricants, and 

coolants that would be used during construction. FGS has prepared a SPCC Plan that 

describes the management of hazardous materials during Project construction. This plan 

was filed by FGS in its certificate application in October 2007 and can be found on the 

FERC’s eLibrary website at www.ferc.gov under Docket No. CP08-13-000. FGS would 

implement this SPCC Plan to prevent and contain, if necessary, accidental spills of any 

material that may contaminate soil and water resources and ensure that inadvertent spills 

of fuels, lubricants, or solvents are contained and cleaned up in an appropriate manner. 

Although not anticipated, contaminated soils could be encountered during construction 

activities. The mismanagement of contaminated material could adversely affect soil 

resources. FGS developed an Unanticipated Hazardous Waste Discovery Plan 

identifying the procedures that would be implemented during construction to identify, test, 

treat, and dispose of such materials in accordance with the appropriate federal and state 

regulations. This plan was filed by FGS in its certificate application in October 2007 and 

can be found on the FERC’s eLibrary website at www.ferc.gov under Docket No. CP08-

13-000. 

With the implementation of our Plan and FGS’s SPCC and SWPP plans, impacts to 

Project area soils would be minimized and minor in nature. 

4.3 WATER RESOURCES 

4.3.1 Groundwater 

Groundwater is a significant source of drinking water in the State of Florida, which 

historically obtains nearly all of its drinking water from aquifers. The Project is located 

over two aquifers: the non-artesian surficial aquifer system and the artesian Floridan 

aquifer system. The surficial aquifer, situated approximately 15 to 150 feet below ground 

surface, is the principal source of fresh water in Martin County. The direction of shallow 

groundwater flow is to the south towards the St. Lucie Canal (Ardaman, 2006). 

A silt and clay unit with low permeability (Hawthorne Group) separates the surficial 

aquifer from the Floridan aquifer. In contrast to the surficial aquifer, the Floridan aquifer 

is part of the largest, oldest, and deepest aquifer system in the southeastern United States. 

Ranging over 100,000 square miles, it underlies all of Florida as well as parts of southern 

Alabama, southeastern Georgia, and southern South Carolina. 
4-13 4.0 – Environmental Analysis

The Indiantown Company, a local water utility which supplies drinking water to the area 

around the Project, uses the surficial aquifer as its water source. It is the largest permittee 

of groundwater use for public water supply near the LNG storage facility site. The 

utility’s wells are located in Indiantown, approximately two to three miles south of the 

storage facility site. Permitted irrigation and industrial supply wells near the Project 

include the FPL Martin power plant, Louis Dreyfus citrus processing plant, and the 

Cogentrix power plant. 

With the exception of the LNG storage facility site and the adjacent landfill “vault,” there 

are no hazardous waste sites or known areas of contaminated groundwater in the area 

potentially affected by Project facilities. A groundwater remediation system, which was 

activated on the storage facility site in April 1997 to address high sodium concentrations, 

is still in operation (Ardaman, 2006). The remediation system consists of groundwater 

recovery, injection, and production wells as well as numerous monitoring wells. The 

water is discharged via land application on three spray fields totaling 40 acres in the 

northern portion of the storage facility site. FGS has incorporated the existing 

remediation system into the overall Project design and would comply with all on-going 

EPA required remediation activities. 

Construction Effects 

Project activities would not occur within 500 feet of any public water supply well and 

would not affect any sole-source aquifers or existing or planned wellhead protection areas. 

Pipeline trenches can redirect groundwater flow by providing a new path of less 

resistance or by blocking the original flow path. Most of the pipeline trenches for this 

Project would be oriented in the southeast direction, which is generally consistent with 

natural flow paths to the south; therefore, blockage should not be a significant issue. 

FGS does not propose any trench dewatering. 

Accidental Project-related spills or leaks of hazardous materials could potentially impact 

groundwater. FGS has agreed to adopt the spill prevention, control, and countermeasures 

included in our Procedures. In addition, FGS has developed an SPCC Plan that describes 

the management of hazardous materials such as fuels, lubricants, and coolants that would 

be used during construction and operation. Given the adoption of the measures in our 

Procedures and the SPCC Plan, the risk of accidental spills or other introduction of 

hazardous materials to groundwater would be minimized. 

Operations Effects 

The potential for impacts to groundwater resources resulting from the Project is a 

function of the magnitude and location of the withdrawal. The Project would be served 

with potable water by the Indiantown Company, which has an existing Consumptive Use 

Permit from the SFWMD for groundwater withdrawals . The LNG storage facility 

operation would withdraw groundwater at a rate of 18 to 30 gpm for landscape irrigation. 

FGS would use an existing on-site production well, which was formerly used as part of 

the groundwater remediation system, to satisfy its landscaping water requirements. The 

FDEP Hazardous Waste Cleanup Section stated that it has no objection to the use of the 

on-site well for irrigation and fire control purposes pursuant to certain conditions (FDEP, 
4.0 – Environmental Analysis 4-14 

November 28, 2007). The proposed irrigation well was previously pumped at rates 

similar to or greater than the anticipated demand for landscape irrigation. The modeling 

performed during design of the remediation system and the performance during operation 

of the remediation system both demonstrate that the use of groundwater for landscape 

irrigation would have negligible effects on nearby wells and the on-site groundwater 

remediation system. The remainder of the storage facility’s operational water 

requirements (e.g., sanitary and potable water) would be supplied via the Indiantown 

Company municipal water system and would not affect on-site groundwater. Given the 

proposed volume of water withdrawal, Project operations would have a negligible effect 

on groundwater levels and flow paths. 

The SFWMD reviewed the compatibility of the proposed groundwater withdrawals with 

local groundwater resources as part of FGS’ Water Use Permit applications. The rates of 

groundwater withdrawal would not adversely affect natural groundwater systems and 

existing users or degrade groundwater quality. The SFWMD approved the Water Use 

Permit (No. 43-02186-W) on April 10, 2008, for groundwater withdrawals for 

landscaping use at the storage facility. 

Pipeline facility operations would not require any groundwater withdrawals. 

4.3.2 Surface Water Resources 

The Project is situated within the Everglades Watershed (U. S. Geological Survey 

Hydrologic Unit Code 03090202) and, more specifically, within the approximately 

117,000-acre St. Lucie Canal drainage basin. The only major surface water feature in the 

Project area is the St. Lucie Canal. The St. Lucie Canal connects Lake Okeechobee to 

the Atlantic Ocean through the Indian River Lagoon and St. Lucie estuary. Two locks on 

the canal control its flow. The only waterbodies at the Project are three stormwater 

management ponds located on the LNG storage facility site and five drainage ditches 

along the pipeline right-of-way. 

The COE, in cooperation with the SFWMD and numerous other federal, state, local, and 

tribal partners, has started construction of the St. Lucie Canal Reservoir/Stormwater 

Treatment Area as a component of the Comprehensive Everglades Restoration Plan. This 

component would collect and treat local stormwater runoff from the basin thereby 

decreasing flows and improving water quality in the St. Lucie estuary. The Project would 

not conflict with this or any other proposed Everglades restoration efforts. 

The FDEP has established water quality standards to maintain water quality consistent 

with the associated goals of protecting public health, recreation, and the propagation and 

maintenance of healthy, well-balanced populations of fish and wildlife. Surface waters in 

the State are classified according to designated uses, with classifications arranged in 

order of the degree of protection required. Class I water (i.e., potable water supplies) 

generally has the most stringent water quality criteria, and Class V the least. The St. 

Lucie Canal is designated as Class III (i.e., recreation, propagation, and maintenance of 

healthy and well-balanced population of fish and wildlife). The site is not within or 

adjacent to any designated Outstanding Florida Waters or Aquatic Preserves. 
4-15 4.0 – Environmental Analysis

The primary potential effects of Project construction and operation on surface water 

resources would be the potential for erosion and sedimentation during construction and 

stormwater runoff during operations. The potential for accidental spills of hazardous 

materials could occur during either facility construction or operations. Both the LNG 

storage tanks and the pipelines would also use surface water for hydrotesting. 

LNG Storage Facility 

During construction of the LNG storage facility, land required for Project development 

would be cleared of vegetation and graded to the desired elevations, increasing the 

potential for erosion and sedimentation. Temporary ditches, sediment fences, and silt 

traps would be installed as necessary in accordance with our Plan and applicable state and 

local sediment and erosion control regulations. Some of the mitigation measures 

identified in our Plan include using erosion controls (e.g., silt fencing) during 

construction to control runoff; reducing the time of soil disturbance, and re-establishing 

contours and vegetative cover as soon is practicable after construction is complete. 

Stormwater from areas disturbed during construction would be discharged under a 

General Construction Permit pursuant to the National Pollutant Discharge Elimination 

System (NPDES) program, which would include conditions requiring FGS to implement 

appropriate pollution prevention techniques to reduce erosion and sedimentation and 

properly manage stormwater. FGS would also develop and implement a site-specific 

SWPP Plan. Given these protective measures, any effects to surface water associated 

with construction of the storage facility site would be minor. 

Stormwater draining from the LNG storage facility site during Project operations may 

carry various pollutants. FGS proposes to expand one of the three stormwater 

management ponds on the site to accommodate the increase in stormwater runoff. FDEP 

and Martin County have approved the stormwater management plans for the site through 

its Environmental Resource Permit (ERP) and Major Development Master Site Plan, 

respectively. Wastewater (principally domestic) generated at the storage facility would 

be disposed of through sewage lines extended by Indiantown Company to a wastewater 

treatment plant. 

Pipeline and Aboveground Facilities 

The pipeline and associated aboveground facilities would not cross any naturally 

occurring waterbodies, including any major, navigable, or sensitive waterbodies. The 

only waterbodies along the pipeline right-of-way are five small intermittent drainage 

ditches. FGS proposes to use the open cut/conventional lay method across four of these 

ditches and bore the ditch at MP 0.99. Section 2.4.2.2 describes the specialized 

construction procedures that FGS would implement to minimize impacts on waterbodies. 

It is possible that no flow would be present during construction across the four 

intermittent ditches, in which case the open-cut method would have little impact on the 

waterbody. Nevertheless, FGS would follow our Procedures to limit water quality 

impacts to waterbodies during construction. Construction activities would be scheduled 

so that the pipeline trench would be excavated immediately prior to pipelaying activities. 

FGS would use rubber tire backhoe-type excavators to open a trench across the ditch. 
4.0 – Environmental Analysis 4-16 

The duration of construction would be limited to 24 hours barring unforeseen 

circumstances. Excavated trench spoil would be stockpiled at least 10 feet from the edge 

of the waterbody with appropriate erosion and sedimentation control measures. The ditch 

banks would be stabilized. Most impacts, therefore, would be temporary; turbidity levels 

would be expected to return to preconstruction levels soon after construction in each 

ditch is completed. 

Hazardous Material Spills 

Lubricants, hydraulic fluid, and fuel spills from refueling construction equipment, or 

equipment failure in or near a waterbody could flow or migrate to a waterbody. In the 

event of an accidental spill of these or other hazardous materials during Project 

construction or operation, FGS would follow measures specified in our Procedures. Our 

Procedures include, but are not limited to, the following measures: 

• overall structuring of operations to reduce the risk of accidental spills 

or introduction of fuels or other hazardous materials into the 

environment; 

• proper training of employees handling fuels and other hazardous 

materials; 

• regular inspection of equipment to ensure good operating order; 

• storage of hazardous materials and refueling of equipment at least 100 

feet from any wetland or waterbody; 

• provisions to have the necessary tools, equipment, and supplies on 

hand to contain and recover spilled materials at the job site; and 

• prompt reporting of any spills to the appropriate agencies. 

In addition, FGS has developed and would implement its own SPCC Plan. Given the 

adoption of the measures in our Procedures and the additional measures in FGS’ sitespecific SPCC Plan, the risk of accidental spills or other introduction of hazardous 

materials to waterbodies would be effectively minimized. 

Hydrotesting 

FGS would hydrotest the LNG storage tanks and pipelines after installation in 

compliance with DOT pipeline safety regulations (see Section 2.4.1.4 and 2.4.2.1 for 

further details on hydrotesting procedures). FGS proposes to use water from the St. 

Lucie Canal as the primary source for the hydrotest water. Hydrotesting of the LNG 

storage tanks and the two pipelines would require a one-time withdrawal of 

approximately 33.5 million and one million gallons of water, respectively, which would 

be pumped at a rate of approximately 1,500 gpm. Upon completion, the test water would 

be pumped back to the canal in a manner and at a location where erosion and damage 

would be minimal. FGS indicates that it would not use any biocides or other water 

additives. 
4-17 4.0 – Environmental Analysis

The proposed withdrawal rate of 1,500 gpm represents less than 0.1 percent of the 

average annual flow in the St. Lucie Canal and would have a negligible effect on water 

flow. FGS would be required to obtain a general NPDES permit administered by the 

FDEP with EPA oversight. FGS would also avoid or adequately minimize potential 

effects to waterbodies resulting from hydrostatic testing by implementing our Procedures, 

which include, but are not limited to, the following measures: 

• obtain and comply with all applicable water withdrawal permits and 

special-status stream permits; 

• address the operation and fueling of any pumps within 100 feet of 

waterbodies or wetlands in the Project-specific SPCC plan; 

• maintain adequate flow rates in all source waterbodies to protect 

aquatic life and provide for all downstream uses; 

• screen all hydrostatic test water withdrawal intakes to prevent 

entrainment of fish and aquatic organisms; and 

• regulate the discharge of hydrostatic test waters using energy 

dissipation devices to prevent erosion, scour, turbidity, or excessive 

streamflow. 

Since FGS would return the water to its original source for discharge, not add any 

chemicals to the water, and implement our Procedures, we believe that the withdrawal 

and discharge of the hydrotest water would not adversely affect receiving water quality. 

The SFWMD approved the Water Use Permit (Permit 43-02186-W) on April 10, 2008 

for hydrostatic testing of the storage tanks and pipeline. 

4.4 VEGETATION 

The Project encompasses both wetland and upland vegetative communities, the acreages 

of which are provided in Table 4.4-1. 

Table 4.4-1 

Existing Project Vegetative Cover 

Project Components Wetlands and 

Waterbodies 

Uplands Total 

LNG Storage Facility 27.95 108.86 136.81 

Pipeline construction ROW, 

construction staging area, and 

aboveground facilities 

3.91 67.54 71.45 

Total 31.86 176.40 208.26 

4.4.1 Wetlands 

The COE defines wetlands as areas that are inundated or saturated by surface water or 

groundwater at a frequency and duration sufficient to support, and that under normal 

circumstances do support, a prevalence of vegetation typically adapted for life in 
4.0 – Environmental Analysis 4-18 

saturated soil conditions. Wetlands generally include swamps, marshes, bogs, and 

similar areas. Wetlands perform a number of valuable functions including flood flow 

attenuation, sediment retention, nutrient retention, provision of wildlife habitat, 

groundwater recharge and discharge, recreation, and erosion control. 

Section 404 of the Clean Water Act established standards to minimize impacts to 

wetlands under the regulatory jurisdiction of the COE. These standards require 

avoidance of wetlands where possible and minimization of disturbance where impacts are 

unavoidable to the degree practical. All wetland crossings would be subject to review 

and approval by the Jacksonville District of the COE, including the provisions for any 

required wetland compensatory mitigation. 

In addition to federal regulation, the FDEP regulates dredging, filling, and construction in 

wetlands through its ERP. The FDEP also ensures that activities in uplands, wetlands, or 

other surface waters do not degrade water quality or the habitat for wetland dependant 

wildlife. FGS submitted two ERP applications to the FDEP on July 30, 2007 - one for 

the storage facility site and one for the pipeline. On May 19, 2008, the FDEP issued the 

final ERP for the storage facility site; the pipeline ERP application is still under review. 

Martin County’s Land Development Regulations restrict impacts to wetlands and require 

maintenance of a 50- to 75-foot buffer around wetland boundaries and additional 

construction setbacks. The Martin County Environmental Division of the Growth 

Management Department is responsible for reviewing wetland permit applications for 

consistency with County environmental policies and regulations. 

Wetland delineations were conducted for the LNG storage facility site in 2005 and along 

the pipeline corridor in 2007 in accordance with the requirements of the COE’s Wetland 

Delineation Manual (Environmental Laboratory, 1987). The COE is responsible for 

approving wetland delineations and determining each wetland’s jurisdictional status. 

FGS submitted a written request to the COE in July 2007 for its jurisdictional 

determination, but the COE has not yet formally responded. The COE indicated that 

most of the Project wetlands are isolated and not subject to COE jurisdiction; however, 

one drainage ditch near to the storage facility site is hydrologically connected to “waters 

of the United States” and would likely be subject to COE jurisdiction (Reusch, 2008). 

FDEP reviewed the wetland delineation as part of the ERP Permit (approved March 19, 

2008) and no state jurisdictional wetlands were identified. 

There are 27.95 acres of wetlands and waterbodies on the LNG storage facility site and 

3.91 acres along the pipeline corridor (see Table 4.4-1 and Figure 4.4-1). There are no 

wetlands or waterbodies at the temporary workspaces, construction staging area, M&R 

station, or pipeline interconnection sites. The COE has indicated it will make a permit 

decision in the near future. 

None of the wetlands at the Project qualify as high-quality, sensitive, or special-status 

wetlands. These wetlands have generally been degraded by disturbance or colonization 

by exotic and nuisance species. The Florida Natural Areas Inventory database does not 

identify any significant natural communities within the Project area. 
S R- 7 1 0

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P H

P D

P A

Pr o p o s e d 

M & R St ati o n

St or a g e F a cilit y

Sit e

Pr oj e ct 

Pi p eli n e

P Y

P A E

P V

P A A

0. 0 0

0. 5 0

1. 0 0

1. 5 0

2. 0 0

2. 5 0

3. 5 0 3. 0 0

3. 9 5 4. 0 5

4. 1 8

0. 2 5 0. 5 Mil e s

Fi g ur e 4. 4- 1

F G S Pr oj e ct

L o c ati o n of Pr oj e ct W etl a n d s

L e g e n d

R o a d s

Mil e p o st

R ailr o a d

Pr oj e ct W etl a n d s

St or a g e F a cilit y Sit e

Pr oj e ct Pi p eli n e

M & R St ati o n

C o n str u cti o n St a gi n g Ar e a
4.0 – Environmental Analysis 4-20 

LNG Storage Facility 

Construction and operation of the LNG storage facility would not affect any wetlands. 

The wetlands at the storage facility site would be preserved and protected by natural 

buffers required by Martin County. 

FGS has prepared a Preserve Area Management Plan (PAMP) for the storage facility site, 

which is required under the provisions of the Martin County Land Development 

Regulations. This plan was filed by FGS in its certificate application in October 2007 

and can be found on the FERC’s eLibrary website at www.ferc.gov under Docket No. 

CP08-13-000. The PAMP sets aside in perpetuity five “preserve areas,” four of which 

encompass the wetlands and required buffers on the storage facility site. Martin County 

is also requiring enhancement of these undisturbed wetlands within the preserve areas. 

Pipeline and Aboveground Facilities 

Construction of the pipelines would cross 2,620 linear feet of wetlands and would 

temporarily impact 3.91 acres. FGS avoided or minimized impacts to wetlands by 

reducing the nominal construction right-of-way in wetlands to 65-feet-wide, evaluating 

route alternatives to avoid wetland impacts (see Section 3.3.1), using a bore rather than 

open trenching to avoid impacting two wetlands (at MP 1.00 and 1.02), and adoption of 

our Procedures without any proposed variances. FGS’ proposed route would be colocated with or parallel to existing electric transmission lines, pipelines, and roads. No 

route variations have been identified that further avoid or minimize the magnitude of 

wetland impacts proposed by this Project. 

The wetlands affected by the pipeline can generally be described as freshwater marshes 

or wet prairies; no forested wetlands would be impacted. The freshwater marsh habitat, 

which has standing water in part of the year, has a mixture of nuisance/exotic and native 

species, including coastal plain willow, Brazilian pepper, wax myrtle, bushy bluestem, 

Peruvian primrose willow, marsh pennywort, and climbing hempvine. The wet prairies, 

which are not inundated at any time of year, include Peruvian primrose willow; soft rush; 

napier grass; wax myrtle; bushy bluestem; and smartweed. There are also several manmade drainage ditches along the pipeline right-of-way, which, although only carrying 

intermittent flow, are sufficiently wet to support wetland vegetation. The dominant 

vegetative species of the ditch wetlands include the same nuisance/exotic and native 

species commonly found in shallow marshes described above. Table 4.4-2 summarizes 

the location, wetland classification according to the Florida Land Use, Cover, and Farms 

Classification System (FLUCFCS), crossing length, and affected acreage for each 

wetland that would be impacted by pipeline construction. 

Construction of the M&R station, temporary workspaces, and pipeline interconnections 

would not impact any wetlands. There would be no permanent wetland impacts 

associated with pipeline or aboveground facilities operation as all temporarily impacted 

wetlands would be restored. 

Pipeline construction would result in short-term impacts to wetland vegetation, soils, and 

hydrology. Clearing and grading of wetland vegetation could affect surface water flow 

and promote erosion. Failure to properly segregate topsoil and rutting of wetland soils 

from construction equipment could affect the success of post-construction 
4-21 4.0 – Environmental Analysis

reestablishment and natural recruitment of native wetland vegetation. Trenching could 

alter water tables resulting in drier soil conditions, which could inhibit reestablishment of 

wetland vegetation. Section 2.4.2.2 describes the specialized pipeline construction 

procedures, such as the push-pull technique, that FGS would implement based on site 

conditions to minimize wetland impacts. 

Table 4.4-2 

Temporary Wetland Impacts from Pipeline Construction1

MP 

Begin 

MP 

End 

Wetland 

Identification 

Wetland Type 

(FLUCFCS) 

Pipeline 

Crossing 

Length 

(ft) 

Pipeline 

Crossing 

Area (ft2

)

2

 

Pipeline 

Crossing 

Area 

(acres)2

0.35 0.36 Wetland/ Ditch 511 – Ditch 13 845 0.02 

0.60 0.61 Wetland-PA 511 – Ditch 36 2,340 0.05 

0.76 0.86 Wetland-PD 641 - Freshwater Marsh 515 33,475 0.77 

1.00 1.01 Wetland-PH 511 – Ditch 0 (bored) 0 (bored) 0.00 

1.02 1.03 Wetland-PL 511 – Ditch 0 (bored) 0 (bored) 0.00 

1.33 1.39 Wetland-PP 641 - Freshwater Marsh 327 21,255 0.49 

1.43 1.48 Wetland-PR 641 - Freshwater Marsh 248 16,120 0.37 

1.79 1.87 Wetland-PV 641 - Freshwater Marsh 472 30,680 0.70 

1.93 2.01 Wetland-PY 641 - Freshwater Marsh 428 27,820 0.64 

2.07 2.10 Wetland-PAA 641 - Freshwater Marsh 161 10,465 0.24 

2.84 2.86 Wetland-PAE 643 - Wet Prairie 129 8,385 0.19 

3.57 3.59 Wetland-PAI 643 - Wet Prairie 154 10,010 0.23 

3.71 3.73 Wetland-PAJ 643 - Wet Prairie 78 5,070 0.12 

4.03 4.04 Wetland-PAL 511 – Ditch 59 3,835 0.09 

 Total 2,620 170,300 3.91 

Notes 

1

 There would be no Project operational impacts to wetlands. All wetlands would be restored following completion of 

construction. 

2

 Pipeline crossing area assumes a 65-foot-wide construction area.

FGS would follow our Procedures to limit wetland impacts during construction. FGS 

would use the minimum construction equipment necessary within wetlands for clearing, 

trench excavation, pipe fabrication and installation, trench backfilling, and restoration 

activities. If standing water or saturated soil conditions are present, or if construction 

equipment caused ruts or mixing of topsoil and subsoil, construction equipment operating 

in wetlands would be further limited to the use of low-ground-pressure equipment or 

normal equipment operating from timber riprap or prefabricated equipment mats. 

Within the construction right-of-way, FGS would leave existing root systems intact 

where possible; segregate wetland topsoil from the subsoil during trenching and store in 

separate piles; minimize the amount of time that topsoil is segregated; backfill the soil 

material in the proper order; and install erosion control devices to minimize sediment 

flow into the wetland and adjoining wetlands. Trench breakers would be placed in the 

trench at the base of slopes near the wetland boundaries prior to backfilling to prevent 

draining of the wetland along the trench line. No upland soil or fill material would be 

imported into the wetland. 
4.0 – Environmental Analysis 4-22 

FGS would also minimize impacts to nearby wetlands by implementing the measures 

identified in our Procedures such as clearly marking wetland boundaries and buffers in 

the field, using sediment barriers to prevent sediment flow into a wetland, and prohibiting 

the storage of hazardous materials and refueling within 100 feet of a wetland. 

FGS would restore all pre-construction contours immediately after pipeline installation is 

complete and restore wetland areas in accordance with our Procedures. The requirements 

for wetland restoration measures identified in our Procedures include: 

• consulting with appropriate state land management agencies regarding 

measures for re-establishing native species; 

• prohibiting the use of herbicides or pesticides within 100 feet of a 

wetland, except as allowed by the appropriate agencies; 

• prohibiting application of lime, fertilizer, or mulch in wetlands; and 

• monitoring the success of wetland vegetation annually for the first 

three years after construction or until wetland revegetation is 

considered successful. 

The types of wetlands impacted by Project pipeline construction (e.g., freshwater marshes 

and ditches) typically recover more quickly than other wetland types (e.g., forested 

wetlands) and should reestablish in one or two growing seasons. Revegetation would be 

considered successful if the cover of herbaceous and/or woody species is at least 80 

percent of the type, density, and distribution of the vegetation in adjacent wetland areas 

that were not disturbed by construction. The key challenge is to prevent the 

reestablishment of invasive and exotic species. Construction across these wetlands may 

provide the invasive plant species in the adjacent areas and seed stock an opportunity to 

further colonize and degrade the wetlands in the Project area. However, FGS proposes to 

re-seed the wetlands with annual ryegrass to quickly establish a short-lived vegetative 

cover, allowing the wetland's native seed and rhizomes (contained in the topsoil) to 

reestablish dominance over time. Further, FGS would remove invasive species found 

during pipeline maintenance inspections. We believe that the implementation of 

measures detailed in the Procedures and FGS’s PAMP would minimize the opportunity 

for the introduction of invasive species. 

4.4.2 Upland Vegetation 

The FGS Project is located in the Outer Coastal Plain Mixed Province of the Atlantic and 

Gulf Coastal Plains Ecosystem, comprised of the flat and irregular Atlantic and Gulf 

coastal plains. Most upland areas along the Atlantic coast in this Province are covered by 

sub-climax pine forest with an understory of grasses and sedges called savannas. 

Project lands and rights-of-way total 176.40 acres of uplands (see Table 4.4.1). Upland 

cover types that occur in the Project area are summarized in Table 4.4-3. The Florida 

Natural Areas Inventory identifies no significant natural communities within the Project 

area. FGS submitted letters to the FWS and Florida Fish and Wildlife Conservation 

Commission (FFWCC) requesting information on any significant habitats or vegetative 

communities within the Project area. Information received from these agencies, together 
4-23 4.0 – Environmental Analysis

with subsequent biological field surveys, indicates that no vegetative communities of 

special concern or value occur in the Project area. 

Overall, Project construction would temporarily disturb up to 123.12 acres of upland 

cover types (127.03 total impacts - 3.91 acres of wetland impacts). Project operations 

would permanently affect 78.40 acres of upland cover types, which includes the 

permanent loss of 56.07 acres of habitat for the LNG storage facility, M&R station, and 

interconnections, and the maintenance of 22.33 acres of permanent pipeline right-of-way 

in low growth (e.g., shrub and herbaceous) vegetation. The disturbed uplands not 

permanently affected by the Project would be restored. 

Table 4.4-3 

Upland Vegetative Cover Types Occurring in the Project Area 

Vegetative 

Cover Type 

(FLUCFCS) 

Code 

General Description of Cover Type a/ Common Species b/

Dry Prairie 

(310) 

Rangeland with upland prairie grasses 

that occur on non-hydric soils but may be 

occasionally inundated by water. 

Wiregrass, saw palmetto. 

Palmetto Prairie 

(321) 

Rangeland where saw palmetto is the 

most dominant vegetation. This cover 

type is usually found on seldom-flooded 

dry sand areas. These treeless areas 

are often similar to the pine flatwoods. 

Saw palmetto and slash pine, with 

subdominants including greenbriar; 

American beautyberry; old-world climbing 

fern; Brazilian pepper, gallberry; napier 

grass; melaleuca; bluestem grass; winged 

sumac; muscadine grape; dogfennel; 

wiregrass; and sand live oak. 

Pine Flatwoods 

(411) 

Common upland coniferous forest 

dominated by either slash pine or 

longleaf pine. 

Slash pine; saw palmetto; cabbage palm; 

laurel oak; live oak; Brazilian pepper; wax 

myrtle; gallberry; greenbriar; bluestem 

grass; muscadine grape; bracken fern; 

dogfennel. 

Brazilian Pepper 

(422) 

Upland hardwood forest community 

dominated by Brazilian pepper. 

Brazilian pepper 

Hardwood/ 

Conifer Mixed 

Forest (434) 

Upland forest community where neither 

upland conifers nor hardwoods achieve 

canopy dominance. 

Co-dominant species include loblolly pine; 

slash pine; laurel oak; live oak; and 

cabbage palm in the canopy. Saw 

palmetto dominates the ground cover. 

Australian Pine 

(437) 

Upland hardwood forest community 

dominated by Australian pine. 

Nearby monotypic stand of Australian 

pine. Associate species are limited to 

Brazilian pepper along the periphery of 

the Australian pine monoculture. 

Disturbed Open 

Lands (740) 

Areas changed primarily due to human 

activities other than mining. 

Slash pine; cabbage palm; live oak; 

Spanish needle; Bahia grass; torpedo 

grass; goosegrass; smutgrass; wiregrass. 

Electrical 

Transmission 

Line (832) 

Right-of-ways typically maintained in an 

herbaceous and/or shrubby ground 

cover. 

Bahia grass; bushy bluestem; flatsedge; 

marsh pennywort; groundsel tree; 

Brazilian pepper. 

Sources: 

a/ Florida Land Use, Cover and Forms Classification System (FDOT, 1999) 

b/ Resource Report 3 (Golder, 2007) 
4.0 – Environmental Analysis 4-24 

Table 4.4-4 

Vegetative Communities Potentially Affected by the Project

Proposed Facility 

Cover Type 

(FLUCFCS) 

Crossing 

Length 

(miles) 

 Existing 

 Conditions 

 (acres) 

Area Affected 

by 

Construction1

(acres) 

Area 

Affected by 

Operation2

(acres) 

Pine Flatwoods (411) n/a 12.57 2.46 2.46 

Brazilian Pepper (422) n/a 12.00 12.00 12.00 

Hardwood/Coniferous Mixed 

(434) n/a 2.51 1.29 1.29 

Australian Pine (437) n/a 5.24 5.24 5.24 

Ditch (511) n/a 4.61 0.00 0.00 

Reservoirs less than 10 acres 

(534) n/a 9.26 0.00 0.00 

Mixed Wetland Hardwoods 

(617) n/a 0.57 0.00 0.00 

Exotic Wetland Hardwoods 

(619) n/a 4.03 0.00 0.00 

Cypress/Exotic Wetland 

Hardwoods (621/619) n/a 0.49 0.00 0.00 

Freshwater Marsh (641) n/a 8.99 0.00 0.00 

Disturbed Lands (740) n/a 75.70 33.96 31.48 

Railroads (812) n/a 0.35 0.19 0.19 

LNG Storage 

Facility 

Roads (814) n/a 0.49 0.44 0.44 

Subtotal LNG Storage Facility n/a 136.813 55.583 53.10 

Dry Prairie (320) 0.93 11.33 11.33 5.66 

Palmetto Prairie (321) 0.33 3.97 3.97 1.98 

Pine Flatwoods (411) 1.23 14.90 14.90 7.45 

Brazilian Pepper (422) 0.12 1.43 1.43 0.72 

Hardwood/Coniferous Mixed 

(434) 0.15 1.84 1.84 0.92 

Ditch (511) 0.02 0.16 0.16 0.00 

Freshwater Marsh (641) 0.41 3.21 3.21 0.00 

Wet Prairie (643) 0.07 0.54 0.54 0.00 

Disturbed Open Land (740) 0.52 6.37 6.37 3.19 

Electrical Power Facility (831) 0.09 1.11 1.11 0.56 

Pipeline Corridor 

Transmission Lines (832) 0.31 3.71 3.71 1.85 

 

Dry Prairie (320) n/a 2.51 2.51 0.00 

Palmetto Prairie (321) n/a 1.58 1.58 0.00 

Pine Flatwoods (411) n/a 3.13 3.13 0.00 

Disturbed Open Land (740) n/a 0.83 0.83 0.00 

Spoil Areas (743) n/a 0.15 0.15 0.00 

Temporary Work 

Spaces* 

Transmission Lines (832) n/a 1.21 1.21 0.00 

 

Dry Prairie (320) n/a 0.78 0.78 0.78 

Pine Flatwoods (411) n/a 0.58 0.58 0.58 

M&R Station Site 

Hardwood/Coniferous Mixed 

(434) n/a 1.39 1.39 1.39 

 

Interconnections 

(0.11 acres each) Dry Prairie (320) n/a 0.22 0.22 0.22 

 

Palmetto Prairie (321) n/a 2.89 2.89 0.00 

Pine Flatwoods (411) n/a 6.99 6.99 0.00 

Construction 

Staging Area 

Poultry Feeding Operations 

(232) n/a 0.62 0.62 0.00 

Subtotal Pipeline Staging Area, and 

Aboveground Facilities 4.18 71.45 71.45 25.30 

 

GRAND TOTAL 4.18 208.26 127.03 78.40 

Notes: n/a = not applicable 

* Where combined acreage and crossing lengths for two cover types in a single workspace were given by the applicant, the data 

was split evenly among cover types. 

1

 Acres affected by construction consist of the LNG storage facility construction areas, pipeline construction right-of-way, including 

extra work areas. 

2

 Areas affected by operation include the LNG storage facility, M&R stations, interconnections, and the permanent right-of-way 

3

 This reflects the net acreage of the LNG storage facility site excluding the 7.82 acres affected by pipeline construction. 
4-25 4.0 – Environmental Analysis

LNG Storage Facility Site

The LNG storage facility site is a previously-disturbed industrial area that does not 

contain any unique vegetative communities or support significant wildlife habitat. 

Construction of the LNG storage facility would disturb 55.58 acres, or 41 percent, of the 

net 136.81-acre site. Most of the affected area, 34.59 acres, is previously disturbed land, 

railroads, and roads. FGS would also remove 17.24 acres of Australian pine and 

Brazilian pepper as required by Martin County because they are invasive, exotic species. 

The only impacts to natural habitat would be the loss of 2.46 acres of pine flatwoods and 

1.29 acres of mixed hardwood/coniferous forest. 

Storage facility operations would result in the permanent conversion of 53.10 acres, of 

which only 3.75 acres would be natural vegetation. In addition, one existing stormwater 

pond would be expanded by 2.48 acres and is included in the remaining 83.71 acres of 

the site remain as open space or used as spray irrigation fields as part of the on-going site 

remediation. 

Pipeline, Construction Staging Area, and Associated Aboveground Facilities 

The pipeline corridor and aboveground facilities are generally adjacent to or co-located 

with maintained powerline, pipeline, and road rights-of-way. The Tampa Farms property 

is located adjacent to the pipeline corridor at approximately MP 1.60 and would be used 

as a temporary pipe storage and construction staging area. Access is already available via 

existing roads. This area is disturbed and was formerly used as a mulch yard, but is not 

currently in use. The existing vegetation at the construction staging area would be 

cleared, the topsoil stockpiled, and the site covered with gravel. Construction of the 

pipeline, construction staging area, and associated aboveground facilities would affect 

71.45 acres, of which 28.83 acres would be natural forest. 

Pipeline facility operations would result in the permanent loss of 2.97 acres of natural 

vegetation for the M&R station and the pipeline interconnections, and the maintenance of 

22.33 acres of permanent right-of-way as low-growth (e.g., shrub or herbaceous) 

vegetation. At the completion of construction, FGS would remove the gravel, replace the 

stockpiled topsoil, and revegetate the area. 

Mitigation Measures 

Most (75 percent) of the Project impacts affect prairie, disturbed lands, marshes, or areas 

dominated by invasive/exotic species, the effects of which would be short-term as these 

communities would typically return to their herbaceous or shrub status within 1 to 2 

seasons following construction. Impacts to the forested cover types within the temporary 

construction right-of-way would be longer term, taking up to 30 years or more to recover. 

To minimize construction-related effects, FGS has agreed to adopt our Plan with no 

modifications. The intent of our Plan is to identify baseline mitigation measures to 

minimize erosion and enhance revegetation in upland areas. Our Plan requires all 

temporarily disturbed areas to be restored to pre-construction contours and revegetated 

upon completion of construction. The Martin County Field Operations Department 

(2007) states that sodding with Bahia grass, in lieu of seeding, is commonly used to 

vegetate disturbed areas in Martin County. In addition, FGS consulted with the NRCS, 
4.0 – Environmental Analysis 4-26 

which indicated that there is no state or county requirements regarding revegetation, but 

recommended a seed mixture of Bahia or Bermuda grass and suggested Pensacola or 

Argentine sod in areas sensitive to erosion. 

The PAMP that FGS prepared for Martin County identifies the location and use of 

preserve areas; surveying, marking and barricading requirements; restoration and 

maintenance activities (including exotic species removal and revegetation); measures for 

protecting listed species; and monitoring, maintenance, reporting, and inspections 

requirements. Implementation of the PAMP would ensure cutting or removal of 

vegetation would be minimized. We received a comment from the EPA on our draft EIS 

recommending that rights-of-way maintenance avoid the use of herbicides, particularly 

aerial applications, to avoid overspray and opportunities for invasives to establish. EPA 

also recommended that any herbicide use be limited to EPA-registered products, applied 

by trained personnel according to label directions. To ensure appropriate application of 

herbicides as a management tool, and to minimize potential detrimental effects to the 

environment noted by the EPA, we recommend that:

• FGS should develop a Standard Operating Procedure for 

Herbicide Use that meets EPA requirements.

With the implementation of our Plan and recommendation in conjunction with the 

requirements of the PAMP, impacts to upland vegetation would be minimized and minor 

in nature. 

Exotic or Invasive Plant Species 

Invasive and exotic pest plants are a threat to Florida’s natural areas. According to the 

Florida Exotic Pest Plant Council (2007), approximately 31 percent of the plant species 

known to occur in Florida outside cultivation are introduced. Exotic plants are 

introduced accidentally through shipping materials or deliberately for ornamental or 

commercial purposes. Invasive and exotic pest plants often lack the natural enemies that 

control their growth in their home range, allowing them to spread easily into Florida’s 

native plant communities. Exotic plants can cause a reduction in biodiversity; loss of 

habitat and food sources for native insects, birds, and other wildlife; and changes to 

natural ecological systems. 

Several of the upland vegetative communities listed in Table 4.4-3 contain exotic or 

invasive plant species. The primary invasive, exotic plants in the upland communities are 

Australian pine and Brazilian pepper and other herbaceous species. Where present at the 

Project, Australian pine and Brazilian pepper would be removed to promote conversion 

to native cover types in accordance with the PAMP. 

4.5 WILDLIFE AND AQUATIC SPECIES 

4.5.1 Wildlife 

Game and non-game wildlife species are regulated and protected under various federal 

laws, including the Fish and Wildlife Conservation Act of 1980 (16 U.S.C. §§ 2901-
4-27 4.0 – Environmental Analysis

2911), Fish and Wildlife Coordination Act of 1958, and the ESA. The FFWCC also 

administers programs at the state level for the protection of wildlife species. 

4.5.1.1 Existing Conditions 

Habitats at the Project, which include upland forests, open lands and prairies, wetlands, 

drainage ditches, and open water provide cover and forage for a variety of wildlife. Most 

of the habitat suitable for wildlife occurs along the pipeline corridor and at the M&R 

station. The LNG storage facility site and the construction staging area have been 

disturbed and do not provide significant habitat for wildlife, although the area is used by 

a variety of common avian and mammalian species despite the historical disturbance and 

lack of native habitat. The Project area is not located in any federal, state, or private 

wildlife managed areas. Wildlife observed during field surveys at the Project site in 

December 2006 and January 2007 are discussed below by community type. 

Upland Forests 

The local upland forested communities include pine flatwood and mixed 

hardwood/coniferous forest. The forested canopy can be used for nesting by birds 

including mockingbird, morning dove, turkey vulture, cardinal, common yellowthroat, 

red-shouldered hawk, and white-eyed vireo. A variety of shrub and herbaceous plant 

species in the understory of the upland forests provide significant cover and forage for a 

variety of wildlife species including raccoon, eastern cottontail rabbit, bobcat, coyote, 

white-tailed deer, and eastern diamond back rattlesnake. 

Open Lands and Prairies 

The open lands in the pipeline corridor and M&R station include the cleared/ maintained 

transmission line rights-of-way (portions of which are cattle pasture and disturbed open 

land associated with the former industrial facility), palmetto prairie, and dry prairie. 

These habitats provide cover and forage for avian and wildlife species including 

loggerhead shrike, ground dove, common nighthawk, American robin, feral hog, raccoon, 

armadillo, coyote, white-tailed deer, and black racer. The existing transmission line 

rights-of-way generally provide low to moderate quality wildlife habitat except for 

palmetto prairie, which provides quality habitat for typical pine flatwood species such as 

the gopher tortoise. 

Unlike most other grasslands in the southeastern United States, Florida dry prairie 

harbors numerous endemic vertebrates (FWS, 1991). Several rare avian taxa are nearendemic to the dry prairie region of south-central Florida. Both breeding and seasonal 

migrants use dry prairies extensively. The dry prairie habitat along the pipeline corridor 

is within or adjacent to the existing transmission line corridor, which is periodically 

mowed. The improved pasture, with herbaceous species such as Bahia grass, provides 

grazing habitat for species such as white-tailed deer. The dry prairie at the M&R station 

abuts cleared railroad and road right-of-way. 

Forested, Scrub-Shrub, and Emergent Wetlands 

There are several isolated freshwater marshes located along the pipeline corridor. These 

emergent wetlands are characterized by erect, rooted, herbaceous plants used for feeding, 
4.0 – Environmental Analysis 4-28 

potential nesting, and during migration by avian and wildlife species including green 

heron, great egret, northern harrier, eastern cottontail rabbit, and raccoon. These 

emergent, isolated wetlands may also be used as breeding sites for a variety of 

amphibians including Florida cooter, green tree frog, pig frog, and water moccasin. 

Open Water and Ditches 

The LNG storage facility site and pipeline corridor contain several minor waterbodies. 

The storage facility site has three stormwater ponds totaling 9.26 acres that support a 

fringe of vegetation and provide habitat for wading birds and other aquatic species such 

as moorhen, anhinga, green heron, black-crowned night heron, raccoon, green tree frog, 

and water moccasin. An American alligator inhabits at least one of the ponds on the 

storage facility site. The five drainage ditches present at the Project are all small and 

intermittent, only carrying flows during wet periods or immediately after storm events. 

Although only intermittent, these ditches provide suitable foraging habitat for a variety of 

wading birds, including the endangered wood stork. 

Migratory Birds 

The Migratory Bird Treaty Act regulates taking of or impacts to migratory birds, 

including their nests. The FWS estimates that there are approximately 398 species of 

migratory birds in South Florida. Migratory birds would be expected to occur at least as 

transients in the Project area throughout most of the year. In general, construction and 

maintenance of the pipeline right-of-way would benefit some species through the creation 

and maintenance of edge habitats; however, other species can be adversely affected, 

especially if nesting activities are disturbed by vegetative clearing activities associated 

with construction and maintenance of the Project. 

Colonial Nesting Waterbirds 

Colonial nesting waterbirds is a collective term used to refer to a variety of bird species 

that obtain all or most of their food from aquatic environments and gather in large 

colonies, or rookeries, during the nesting season (FWS, 2002). No rookeries have been 

identified by the FWS (2007), FFWCC (2007), or Florida Natural Areas Inventory (2007) 

sufficiently near to the Project area that warrants timing restrictions for construction 

during the nesting period. Foraging habitat provided by wetlands and ditches affected by 

construction would be restored in accordance with our Procedures. No long-term impacts 

to colonial nesting birds are expected. 

4.5.1.2 Impacts and Mitigation 

The Project would disturb 127.03 acres of potential upland and wetland wildlife habitat 

(see Table 4.4-4). The extent and duration of impacts to wildlife and their habitats 

resulting from construction and operation of the Project would depend on the species 

present in each habitat type and their individual life history requirements. Potential 

impacts to wildlife habitat from each component of the Project are discussed below. 

LNG Storage Facility Site 

The LNG storage facility construction would temporarily disturb 55.58 acres and 

operation would result in the permanent loss of 53.10 acres of potential wildlife habitat. 
4-29 4.0 – Environmental Analysis

The storage facility site, however, does not contain significant wildlife habitat. The site 

is an industrial, fenced property included in the Superfund Program with ongoing 

remediation activities. Most (93 percent) of the LNG storage facility construction would 

occur in previously disturbed, sparsely vegetated open lands or areas dominated by 

invasive species. 

No adverse impacts to wildlife are anticipated as a result of construction and operation of 

the LNG storage facility. Noise effects on wildlife from construction would be 

temporary and noise levels from facility operations would be within acceptable FERC 

and state levels. Existing wildlife in the area are acclimated to noise already generated by 

the adjacent industrial facilities, SR 710, and the CSX railroad. 

Pipeline Facilities and Construction Staging Area 

Pipeline facility construction would result in the clearing of 71.45 acres of vegetation that 

provides habitat for wildlife. Pipeline operations would result in the permanent loss of 

2.97 acres of vegetation for the M&R station and pipeline interconnections and the 

permanent maintenance of 22.33 acres of pipeline right-of-way as low growth vegetation. 

FGS minimized these impacts by locating the pipeline route adjacent to existing 

maintained utility rights-of-way and roads, avoiding the creation of new cleared corridors 

through forest tracts. FGS also avoided all forested wetlands. 

The clearing of vegetation for the pipeline facilities and construction staging area would 

reduce cover, nesting, and foraging for some wildlife until construction is complete and 

vegetation re-established along the right-of-way. During construction, more mobile 

species would be temporarily displaced from the construction right-of-way and 

surrounding areas to similar habitats nearby. Some wildlife species disturbed or 

displaced by construction may be able to return to adjacent, undisturbed habitats soon 

after completion of construction. Less mobile species, such as small mammals, reptiles, 

amphibians, and birds nesting in the rights-of-way, may be affected by construction 

activities due to direct mortality or permanent displacement, potentially affecting 

reproduction, recruitment, and survival of these individuals. Regardless of mobility, 

some wildlife species would be affected by the loss of cover, nesting, and foraging 

habitat. Similar effects, although much less extensive, would result from routine 

maintenance of vegetation along the permanent right-of-way. 

Pipeline facility and construction staging area construction would clear 28.83 acres of 

forest (excluding areas dominated by the invasive Brazilian Pepper), of which 1.97 acres 

at the M&R station would be permanently impacted; approximately 16.74 acres within 

the permanent right-of-way would be permanently converted to low growth (shrub or 

herbaceous) vegetation; and 10.12 acres within temporary workspaces and construction 

staging area would be allowed to revert to forest. Effects to wildlife using forest habitats 

would be more substantial and longer-term (up to 30 years) than that to wildlife 

inhabiting other habitat types, as vegetative strata in those areas would undergo a more 

marked change. 

Non-forested habitats that would be affected by construction and operation of the Project 

include open lands, palmetto prairie, dry prairie, scrub-shrub and emergent wetlands, and 

vegetated ditches. The impact on these habitats and associated wildlife species would be 
4.0 – Environmental Analysis 4-30 

relatively minor and either temporary or short-term. Due to the short duration of pipeline 

installation and the vegetative restoration measures included in our Plan, these areas 

would generally be restored within three to five years after construction for scrub-shrub 

habitats and one to two years for the other habitats. FGS proposes to re-seed the 

improved pastureland with Bahia grass. 

FGS would minimize impacts to wildlife habitats through the implementation of our Plan. 

FGS would not conduct routine vegetative maintenance of the pipeline right-of-way more 

frequently than once every three years. Routine vegetative maintenance clearing would 

not occur between April 15 and August 1 in any year to minimize the potential for 

Project-related disturbances of migratory bird nesting periods. 

4.5.2 Aquatic Resources 

Game and non-game fish species are regulated and protected under various federal laws, 

including the Fish and Wildlife Act of 1980 (16 USC §§ 2901-2911) and the Fish and 

Wildlife Coordination Act of 1958 (16 USC §§ 661 et seq.). The Project would also be 

reviewed under Florida’s state regulatory programs. 

Aquatic habitats affected by the Project are limited to the St. Lucie Canal, which would 

be used by FGS as a source of hydrostatic test water, three stormwater ponds on the LNG 

storage facility site, and five drainage ditches crossed by the proposed pipeline. No 

fisheries of special concern, Essential Fish Habitat, commercial fisheries, Outstanding 

Florida Waters, or Aquatic Preserves are located in the Project area (Golder, 2007). 

LNG Storage Facility 

The three stormwater management ponds on the LNG storage facility site provide habitat 

for a variety of common forge fish, but recreational fishing is prohibited as a condition of 

the site’s remediation plan. The southwestern pond would be enlarged by 2.48 acres to 

meet State and local stormwater management requirements. Temporary construction 

impacts are likely to be minor and of short duration. Potential impacts to alligators that 

may inhabit the ponds are discussed in Section 4.6. 

Pipelines, Construction Staging Area, and Associated Aboveground Facilities 

The pipeline would cross five intermittent drainage ditches affecting 0.16 acres of ditch 

wetlands. The drainage ditches contain water seasonally or during rain events and do not 

provide any significant habitat for fish. The ephemeral hydroperiod associated with these 

ditches and wetlands limit fish communities to common forage fishes such as 

mosquitofish, least killifish, and small sunfish. The ditches and wetlands are not 

considered critical habitat for any native or game fish species and do not provide habitat 

for recreationally important fish species. 

Potential impacts to water quality and associated aquatic habitats would include 

sedimentation, turbidity, and physical disturbance of vegetative cover. These effects 

would be minor and temporary. FGS proposes to construct the Project in accordance 

with our Procedures, ensuring that the physical characteristics of the drainage ditches that 

may provide aquatic habitat are restored to pre-Project conditions. 
4-31 4.0 – Environmental Analysis

Hydrotesting 

FGS proposes to use the St. Lucie Canal as the source of water to hydrotest the LNG 

storage tanks and pipelines. The hydrotesting would withdraw water at approximately 

1,500 gpm for several weeks. FGS would use an existing permitted irrigation intake 

structure, which would be screened to minimize the impingement or entrainment of fish 

per our Procedures. The withdrawal rate would be less than 0.1 percent of annual 

average flow in the St. Lucie Canal. FGS would not use any biocides or other water 

additives and, after completion of the hydrotesting, would return the water to the St. 

Lucie Canal at non-erosive velocities. Therefore, the hydrotest water withdrawal would 

have no significant adverse effect on the fishery or aquatic resources of the St. Lucie 

Canal. 

4.6 THREATENED, ENDANGERED, AND SPECIAL STATUS SPECIES 

4.6.1 Federally Listed Threatened and Endangered Species 

In order to comply with Section 7 of the ESA, FGS, acting as our non-federal 

representative, consulted with the FWS regarding the presence of federally listed 

threatened and endangered species and their designated critical habitats within the Project 

area. The FWS (FWS, 2007) reported that the Project area is located within known 

ranges of the wood stork (Mycteria americana) and Audubon’s crested caracara 

(Polyborus plancus auduboni). No other federally listed species were identified in the 

FWS database as occurring in the Project area. Appendix D includes copies of 

correspondence between FGS and the FWS. 

Critical habitat is defined in the ESA and identified in 50 CFR 17.95 (fish and wildlife) 

and 50 CFR 17.96 (plants). It refers to specific geographic areas essential to the 

conservation of a threatened or endangered species that may require special management 

consideration or protection. Federal agencies that undertake, fund, or permit activities 

that may affect critical habitat are required to consult with the FWS to ensure such 

actions do not adversely modify or destroy designated critical habitat. The Project area is 

located outside any federally-designated critical habitat. The FWS has established 

critical habitat in Martin County for Johnson’s seagrass (Halophila johnsonii), piping 

plover (Charadrius melodus), and West Indian manatee (Trichechus manatus), but the 

critical habitats for these species involve marine, coastal, and estuarine habitats, which do 

not occur in the Project area. 

FGS conducted field reconnaissance of the Project area in December 2006 and January 

2007. The wood stork and American alligator (Alligator mississippiensis), both federally 

listed species, were observed during the surveys. No other federally-listed species, 

including the Audubon’s crested caracara, were observed during these field surveys. 

FGS conducted another field reconnaissance of the site and pipeline corridor with the 

FFWCC in June 2007 and did not observe any listed species. Although not identified or 

observed, suitable habitat (i.e., gopher tortoise burrows) for another federally-listed 

species, the Eastern indigo snake (Drymarchon corais couperi) was observed at the LNG 

storage facility site and therefore included in our analysis. 
4.0 – Environmental Analysis 4-32 

These species and their management status are listed in Table 4.6-1. The preferred 

habitats and potential for occurrence of these species, as well as our assessment of 

potential Project effects, are discussed below. 

Table 4.6-1 

Federally-Listed Species Potentially Occurring in the Project Area 

Species 

Federal 

Status 

Florida 

Status Preferred Habitat 

Wood stork 

(Mycteria Americana) 

E E Freshwater and brackish wetlands, primarily 

nesting in cypress or mangrove swamps and 

feeding in open water habitats that support small 

fish. Optimal feeding sites include depressions 

where fish become concentrated during periods of 

falling water levels. 

Audubon’s crested caracara 

(Polyborus plancus audubonii) 

T T Cabbage palms surrounded by open habitats, 

such as improved pasture, with low ground cover 

and a low density of tall or shrubby vegetation. 

American alligator 

(Alligator mississippiensis) 

T (S/A) SC Swamps and marshes 

Eastern indigo snake 

(Drymarchon corais couperi) 

T T Variety of habitats, including pine flatwoods, dry 

prairies, and freshwater marshes. 

Sources: FWS (2007), Florida Natural Features Inventory (2001) 

Definitions: E = endangered, T = threatened, S/A = similarity of appearance, SC = species of concern 

4.6.1.1 Species Descriptions 

Wood Stork 

The wood stork is federally and state-listed as endangered, which classifies it as in danger 

of extinction throughout all or a significant portion of its range. According to the FWS 

(2007a), the Project area is located within the core foraging area (CFA) of two active 

wood stork breeding colonies. The CFA extends up to 18.6 miles from the location of the 

breeding colony. Wood storks were observed flying over the LNG storage facility site 

and pipeline corridor in December 2006 and January 2007. 

The wood stork is a large, long-legged wading bird, about 50 inches tall, with a wingspan 

of 60 to 65 inches. The plumage is white except for black primaries, secondaries, and a 

short tail with greenish and purplish sheen. The head and neck are unfeathered, scaly, 

and dark gray in color. The bill is black, long and thick at the base, and slightly decurved. 

Immature birds are dingy gray and have a yellowish bill. Sexes are similar in appearance. 

Wood storks are birds of freshwater and brackish wetlands, primarily nesting in cypress 

or mangrove swamps. Nesting periods vary geographically. In South Florida, wood 

storks lay eggs as early as October and fledge in February or March. Nests are frequently 

located in the upper branches of large cypress trees or in mangroves on islands. Several 

nests are usually located in each tree. Wood storks have also nested in man-made 

structures. Storks lay two to five eggs and average two fledglings per successful nest 

under good conditions. 
4-33 4.0 – Environmental Analysis

Wood storks feed in freshwater marshes, narrow tidal creeks, or flooded tidal pools. 

Particularly attractive feeding sites are depressions in marshes or swamps where fish 

become concentrated during periods of falling water levels. Wood storks eat small fish, 

especially topminnows and sunfish. They capture their prey by grope-feeding (i.e., 

capturing food by feel). Feeding often occurs in water six to 10 inches deep, where a 

stork probes with the bill partly open. 

The Project is located outside known breeding colony locations and would not impact 

cypress swamp or mangrove communities. The construction of the Project would involve 

temporary impacts to non-forested wetlands and drainage ditches in the proposed pipeline 

construction right-of-way. The FWS believes that the on-site ditches provide suitable 

foraging habitat for wood storks because the ditches can concentrate prey. To minimize 

adverse effects to the wood stork, the FWS recommends that FGS replace all lost 

foraging habitat within the CFA due to the proposed action so no net loss of foraging 

habitat occurs (Wrublik, 2007). 

FGS proposes to restore wetlands and drainage ditches affected by construction in 

accordance with our Procedures, which limits the duration of construction to 24 hours 

and requires re-establishing ground surface contours and vegetative cover. These 

measures would ensure that permanent wetland loss would not occur within the CFA and 

that the hydroperiod of these wetlands are returned to pre-Project conditions. For these 

reasons, we have determined that the Project is not likely to adversely affect the wood 

stork. 

Audubon’s Crested Caracara 

The Audubon’s crested caracara is federally and state-listed as threatened, which 

identifies it as likely to become endangered within the foreseeable future throughout all 

or a significant portion of its range. The region of greatest abundance for the Florida 

population is a five-county area north and west of Lake Okeechobee (Sprunt, 1954; 

Layne in Kale, 1978; Layne, 1985). The FWS (2007) identified the Project area in 

Martin County, east of Lake Okeechobee, to be within the caracara’s geographic range. 

The caracara is 21 to 23 inches in length and has a wingspread of about 48 inches. It has 

long yellow legs and a massive bluish bill. Sexes are similarly plumaged; younger birds 

are browner than adults. The caracara is an opportunistic feeder; its diet includes both 

carrion and living prey. Living prey are usually small turtles and turtle eggs. In addition 

to these items, caracaras prey on insects, fish, frogs, lizards, snakes, birds, and small 

mammals. 

Humphrey and Morrison (1997) characterized habitat features and land use patterns at 

active caracara nests in south-central Florida. They found that caracaras prefer to nest in 

cabbage palms surrounded by open habitats with low ground cover and a low density of 

tall or shrubby vegetation. The FWS (2007) notes that nests have occasionally been 

documented in live oak, pines, cypress, Australian pine, saw palmetto, and black gum 

(Nyssa sylvantica) trees. The 1997 study also indicated that there was a strong 

association with improved pastureland. Humprey and Morrison (1997) postulated that 

vegetation height may be related to lower predation rates in lower vegetation, or it may 
4.0 – Environmental Analysis 4-34 

simply be easier for caracaras to walk around and forage in shorter vegetation. Distances 

to roads or other human disturbances may also contribute to nesting success. 

Caracara nests are bulky, loosely woven structures, round or oval in shape and 

approximately two feet in diameter. The breeding peak is from January to March, with 

the usual clutch being two or three eggs. Incubation lasts about 32 days, and the young 

leave the nest at about eight weeks of age. Caracara nests are often used year after year; 

often nesting pairs construct two or three alternate nest trees within the same general 

vicinity (Morrison, 2001). 

The LNG storage facility site is an abandoned industrial facility that does not provide 

suitable nesting or foraging habitat for the caracara. No caracara nests were found on the 

storage facility site during field visits in December 2006 and January 2007. The 

Australian pine and cabbage palm communities on the site have relatively dense 

understory and are located in proximity to disturbed on-site areas as well as the CSX rail 

line and SR 710, which reduces the suitability of these communities for caracara. 

The proposed pipeline corridor and M&R station contain areas of pine flatwoods, 

palmetto prairie, and mixed pine/hardwoods. The pine flatwoods and palmetto prairie 

habitats adjacent to the proposed pipeline corridor do not provide the open understory, 

minimal shrub layer, and cabbage palms favored by the caracara. Although cabbage 

palms are present within the mixed hardwood communities, the canopy and understory 

are densely vegetated, which is not considered suitable caracara foraging or nesting 

habitat. None of these vegetative associations reflect habitat conditions preferred by the 

caracara, and field surveys confirmed that no caracara nests exist in the dry prairie 

communities along the pipeline corridor or at the M&R station. 

In all, no caracara nests or suitable nesting habitat were identified in the Project area. For 

these reasons, we have determined that the Project would have no effect on the caracara. 

American Alligator 

The American alligator (Alligator mississippiensis) is classified by the FWS as threatened 

due to similarity in appearance to the federally-endangered American crocodile 

(Crocodylus acutus). The federal listing of threatened by similarity of appearance offers 

no formal protection from take: the designation simply helps to prevent harvest of other 

similar rare crocodilians by controlling illegal international trade of crocodilian skins. 

The FFWCC does not classify the alligator as threatened or endangered, but as a Species 

of Special Concern. Under Florida law, no person may take, possess, transport, or sell a 

Species of Special Concern. 

Alligators occur in large wetlands throughout the coastal plain of the southeastern United 

States, with the greatest populations occurring in coastal and inland freshwater marshes 

and in lakes and reservoirs with dense stands of emergent vegetation along the shoreline. 

Some also occur in rivers and riverine wetland systems. At the LNG storage facility site, 

a single alligator was observed in one of the stormwater ponds and may possibly inhabit 

other open water habitats and wetlands in the vicinity of this pond. FGS proposes to 

expand one of the ponds to provide increased stormwater management capacity. 

Temporary construction impacts to the American alligator are likely to be minor and of 

short duration. During the expansion of the stormwater pond, it is likely that individual 
4-35 4.0 – Environmental Analysis

alligators within the pond would temporarily relocate to adjacent ponds on-site. 

Expansion of the southwestern stormwater pond acreage would ultimately provide 

additional suitable habitat. FGS indicates it would develop special management 

considerations for alligators and notify construction workers and LNG storage facility 

operators not to harass or unduly disturb any alligators. Therefore, we conclude that the 

Project is not likely to adversely affect the American alligator. 

Eastern Indigo Snake 

The Eastern indigo snake is federally and state-listed as threatened. Eastern indigo 

snakes are the largest non-venomous snake in North America. Individuals up to 104 

inches have been measured, although this species averages between 60 and 74 inches in 

length. It has smooth, shiny scales and a reddish chin and throat. The young are lighter 

in color and have a faint banded pattern. They lay from 5 to 12 eggs in May or June. 

Hatching occurs in August and September. Young indigos may approach two feet in 

length when they hatch. 

Eastern indigo snakes may be found in a variety of habitats throughout most of Florida 

and southern Georgia and are known to use gopher tortoise burrows for egg laying, 

shedding, and protection from dehydration and temperature extremes. Eastern indigo 

snakes need relatively large areas of undeveloped land. They are active nearly yearround in southern Florida, but winter underground farther north. Major threats are habitat 

loss, degradation, and fragmentation, with associated highway mortality. Other threats 

include mortality from gassing of tortoise burrows for rattlesnakes and illegal collection 

as pets. 

Although no Eastern indigo snakes have been observed on the LNG storage facility site 

or along the pipeline corridor, FGS surveys identified several gopher tortoise burrows on 

the proposed storage facility site. FGS would obtain a pre-clearing gopher tortoise 

relocation permit from the FFWCC to excavate any burrows within 25 feet of 

construction areas prior to initiation of construction. In addition, FGS has agreed to 

implement the FWS Standard Protection Measures for the Eastern Indigo Snake. For 

these reasons, we conclude that the Project is not likely to adversely affect the Eastern 

indigo snake. 

4.6.1.2 Conclusion Regarding Federally Listed Threatened and Endangered 

Species 

Four federally-listed threatened or endangered species may occur at the Project. Based 

on our review of FWS species accounts and survey information provided by FGS, we 

have determined that the Project would either have no effect or is not likely to adversely 

affect these species. We have informally consulted with the FWS, which is a cooperating 

agency in the preparation of this EIS, regarding Project effects on these listed species. 

Given the adoption of the Standard Protection Measures for the Eastern Indigo Snake, the 

FWS has concurred that the Project, including the Tampa Farms construction staging area, 

would either have no effect or is not likely to adversely affect federally-listed species 

(June 2, 2008 for the storage facility site and pipeline; and June 27, 2008 for the Tampa 

Farms construction staging area). Consequently, the Commission’s required consultation 

under Section 7 of the ESA is complete. 
4.0 – Environmental Analysis 4-36 

4.6.2 State-listed Species 

Florida’s Endangered Species Protection Act prohibits the intentional wounding or killing 

of any fish or wildlife species designated by the FFWCC as endangered, threatened, or of 

special concern (University of Florida, 2007). This prohibition also extends to the 

intentional destruction of the nests of any such species. The Preservation of Native Flora 

of Florida Act addresses the protection of endangered, threatened, or "commercially 

exploited" plants, which are listed by the Florida Department of Agriculture and 

Consumer Services. The Florida Natural Areas Inventory, which includes all state-listed 

species and important natural communities, did not document any occurrences of listed 

species within the Project area. During field surveys in December 2006 and January 

2007, several state-listed species were observed. These species, their status, and 

preferred habitat are listed in Table 4.6-2 and discussed below. 

Table 4.6-2 

State-Listed Species Potentially Occurring in the Project Area 

Species 

Florida 

Status Preferred Habitat 

Gopher Tortoise 

(Gopherus polyphemus) 

T Dry upland habitats, including dry pine flatwoods. Also 

commonly uses disturbed habitats such as pastures, old 

fields, and road shoulders. 

Little Blue Heron 

(Egretta caerulea) 

SC Forages in freshwater lakes marshes, swamps, and 

streams. Nests in variety of woody vegetation, including 

cabbage palm. Usually breeds in mixed-species colonies 

in flooded vegetation or islands. 

Tricolor Heron 

(Egretta tricolor) 

SC Most nesting colonies occur on mangrove islands or in 

willow thickets in fresh water. Seasonal variations in water 

levels are particularly critical to nesting success. Feeds in 

a variety of permanently and seasonally flooded wetlands, 

mangrove swamps, tidal creeks, ditches, and edges of 

ponds and lakes. 

Snowy Egret 

(Egretta thula) 

SC Feeds in many types of permanently and seasonally 

flooded wetlands, streams, lakes, swamps, and man-made 

impoundments. Nests in both island and coastal wetlands 

with nests placed in many types of woody shrubs, 

especially mangroves and willows. A wide variety of 

wetland types must be available within 5-7 miles to support 

breeding colonies. 

White Ibis 

(Eudocimus albus) 

SC Found in a variety of wetland habitats and streams. Adults 

prefer foraging in freshwater areas when feeding young. 

Nests placed on a variety of trees, shrubs, and vines. 

Florida Sandhill Crane 

(Grus canadensis pratensis) 

T Prairies, freshwater marshes, and pasture lands. Uses 

edges and transition zones between forests and open 

habitats. 

Source: Florida Natural Areas Inventory (2001). 

Definition: E = Endangered, T = threatened, SC = species of special concern 
4-37 4.0 – Environmental Analysis

4.6.2.1 Species Descriptions 

Gopher Tortoise 

Nine active gopher tortoise burrows were observed at the LNG storage facility site, 

primarily in the palmetto prairie habitat at the western edge of the property, although two 

inactive burrows were also observed along the pipeline corridor. Gopher tortoises are 

listed as a threatened species in the State of Florida due to loss of preferred habitat, which 

includes xeric upland areas that are prime parcels for development. 

FGS has proposed mitigation for the gopher tortoise in its PAMP. According to the 

PAMP, a certified environmental professional would supervise clearing in the areas of 

gopher tortoise burrows. Tortoises inhabiting burrows in areas to be developed would be 

captured and relocated following guidelines set forth below. Tortoise burrows may be 

bucket trapped or excavated using methodology approved by the FFWCC and conducted 

by an environmental professional possessing a valid relocation permit. During clearing 

and grubbing operations, equipment operators would be notified of the occurrences of 

gopher burrows on-site and instructed to look for roaming and foraging individuals. 

Should gopher tortoises be seen during the clearing and grubbing, equipment operations 

would be stopped and the gopher tortoises captured and relocated into an approved 

Preserve Area on the LNG storage facility site. Once the tortoise(s) have been safely 

relocated to the Preserve Area and restrained by tortoise fencing, equipment operation 

can resume. 

All gopher tortoise relocation efforts would include trapping of endangered commensal 

species that may live in the burrow. These commensal species include, but are not 

limited to, the Florida mouse, gopher frog, and Eastern indigo snake. 

If the number of tortoises exceeds the carrying capacity of the on-site Preserve Areas, the 

Martin County Environmental Planning Administrator would be notified. In consultation 

with Martin County, the tortoises would be relocated to a suitable and approved off-site 

location. All relocations would be carried out by an environmental professional licensed 

for gopher tortoise relocations. 

Other State-Listed Species 

The observed state-listed wading birds (i.e., little blue heron, tricolor heron, snowy egret, 

and white ibis) occasionally use ditches and wetland habitats on the LNG storage facility 

site and within the pipeline corridor for foraging. Suitable habitat does not exist at the 

Project for nesting. Although pipeline construction would involve open cut trenching 

across four ditches, the trenches would only be open for no more than 24 hours and all of 

the ditches would be immediately restored to pre-construction conditions. There would 

be no permanent adverse operational effects. Therefore, construction and operation of 

the Project would have no effect on state-listed wading bird nesting and negligible effect 

on foraging. 

An individual Florida sandhill crane was observed foraging for insects in an open pasture 

used as a turf farm adjacent to SR 710 and may occasionally use improved pasture and 

wet prairie habitats within the proposed pipeline corridor. Construction of the M&R 

station would permanently convert less than one acre of dry prairie to industrial/ 
4.0 – Environmental Analysis 4-38 

commercial cover type (i.e., gravel). Due to the large acreage of suitable habitat in the 

surrounding area, no adverse impact to the sandhill crane population in the region is 

anticipated. 

4.6.2.2 Conclusion Regarding State-listed Species 

The Project is not likely to have an adverse effect on state-listed and rare species. FGS is 

pursuing approvals from the FWS and FFWCC with respect to its PAMP, which covers 

potential Project-related impacts to listed species and mitigation. The FFWCC conducted 

a site review of the Project and determined that there are no substantive threatened or 

endangered species issues with respect to constructing the LNG storage facility, pipelines, 

or M&R station (Walsh, 2007). 

4.7 LAND USE, RECREATION, AND VISUAL RESOURCES 

4.7.1 Land Use 

In this section we discuss the land requirements for Project construction and operation; 

describe the current use of those lands; and evaluate the significance of Project-related 

impacts to those lands. 

4.7.1.1 Existing Land Use 

The Project is located approximately two miles north of Indiantown, an unincorporated 

area within Martin County. The Project area (e.g., an approximately two-mile radius of 

the LNG storage facility site and pipeline) is dominated by industrial and agri-business 

uses, citrus groves, pastures, some wetlands, and road, railroad, and transmission line 

corridors. 

The proposed LNG storage facility site and most of the surrounding area is zoned for 

industrial use (i.e., M-3 zoning); the Martin County Future Land Use Map also designates 

much of this area for industrial use (Martin County, 2007) (Figure 4.7-1). There are three 

new industrial parks proposed in the Project area, including Venture Park, Indiantown 

Commerce & Technology Park, and Prism Business Park, as well as one mixed-use 

(residential and commercial) development (Table 4.7-1). 

The LNG storage facility site is located on 144.63 gross acres that was the former 

location of the Florida Steel manufacturing facility. The storage facility site is bounded 

by SR 710 and the CSX rail line to the east and northeast; the Louis Dreyfus juicing plant 

to the north, the Cogentrix 330 MW coal-fired generating plant to the west, the FPL 

powerline right-of-way and open forest land dominated by pine flatwoods and Brazilian 

pepper (Post Family Trust property) to the south and east. Citrus groves and improved 

pasture are located north and east across SR 710 from the site. 

The site itself includes several remnant Florida Steel structures. Much of the remaining 

portion of the site includes spray irrigation fields (related to the on-going groundwater 

remediation at the site), a small pine flatwood, stands of invasive Australian pine and 

Brazilian pepper, and three small stormwater management ponds. 
4-39 4.0 – Environmental Analysis

Table 4.7-1 

Planned Development in the Project Area

Development Name Location Type / Size Facilities 

Venture Park Across SR 710 from the northern corner 

of SRS project site. 

Industriala / 

139 acres 

22 industrial lots and 2 agricultural 

ranchettesb

Indiantown Commerce & 

Technology Park 

West side of CSX Railroad, north 

of the Booker Park Community of 

Indiantown 

Industrial/ 

97.4 acres 

31 industrial lots 

Prism Business Park Northwest corner of SR 710 and County 

Road 609 in Indiantown 

Industrial/ 

21 acres 

Details unknown 

Quillen Development Northwest corner of SR 710 and County 

Road 609 in Indiantown approximately 

1.25 miles from FGS site 

Mixed use/ 

586 acres 

2,250 residential units and 

150,000 square feet of commercial 

space 

Notes: 

a Industrial classification includes manufacturing, warehousing and other high-impact uses. 

b

Agricultural Ranchette classification includes commercial agriculture, along with uses supportive of agriculture. 

4.7.1.2 Project Effects 

The effects of the Project on existing land use and land cover include construction-related 

disturbances, limitations on land use within the LNG storage facility site and right-ofway, and effects on future development patterns in the Project area. The effects would be 

a function of the construction methods employed, restoration actions implemented upon 

completion of construction, and nature of the affected land. Section 2.4 describes the 

construction methods proposed for this Project along with post-construction restoration 

plans. 

FGS has an exclusive option to purchase the former Florida Steel site. FGS would also 

obtain 35.65 acres of temporary construction easement in addition to 25.30 acres of 

permanent easements for operation of the pipelines, M&R station, and interconnections. 

FGS has obtained an agreement to use 10.50 acres of land at the nearby Tampa Farms 

Property for temporary pipe storage and construction staging. Project construction could 

affect as much as 127.03 acres, of which 48.63 acres would be restored to natural 

vegetative cover and 78.40 acres would remain in permanent Project use (i.e., LNG 

storage facility, permanent pipeline right-of-way, M&R station, and interconnections). 
S R- 7 1 0

C S X R ailr o a d

Pr oj e ct 

Pi p eli n e

Pr o p o s e d 

M & R St ati o n

F P L 

I nt er c o n n e cti o n

G ulf str e a m

I nt er c o n n e cti o n

I N D U S T RI A L

A G RI C U L T U R A L

L O W

D E N SI T Y

A G RI C U L T U R A L

R A N C H E T T E

C O M M E R CI A L

G E N E R A L

A G RI C U L T U R A L

R A N C H E T T E

A G RI C U L T U R A L

St or a g e 

F a cilit y Sit e

I N D U S T RI A L

0. 0 0

0. 5 0

1. 0 0

1. 5 0

2. 0 0

2. 5 0

3. 5 0 3. 0 0

3. 9 5

4. 0 5

0. 2 5 0. 5 Mil e s

Fi g ur e 4. 7- 1

F G S Pr oj e ct

Pl a n n e d F ut ur e Pr oj e ct Ar e a L a n d U s e M a p

L e g e n d

R o a d s

Mil e p o st

R ailr o a d

Pr oj e ct Pi p eli n e

St or a g e F a cilit y Sit e

M & R St ati o n

L o w D e n sit y

I n d u stri al

C o m m er ci al G e n er al

A gri c ult ur al R a n c h ett e

A gri c ult ur al

F ut ur e L a n d U s e

C o n str u cti o n St a gi n g Ar e a
4-41 4.0 – Environmental Analysis

LNG Storage Facility 

Construction and operation of the LNG storage facilities would temporarily affect 

approximately 55.58 acres. Storage facility operations would permanently affect 53.10 

acres of the site. Table 4.7-2 identifies the existing land cover on the LNG storage 

facility site that would be affected by Project construction and operation. 

Table 4.7-2 

Land Cover Potentially Affected by LNG Storage Facility Development 

Land Cover 

Existing Land Cover 

(Acres) 

Area affected by 

Construction 

(Acres) 

Proposed Land Cover

(Project Operation) 

(Acres) 

Disturbed Land1 83.64 41.69 44.43 

Forest2 15.78 4.45 11.33 

Invasive Species3 17.24 17.24 0.00 

Wetlands4 14.08 0.00 14.08 

Open Water and Ditches 13.89 0.02 13.87 

LNG Storage Facility 0.00 0.00 53.10 

Pipeline Right-of-way 0.00 0.00 3.55 

Total Acres 144.63 63.40 144.63 

Notes:

1 Disturbed land includes FLUCFCS cover types for disturbed lands, railroads, and roads. 2

 Forest includes FLUCFCS cover types for pine flatwoods and mixed hardwood/coniferous forest. 4

 Invasive species includes FLUCFCS cover types for Brazilian pepper and Australian pine.

4

 Wetlands includes FLUCFCS cover types for mixed wetland hardwoods, exotic wetland hardwoods, freshwater 

marsh, and cypress/exotic wetland hardwoods.

Given the historical use of the LNG storage facility site for industrial purposes, the 

presence of other industrial facilities in the area, the current industrial zoning and planned 

future industrial use of the property by Martin County, development of the Project at this 

site would be compatible with existing and proposed land use in the Project area. Storage 

facility construction and operation would have no adverse effect on existing land use or 

planned development in the area. 

Pipelines, Construction Staging Area, and Aboveground Facilities 

Prior to initiating construction, FGS would secure easements for both temporary (for 

construction) and permanent (for operation) rights-of-way. During the easement 

acquisition process, FGS would compensate landowners for loss of value to specific 

parcels. The easement agreement between the company and landowner typically 

specifies compensation for loss of use during construction; loss of nonrenewable or other 

resources; damage to property during construction; and allowable uses of the permanent 

right-of-way after construction. During negotiations, FGS and affected landowners 

would address the following: 

• allowable uses within the right-of-way; 

• mechanisms required to allow the pipeline to be traversed by heavy 

equipment such as log skidders; and 
4.0 – Environmental Analysis 4-42 

• minor route adjustments to accommodate landowner needs, provided 

the route adjustments do not affect environmentally sensitive areas or 

other non-consenting landowners. 

If an easement cannot be negotiated with a landowner and the Project has been 

certificated by the FERC, FGS could use the right of eminent domain granted to it under 

Section 7(h) of the Natural Gas Act and the procedure set forth under the Federal Rules 

of Civil Procedure (Rule 71A) to obtain the right-of-way and extra workspace areas. 

FGS would still be required to compensate the landowner for the right-of-way and for 

any damages incurred during construction; however, a court would determine the level of 

compensation if a Certificate were issued. In either case, the landowner would be 

compensated for use of the land. 

Construction of the Project pipelines, construction staging area, and aboveground 

facilities would disturb 71.45 acres of land (Table 4.7-3). The proposed pipeline corridor 

crosses open land, forest, and wetlands, but would not affect any agricultural land. No 

residences or federal or state-designated areas are located within 50 feet of the proposed 

pipeline corridor. Table 4.7-3 identifies the acreage of each land use/cover in the pipeline 

corridor, construction staging area, and aboveground facilities. 

Table 4.7-3 

Land Cover Potentially Affected by the Pipeline, Construction Staging Area, and Aboveground 

Facilities (acres) 

Land Cover 

Temporary Construction 

Impacts 

Permanent Operations 

Impacts) 

Disturbed Land1 13.38 3.75 

Prairie 23.28 7.64 

Forest and shrub2 28.83 8.27 

Invasive Species 1.43 0.72 

Wetlands3 & Ditches 3.91 1.95 

Pipeline Facilities 0.00 2.97 

Poultry Feeding Operations 0.62 0.00 

Total Acres 71.45 25.30 

Notes:

1 Disturbed land includes FLUCFCS cover types for disturbed lands, railroads, and roads FLUCFCS cover types. 2 Forest includes FLUCFCS cover types for pine flatwoods and hardwood/coniferous mixed. 3 Wetlands includes FLUCFCS cover types for mixed wetland hardwoods, exotic wetland hardwoods, freshwater 

marsh, and cypress/exotic wetland hardwoods.

Upon completion of construction, the temporary workspaces would be graded, seeded, or 

otherwise restored. The portion of the Tampa Farms property used for temporary pipe 

storage during construction would be restored in accordance with FGS’ agreement with 

the property owner. Because non-woody vegetation would be expected to return to preconstruction conditions within two growing seasons, impacts to acreage currently 

classified as industrial or open land and not needed for permanent right-of-way or 

facilities would be short term and minor. 
4-43 4.0 – Environmental Analysis

4.7.2 Residences and Structures 

The Project is located in an industrial and agricultural area with few residents. There are 

three residences within 0.50 mile of the LNG storage facility, with the nearest residence 

located approximately 0.46 mile away. There are no residences within 0.6 mile, and no 

structures within 50 feet, of the proposed pipeline construction easement. Therefore, 

construction and operation of the Project would have no adverse effect on any residences 

or structures. 

4.7.3 Recreation and Special Interest Areas 

There are no federal, state, or local public lands, recreation areas, nature preserves, 

conservation areas, wildlife management areas, locally significant natural or scenic areas, 

or other special use areas in the immediate Project area and none would be affected by 

Project construction or operation. The closest recreation or special use area is the St. 

Lucie Canal located approximately two miles south of the LNG storage facility site. The 

St. Lucie Canal is used locally for recreational fishing and boating. FGS proposes to 

withdraw water from the St. Lucie Canal for hydrotesting of the LNG storage tanks and 

the pipelines. This withdrawal would occur at an existing irrigation intake with screening 

to minimize the entrainment of fish. After the hydrotesting is completed, FGS would 

return the test water to the St. Lucie Canal. The entire hydrotesting process would take 

about five weeks. The Project, including the proposed water withdrawal, would have no 

effect on recreational use of the river. 

4.7.4 Coastal Zone Management 

The entire state of Florida, including the Project area, is within the State of Florida’s 

designated Coastal Zone (FDEP, 2007). On July 30, 2007, FGS filed an application for 

an ERP under Part IV of Chapter 373 of the Florida Statutes. The ERP permit serves as 

the State of Florida’s final Coastal Zone Management Act (CZMA) federal consistency 

determination. The FDEP approved the ERP for the LNG storage facility site on March 

19, 2008; therefore, the Project has been determined to be consistent with the CZMA. 

4.7.5 Hazardous Waste Sites 

The only landfill or hazardous waste site within 0.25 mile of the Project is the FGS 

property itself and the adjoining remediated soil landfill, both of which were the site of 

the former Florida Steel plant. From 1970 to 1982, Florida Steel recycled steel from old 

cars into steel reinforcement bars for concrete at the Project site, which FGS proposes to 

develop for the LNG storage facility. This process resulted in on-site soil (lead, zinc, and 

PCB) and groundwater (sodium) contamination. In 1982, the EPA included the Florida 

Steel site on the National Priorities List under the provisions of the Comprehensive 

Environmental Response, Compensation, and Liability Act. 

The site is currently part of the EPA’s Superfund Program and is nearing completion of 

its remediation. The soil remediation has been completed and primarily involved the 

removal, treatment, and placement of the contaminated soils in a double-lined landfill 

(referred to as the “land vault”) constructed at the site. It should be noted that FGS would 
4.0 – Environmental Analysis 4-44 

not acquire the vault and it would not be included in the Project site. The current 

property owner, Gerdau Ameristeel, would retain ownership of the landfill vault and 

rights of access through the LNG storage facility site to inspect and maintain the vault. 

The groundwater remedial system involved the extraction, treatment, and disposal of the 

treated groundwater via an on-site spray irrigation system. According to EPA (2006), 

groundwater contaminant concentrations have decreased and are nearing cleanup 

standards. 

As a result of its past use and condition, the following deed restrictions have been 

imposed on the property by EPA: 

1. The Property shall not be used for residential purposes; 

2. No day-care facilities, kindergartens, playgrounds, schools, or other facilities 

catering to children under the age of 16 years shall be operated on the 

property; 

3. The Property shall not be used for swimming, fishing, camping, or hunting; 

4. No structures or improvements intended for use for recreational purposes shall 

be constructed or operated on the property; and 

5. The Property shall not be used for the purpose of growing any crops to 

provide food for humans or animals. 

EPA has completed two five-year reviews (i.e., 2001 and 2006) of the site. Both reviews 

determined that the remedial actions taken remain protective of human health and the 

environment. Subsequent reviews are required to be conducted every five years. In a 

letter to FGS (EPA, 2006a), EPA stated that “based upon the facts presently known to 

EPA, the Agency is of the opinion that the proposed used of the Property does not pose 

significant incompatibility issues with potential future cleanup activities.” 

The Project would be consistent with the deed restrictions; however, FGS would be 

responsible for ensuring that the proposed use does not interfere with or impede the 

cleanup at the site. Therefore, the Project would not affect, or be affected by, any 

hazardous waste or other contaminated sites. 

4.7.6 Visual Resources 

4.7.6.1 Existing Visual Character 

Visual resources refer to the composite of basic terrain, geologic features, vegetative 

patterns, and anthropogenic features that comprise the visual character of an area. The 

existing LNG storage facility site has been historically used for industrial purposes and is 

adjacent to two industrial neighbors, the Cogentrix 330 MW coal-fired generating plant 

and Louis Dreyfus citrus processing facility. As a result, the visual character of the 

proposed FGS site and neighboring areas is currently industrial. 

The elevation of the tallest structure at the Louis Dreyfus citrus processing facility is 138 

feet. The Cogentrix generating plant includes a 235-foot-high power plant and a 495-
4-45 4.0 – Environmental Analysis

foot-high stack. Other visual features of the area include electric transmission lines, 

citrus groves, roads, forested land, and open fields. 

4.7.6.2 Project Effects 

The significance of visual impact that may result from a proposed project depends on the 

general character of the existing landscape, degree of alteration of that view, number of 

potential viewers, and perspective of the viewer. 

LNG Storage Facility 

The two proposed LNG storage tanks would be the dominant visual feature on the LNG 

storage facility site. Each tank would be approximately 280 feet in diameter and 174 feet 

above grade. The other FGS facilities would be at least partially screened by vegetation 

from viewers driving on SR 710 or from other pubic viewing locations around the area. 

We evaluated the view of the LNG storage tanks from the intersection of SR 710 and Fox 

Brown Road, approximately 0.25 mile northwest of the LNG storage facility site, as a 

representative view from the major road in the area. As Figure 4.7-2 shows, the LNG 

storage tanks would be visible from vehicles traveling along SR 710; however, other 

industrial features, such as the Cogentrix stack and the Louis Dreyfus citrus processing 

facility are also prominent. 

Overall, we believe that the industrial character of the Project would be consistent with 

other industrial facilities in the area and would not represent a significant visual impact. 

To minimize visual effects, FGS would avoid removal of mature trees (other than 

Australian pine, which is required to be removed by Martin County because it is an 

invasive species) and provide a dense landscape buffer along the edge of the property 

adjacent to SR 710. In addition, FGS would establish a PAMP that includes provisions to 

provide visual buffers around the LNG storage facility. To minimize light pollution at 

night, FGS would use downcast lighting fixtures. 

Pipelines, Construction Staging Area, and Associated Aboveground Facilities 

The primary visual impact during pipeline and M&R station construction would result 

from clearing of vegetation. Upon completion of construction, the temporary pipeline 

construction right-of-way (35.65 acres) and construction staging area (10.50 acres) would 

be restored to pre-construction conditions. The permanent pipeline right-of-way (22.33 

acres) would be maintained with low-growth (e.g., shrub or herbaceous) vegetation that 

would allow for continued access to the pipeline corridor for inspection and maintenance. 

The M&R station and the interconnections would not be restored, but would be stabilized 

with gravel and fenced for security purposes. 
4-46

The vantage point on the figure is looking southeast from Fox Brown Road, just north of SR-710. 

Figure 4.7-2 

FGS Project 

Storage Facility Visual Simulation 

Proposed LNG 

storage tanks
4-47 4.0 – Environmental Analysis

4.8 SOCIOECONOMICS 

The Project would be located in an unincorporated portion of Martin County classified by 

the U.S. Census Bureau as the Indiantown Census County Division (CCD), which 

comprises the majority of land area in Martin County. The nearest concentration of 

population to the Project is also unincorporated and identified by the U.S. Census as the 

Indiantown Census Designated Place (CDP). The socioeconomic effects of the Project 

would likely extend beyond the Indiantown CCD and CDP; therefore, for the purpose of 

this socioeconomic analysis, we define Martin County as the Project’s area of influence. 

We include information, where available, for the Indiantown CCD and CDP and the State 

of Florida for comparison purposes. Figure 4.8-1 shows the boundaries of Martin County 

and the Indiantown CCD and CDP. 

4.8.1 Population 

Martin County has a total population of 126,731 in 2000 (U.S. Census, 2000a). Martin 

County experienced slightly higher growth rates than the State of Florida, but slightly 

lower growth rates than the Indiantown CCD between 1990 and 2000 (Table 4.8-1). 

Table 4.8-1 

Existing Population in the Project Area of Influence 

Place Name 

Total 

2000 Population 

Population Change Since 

1990 (%) 

Population Density 

(persons/sq. mi.) 

State of Florida 15,982,378 23.5 296.4 

Martin County 126,731 25.6 227.9 

Indiantown CCD 15,530 29.3 37.1 

Indiantown CDP 5,588 12.3 156.0 

Source: U.S. Census Bureau, 2000 Census 

Population density for Martin County is less than the average for the State of Florida. 

Most of Martin County’s population is located along the Atlantic coast, while the 

population density of the inland portions of the County, as represented by the Indiantown 

CCD, is quite low reflecting the rural character of this portion of the County (U.S. Census, 

2000a). 
4-48

Figure 4.8-1 

FGS Project 

US Census Track Boundaries 
4-49 4.0 – Environmental Analysis

Project-related population effects are expected to be temporary and relatively minor. 

Project construction is estimated at approximately 36 months. During construction, the 

total population change would equal the number of non-local construction workers plus 

any family members accompanying them. Project construction would require an average 

of 270 supervisory personnel and crafts workers (including skilled, semi-skilled, and 

unskilled workers), with a peak of around 450 personnel during construction months 14 

and 15. FGS proposes to use local workers for construction to the extent that they are 

available and is encouraging local companies to implement training programs to ensure 

that many of the construction jobs would be filled by workers from the area. The 

potential pool of construction workers within commuting distance of the Project is large, 

including most or all of Martin, Palm Beach, and St. Lucie counties. Therefore we 

anticipate that relatively few construction workers would actually move to the Project 

area during construction. 

Project operations would require up to 33 permanent staff. This small staff would likely 

be comprised of existing residents and some non-local personnel who would move to the 

Project area. Even if all 33 staff were non-local and moved to the Project area with their 

families, the overall effect on the population of Martin County (126,731 residents) would 

be minor. As a result, we do not anticipate any significant long-term population growth 

to occur as a direct effect of the Project. 

4.8.2 Economy and Employment 

The civilian labor force within Martin County includes an estimated 53,301 individuals 

(Census, 2000), with the largest percentage employed in sales (17 percent) and 

construction/extraction industries (10 percent). Martin County has a relatively high per 

capita income that is approximately 27 percent greater than that of Florida, although per 

capita income in the Indiantown CCD is below the State average and the poverty rate is 

above the State average. The unemployment rates of Martin County and the Indiantown 

CCD are higher than that of the State of Florida as a whole; however, the unemployment 

rate in the Indiantown CDP was less than the State of Florida. Within the Indiantown 

CCD and CDP, income is lower than the County as a whole and the portion of the 

population living below the poverty level is significantly higher. Table 4.8-2 reports 

unemployment rates and per capita income for Martin County, the State of Florida, and 

the Indiantown CCD and CDP. 

Table 4.8-2 

Income and Unemployment Data for the Project Area of Influence

State/County/ 

Town 

1999 

Per Capita 

Income 

($) 

1999 

Population Below 

Poverty Level 

(number and %) 

2000 

Civilian 

Labor 

Force 

2000 

Unemployment 

Rate 

(%) 

State of Florida $21,557 1,952,629 (12%) 7,407,458 3.8 

Martin County $29,584 10,844 (9%) 53,301 4.2 

Indiantown CCD $18,530 2,418 (17%) 6,670 5.7 

Indiantown CDP $11,085 1,250 (24%) 2,252 3.6 

Source: U.S. Census, 2000 
4.0 – Environmental Analysis 4-50 

Project construction would occur over a period of 36 months and require an average 

workforce of 270 personnel with a maximum of 450 personnel in construction months 14 

and 1 5. To the extent available, workers would be hired from the local area and their 

salaries would directly benefit the regional economy. These jobs would also create a 

multiplier effect as the purchase of goods by construction workers (e.g., food, clothing, 

lodging, gasoline, and entertainment) would create additional jobs temporarily 

stimulating the local economy. These jobs would represent a temporary, moderate 

increase in employment opportunities within the area. During operation, the Project 

would create up to 33 full-time positions, which would represent a minor, permanent 

increase in employment opportunities in the area. 

During Project construction, expenditures would include approximately $19 million for 

goods and services and approximately $100 to $110 million for salaries, with a monthly 

average of approximately $3 million. During operation, the Project would pay 

approximately $2.2 million annually in wages and provide an estimated beneficial 

economic impact, including Project spending, sales and payroll, of nearly $19 million 

(2006 dollars) annually (FAU, 2007). 

4.8.3 Housing and Property Values 

Table 4.8-3 provides information on available housing units in the area of influence. As 

discussed in Section 4.8.1, relatively few construction workers are expected to move to 

the Project area. Even if all long-term construction workers (i.e., 270 workers) 

temporarily relocate, they would only occupy approximately 2 percent of the available 

rental units in Martin County. With a rental vacancy rate of about 9.5 percent, there is 

adequate rental housing available. Housing demand for the 33 permanent staff during 

operation would represent a negligible, though permanent, increase in housing demand. 

Table 4.8-3 

Rental Units in Martin County 

State/ County/ 

Town 

Rental 

Units* 

Rental 

Vacancy 

Rate* 

Units for Seasonal, 

Recreational or 

Occasional Use* 

Number of 

Hotel/Motel 

Rooms** 

Total 

Units 

Martin County 11,152 9.5% 6,720 985 18,857 

Sources: *U.S. Census Bureau State and County Quick Facts, 2000 Census. 

 **U.S. Economics Characteristics, 2005 

The Project is not anticipated to adversely affect property values. The surrounding area 

is predominantly in industrial and agricultural use, with the nearest residence 

approximately 0.46 miles away. Based on the surrounding land uses, zoning, and the 

distance to the nearest residence, it is unlikely that the Project would adversely affect 

property values. 

4.8.4 Government Revenues from the Project 

Government tax revenues would increase as a direct result of the Project. In addition to 

Martin County Building Department fees to be paid by FGS, the County would also 
4-51 4.0 – Environmental Analysis

experience an increase in sales tax revenue resulting from local spending by construction 

employees as well as by the Project. In addition, Project operation would have a positive 

effect on state and local tax revenues. State revenues from Project operation would 

include corporate income tax revenue of approximately 5.5 percent of income. FGS 

would pay at least $1.6 million annually in property taxes to Martin County (FAU, 2007). 

The property tax benefits would continue through the life of the Project. 

4.8.5 Public Services 

Table 4.8-4 summarizes the number of full-time equivalent educational, medical, police, 

and fire protection employees in the area of influence. A temporary increase in the 

demand for public services would occur during the construction phase of the Project. 

This increase in demand would be related to support for construction activities as well as 

the temporary in-migration of some construction personnel and their families. 

Table 4.8-4 

Existing Medical, Police, Education, and Fire Full-Time Equivalents in the Area of Influence 

State/County/Town Education 

Health and 

Hospitals 

Police 

Protection 

Fire 

Protection 

Total FullTime 

Equivalents 

Martin County 1,912 81 378 106 3,357 

Source: U.S. Census Bureau 1997 Federal State and County Area Finance and Employment Fastfacts 

During Project operation, the facility would have self-contained safety, fire, and security 

resources and would thus not place an increased demand on the local public service 

infrastructure’s capacity in terms of resources or personnel. Because only 33 permanent 

staff would be hired, the addition of those individuals and their families to the local 

population would represent a negligible increase in demand for public services. 

4.8.6 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 its 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 

called upon federal agencies to actively scrutinize the following issues with respect to 

environmental justice (CEQ, 1997): 

• racial and economic composition of affected communities; 

• health-related issues that may amplify Project effects on minority or lowincome individuals; and 

• public participation strategies, including community or tribal participation in 

the process. 
4.0 – Environmental Analysis 4-52 

The EPA provides guidance on determining whether there is a minority or low income 

community to be addressed in a NEPA analysis. 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. 

4.8.6.1 Potential for Disproportionate and Adverse Impacts 

Minority populations comprise less than 50 percent of the population in the State of 

Florida, Martin County, and the Indiantown CCD (Table 4.8-5). As a whole, Martin 

County contains a significantly smaller proportion of minorities (approximately 10 

percent) within its population than the State; however, the proportion of minorities in the 

Indiantown CCD (approximately 32 percent) is similar to the racial distribution of the 

State (approximately 22 percent). Although the minority population with the Indiantown 

CCD is not greater than 50 percent, the Indiantown CDP, which is only approximately 

one mile from the Project site, does have a minority population that is meaningfully 

greater than in the general area. 

Table 4.8-5 

Racial/Ethnic Characteristics of the Area Surrounding the FGS Storage Project 

Racial/Ethnic Group (percent)

Place White 

African 

American 

Native 

American 

and 

Alaskan 

Native Asian 

Native 

Hawaiian 

and 

other 

Pacific 

Islander 

Persons 

reporting 

some 

Other 

Race 

Persons 

reporting 

two or 

more 

races 

Persons 

of 

Hispanic 

or 

Latino 

Origin

State of 

Florida 

78.0 14.6 0.3 1.7 0.0 3.0 2.4 16.8 

Martin 

County 

90.0 5.3 0.3 0.6 0.1 0.3 2.4 7.5 

Indiantown 

CCD 

68.8 13.6 1.2 0.3 0.4 13.3 1.1 3.3 

Indiantown 

CDP 

45.9 21.0 0.2 0.0 0.1 26.5 0.3 48.9 

Source: U.S. Census Bureau, 2000 Census 

As discussed in Section 4.8.2, per capita income in Indiantown CCD ($18,530) is lower 

than the County ($29,584) and State ($21,557) averages. Approximately 17 percent of 

the Indiantown CCD is below the poverty level (Table 4.8-2), which is greater than the 

State of Florida (12 percent) and Martin County (9 percent). Although the percentage of 

population below the poverty line is greater in the Indiantown CCD, it is not 

meaningfully higher than the State average (17 vs 12 percent). 

Although there does not appear to be a minority or low-income community by EPA 

definitions within the Indiantown CCD, there is a minority population relatively close by 

in the adjoining census unit (Indiantown CDP). Therefore, we evaluated whether the 
4-53 4.0 – Environmental Analysis

Project would have disproportionately high and adverse environmental or human health 

effects on the minority population within the Indiantown CDP. 

As described in Section 4.8.2, the proposed Project would have positive effects on the 

socioeconomic characteristics and economies within the region of influence. The 

proposed Project would provide employment opportunities and added revenues in the 

form of taxes and spending. When available, local workers would be used for 

construction. FGS is sponsoring a welding training program at the Indian River 

Community College to develop skilled welders for pipe and plate welding. The welder 

training course will teach unskilled personnel a transferrable skill plus safe work habits. 

The proposed Project would be located on a parcel of land zoned for industrial use and 

located approximately a half mile from the nearest residence. In addition, the proposed 

FGS Project would productively use property on which a non-industrial use would be 

unacceptable due to prior contamination. Although the racial and economic composition 

of the Indiantown CCD shows some deviations from state and county-level statistics, as 

described above, there is no evidence that the proposed Project would cause a 

disproportionate share of adverse environmental or socioeconomic impacts on any racial, 

ethnic, or socioeconomic group. 

The primary health issue related to the proposed Project would be the risk associated with 

the rare potential of pipeline failure or LNG storage accident. Section 4.12 discusses the 

risks and associated impacts to public safety that would result from an accident at the 

facility or a pipeline failure and describes how applicable safety regulations and standards 

would minimize the potential for these risks. The proposed LNG storage facility and 

pipeline corridor avoid populated areas, minimizing the number of persons at risk of 

injury. Although the proposed LNG storage facility would emit some air emissions 

during normal Project operation, these emissions would be minor, below PSD 

applicability thresholds, and not a public health hazard. Based on our analysis, there is 

no evidence that health risks would be disproportionately borne by any racial, ethnic, or 

socioeconomic group. 

To summarize, although the racial and economic composition of the Indiantown CCD 

does not appear to meet the EPA definition of a minority or low-income community, it is 

proximate (within about one mile) of the Indiantown CDP, which does have a minority 

population that is meaningfully higher than the general area. There is no evidence 

however, that the Project would have any significantly high or adverse environmental or 

human health effects. Overall, we conclude that the Project would not result in any 

environmental justice issues. The socioeconomic impacts of the proposed Project are 

generally beneficial, and there is no evidence that the slight risk of a pipeline or LNG 

tank failure would be disproportionately borne by any group. 

4.8.6.2 Public Participation Strategies 

Under Executive Order 12898, each federal agency must ensure that public documents, 

notices, and hearings related to human health or environmental issues are concise, 

understandable, and readily available to the public. The public review and comment 

process that the FERC implemented in association with the environmental review of the 

proposed Project is discussed in section 1.3. The environmental mailing list for the FGS 
4.0 – Environmental Analysis 4-54 

Project was developed when the Commission issued the NOI for the Project on February 

15, 2007. Since then the mailing list has been continually updated. All interested parties 

or property owners affected by the Project received notices about the Project without 

distinction based upon minority or income status. In addition to landowners, the 

distribution list for this EIS includes federal, state, and local officials; agency 

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

and news media outlets. 

In addition to our public review and comment process, FGS has communicated directly 

with the property owners who would be affected by the proposed Project, irrespective of 

minority or income status. FGS established an Internet Website at 

http://www.floridiangasstorage.com; a toll-free telephone number, 1-800-621-6843; and 

an e-mail address, info@floridiangasstorage.com to provide potentially affected 

landowners and stakeholders with a venue for providing comments or requesting 

additional information about the proposed Project. FERC staff encourages FGS to 

continue its commitment to maintain open communications with affected landowners 

during construction through similar methods, should the Project ultimately be certified. 

The environmental mailing list for the final EIS includes affected landowners; federal, 

state, and local government agencies; elected officials; environmental and public interest 

groups; Native American tribes; local libraries and newspapers; and other parties who 

provided scoping comments, asked to remain on the mailing list, or wrote the FERC or 

one of the cooperating agencies asking to receive a copy of the document. A formal 

notice was published in the Federal Register, indicating that the final EIS is available and 

has been mailed to individuals and organizations on the environmental mailing list 

prepared for the proposed Project (see Appendix A). Section 1.4 further describes the 

public notification and participation process completed for the proposed Project, and 

section 4.10 describes contacts with Native American tribes that traditionally occupied, 

or currently occupy the Project area. 

4.8.6.3 Environmental Justice Summary 

In summary, information about the proposed Project has been readily available to the 

public and no disproportionately high and adverse human health or environmental effects 

on minority and/or low-income communities or Native American tribes have been 

identified. Furthermore, Project construction would provide short-term job opportunities 

in the region of influence and the welding training program provides a long-term, 

transferrable skill to local workers in the program. The only long-term socioeconomic 

effects of the Project are likely to be beneficial, based on the increase in tax revenues that 

would accrue to the counties affected by the Project. A more specific discussion of the 

Project-related impacts on residential areas, air quality and noise, and safety is presented 

in sections 4.7, 4.9, and 4.11 respectively. Cumulative impacts are discussed in section 

4.13. 

4.9 TRANSPORTATION 

SR 710 would provide direct vehicular access to the LNG storage facility site. The 

average annual daily traffic volume on SR 710, measured just northwest of Allapattah 
4-55 4.0 – Environmental Analysis

Road approximately 0.5 miles from the storage facility site, is 7,800 vehicles per day. 

Figure 2.1-2 shows other local roads in the Project area including Fox Brown Road, 

Allapattah Road, and SR 76 (Kanner Highway). The Florida Turnpike and I-95 are 

approximately 24 and 25 miles to the east, respectively, and provide good access to the 

remainder of the State. The Project would also have direct access to rail (CSX 

Transportation System), which runs adjacent to the site and parallel to SR 710, and 

nearby access for barges on the St. Lucie Canal. Construction of the Project could affect 

area transportation if the volume of construction or operation-related traffic caused delays 

or other inconveniences, or if construction resulted in temporary road closures or lane 

blockages. 

One full access driveway connection to SR 710 between Fox Brown Road and 

Allapattah Road would serve as the main entrance to the LNG storage facility and 

provide primary site access for construction and operational traffic. Any site access from 

the state highway system would be subject to the requirements of the State Highway 

System Connection Permits Administrative Process as well as the Access Management 

Classification System and Standards. FGS is also working on an agreement that would 

establish a permanent secondary access road connection between the Indiantown 

Commerce and Technology Park and the LNG storage facility site. This road would only 

be used to provide emergency access to the Project if the primary entrance was blocked 

by a train on the CSX rail line. 

Project construction is proposed to be completed over a 36-month period. Construction 

activities would require an average of 270 workers and a peak of approximately 450 

workers during construction months 14 and 15. All construction activities would occur 

during a single shift, with morning traffic assumed to be inbound to the site and afternoon 

traffic outbound. To minimize the potential for traffic congestion, shift changes would 

occur outside the normal peak hours. All construction materials would be delivered by 

trucks during off-peak hours. The largest number of truck trips would occur in the 17th 

month of construction, when an estimated 1,640 truck trips, or an average of 106 truck 

trips per day would occur. Peak truck traffic from the Project would be minor (less than 

7 percent) compared to the average daily truck traffic on SR 710, which is approximately 

1,670 trips per day. The maximum daily truck traffic during project operations would be 

4 truck trips per day, which is negligible compared to the average daily truck traffic on 

SR 710. 

FGS proposes traffic control at the SR 710 LNG storage facility entrance consisting of 

temporary traffic lights and the use of off-duty representatives of the Martin County 

Sheriff’s Department. The temporary traffic lights would be programmed for periodic 

“controlled stoppage” of SR 710 traffic during the morning start work hours and the 

afternoon/evening stop work hours. The stoppage would allow construction traffic to 

enter SR 710 and/or allow northbound traffic to make left turns into the LNG storage 

facility site. During those hours not requiring controlled stoppage, the temporary traffic 

lights would be programmed to blink yellow for both directions of SR 710 and red for 

traffic leaving the storage facility site. The traffic light would also be equipped with a 

switch to allow the off-duty representative of the Sheriff’s Department to override the 

system to ensure that traffic moved through the intersection smoothly with as little 

disruption as possible to SR 710 traffic during high-use periods. Because the access road 
4.0 – Environmental Analysis 4-56 

between the Indiantown Commerce and Technology Park and the LNG storage facility 

site would only be used for emergencies, traffic controls are not proposed for this access 

point. No construction would occur on public roads, so no road closures or detours are 

expected. 

Florida Department of Transportation (FDOT) plans several traffic signalization and turn 

lane improvements along SR 710 in the next few years to maintain the desired level of 

service standards. In addition, the FDOT is expected to begin a resurfacing project in 

February 2008 for SR 710 between the Okeechobee County Line, northwest of the LNG 

storage facility site, and Martin Luther King Jr. Boulevard, just southeast of the storage 

facility site, including the full frontage of the property. FDOT indicates that any work 

that would occur within FDOT rights-of-way would be conducted in accordance with the 

FDOT Utility Accommodation Manual, dated January 1999 (FDOT, 2007). 

FGS would employ three shifts daily during Project operation, with 20 employees at the 

largest shift. The Project would also receive approximately two daily truck trips 

(Kimley-Horn, 2007). This volume of vehicular traffic would not cause any traffic 

problems at the LNG storage facility’s driveway intersection with SR 710 or elsewhere in 

the local traffic network. As a result, traffic control at the storage facility entrance from 

SR 710 would not be required for Project operation and the temporary traffic lights would 

be removed once construction was completed. 

During emergency events (i.e., the aftermath of a hurricane or other supply interruption) 

when pipeline delivery is not possible, LNG would be transported from the storage 

facility by truck to FGS capacity holders. Specific locations of the truck destinations are 

not known at this time; however, it is expected that hospitals, gas distribution companies, 

power plants, and other essential services would be likely destinations during 

emergencies. Trucks traveling north would not travel through residential areas until they 

reached the city of Okeechobee, roughly 25 miles from the LNG storage facility site. 

Trucks traveling south would pass through Indiantown. Since these additional truck trips 

would only occur during emergency conditions, we do not anticipate that they would 

create any significant traffic problems. 

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 any properties listed in, or 

eligible for listing in, the National Register of Historic Places and to provide the ACHP 

an opportunity to comment on the undertaking. FGS, as a non-federal party, is assisting 

the FERC in meeting its obligation under Section 106 of the NHPA by conducting the 

field surveys and evaluations required by ACHP regulations at 36 CFR 800. 

The area of potential effect (APE) of a project is the geographic area or areas within 

which an undertaking may directly or indirectly cause change in the character or use of 

historic properties, if any such properties exist. The APE is influenced by the scale and 

nature of an undertaking and may be different for different kinds of effects caused by the 

undertaking (36 CFR §800.16[d], amended 1999). The direct APE for this Project 

includes the 144.63-acre storage facility site as well as an approximately four-mile-long, 

210-foot-wide pipeline corridor, which encompasses the proposed pipeline construction 
4-57 4.0 – Environmental Analysis

easement as well as potential route variations. The visual APE includes those properties 

or areas within the viewshed of the Project. 

4.10.1 Results of Cultural Resources Surveys 

FGS conducted research and cultural resource surveys of the Project APE in February 

2007. Review of the Florida Master Site File determined that 14 prior cultural resource 

management surveys have been conducted in the Project area, although none of these 

studies identified any archaeological resources within one mile of the Project. FGS also 

conducted a pedestrian survey of the entire direct APE and subsurface testing of the 

approximately four-mile-long pipeline corridor. In addition to the archaeological surveys, 

FGS conducted a survey of historic buildings 50 years of age or older within the entire 

APE, including the LNG storage facility site, pipeline corridor, and surrounding areas. 

FGS submitted Cultural Resource Assessment Survey Reports to the Florida Department 

of State - Division of Historical Resources, which functions as the State Historic 

Preservation Office (SHPO) in Florida. In letters dated May 25, 2007 and June 2, 2008, 

for the Project facilities and the Tampa Farms staging area, respectively, the Florida 

SHPO concurred with the findings of FGS’ reports that the Project would have no effect 

on any properties listed in, or eligible for listing in, the National Register of Historic 

Places, and agreed that no further investigation of the Project was necessary. We also 

concur. 

FGS has filed an acceptable Unanticipated Discoveries Plan with the Commission that 

outlines the procedures to be followed in the event that unanticipated cultural materials or 

human remains are encountered during construction of the Project. This plan was filed 

by FGS in its certificate application in October 2007 and can be found on the FERC’s 

eLibrary website at www.ferc.gov under Docket No. CP08-13-000. 

4.10.2 Native American Consultation 

FGS sent letters describing the Project, together with a location map showing the location 

of proposed Project facilities, to each of the five federally-recognized tribes with ties to 

the area: the Miccosukee Tribe of Indians of Florida, Muscogee Creek Indians, Band of 

Creek Indians, Seminole Nation of Oklahoma, and Seminole Tribe of Florida. 

FGS held informal conversations with both the Seminole Tribal Historic Preservation 

Officer (THPO) and Miccosukee Section 106 representative prior to the initiation of field 

work, at which time no concerns or issues were identified. A copy of the Cultural 

Resource Assessment Report was submitted to the Seminole THPO, who responded with 

a concurrence e-mail on May 31, 2007. During an April 11, 2007, meeting, the 

Miccosukee Tribal representative also concurred with the report findings. 

4.10.3 Compliance with NHPA 

FGS has completed cultural resource surveys on the LNG storage facility site, 

construction staging area, and pipelines corridor, submitted reports on the results; and 

conducted consultation with the SHPO, Seminole THPO, and Miccosukee Tribal Section 

106 representative. All concur that the proposed development would have no effect on 
4.0 – Environmental Analysis 4-58 

cultural resources listed or eligible for listing in the National Register of Historic Places 

and agree that no further surveys are required. We also concur. Consequently, the 

Commission’s required consultation under Section 106 of the NHPA is complete. 

4.11 AIR QUALITY AND NOISE 

4.11.1 Air Quality 

4.11.1.1 Existing Air Quality 

Ambient air quality is protected by federal and state regulations. The Clean Air Act 

designates six pollutants as criteria pollutants for which the National Ambient Air Quality 

Standards (NAAQS) are promulgated. The NAAQS for sulfur dioxide (SO2); nitrogen 

dioxide (NO2); particulate matter (PM10 particulates and PM2.5 particulates); carbon 

monoxide (CO); ozone (O3,); and lead were set to protect human health (i.e., primary 

standards) and human welfare (i.e., secondary standards). These standards are 

summarized in Table 4.11-1. State air quality standards cannot be less stringent than the 

NAAQS. The State of Florida has its own ambient air quality standards that are more 

stringent than the NAAQS for some pollutants and the same as NAAQS for other 

pollutants. The NAAQS program also classifies areas, where sufficient data are available, 

as either attainment (i.e., does not exceed NAAQS) or non-attainment (i.e., exceeds 

NAAQS). The Project would be located in Martin County, which is in attainment for all 

criteria pollutants. 

Currently, Martin County has no active continuous air quality monitoring stations. The 

closest air quality monitoring stations to the Project are in Palm Beach County, which has 

seven. Over the past three years (i.e., 2004 to 2007), the NAAQS standards were only 

exceeded once for PM2.5 (i.e., 51 micrograms per cubic meters) at the Delray Beach 

monitoring station in Palm Beach County. 

4.11.1.2 Project Effects 

Air quality would be affected by construction and operation of the Project. Although air 

emissions would be generated by operation of equipment during construction of the 

pipeline and aboveground facilities proposed by FGS, most air emissions associated with 

the Project would result from the long-term operation of the LNG storage facility. 

The LNG storage facility would contain vaporization, liquefaction, and metering systems, 

including: 

• eight natural gas-fired WEG heaters, each rated at 98 MMBtu/hr heat 

input that would operate 2,400 hours per year and be equipped with a 

low nitrogen oxide (NOx) burner to control NOx emissions; 

• two natural gas-fired regeneration gas heaters each rated at eight 

MMBtu/hr that would operate a maximum of 2,880 hours per year; 

• two natural gas-fired amine system heaters, each rated at 10 

MMBtu/hr that would operate 5,760 hours per year; and 
4-59 4.0 – Environmental Analysis

• two natural gas-fired M&R station heaters, each rated at 52 MMBtu/hr 

that would operate a maximum of 2,400 hours per year. 

Table 4.11-1 

National and State Ambient Air Quality Standards 

National AAQS (μg/m3) 

Pollutant Averaging Time Primary Standard 

Secondary 

Standard 

Florida 

AAQSa 

(μg/m3) 

Particulate matter 

less than 10 microns 

in diameter c Annual Arithmetic Mean NA NA 50 

 (PM10) 24-Hour Maximum 150 150 150 

Particulate matter 

less than 2.5 microns 

in diameter c Annual Arithmetic Mean 15 15 15 

 (PM2.5) 24-Hour Maximum 35 35 35 

Sulfur Dioxide Annual Arithmetic Mean 80 NA 60 

 24-Hour Maximum 365 NA 260 

 3-Hour Maximum NA 1,300 1,300 

Carbon Monoxide eight-hour Maximum 10,000 10,000 10,000 

 1-Hour Maximum 40,000 40,000 40,000 

Nitrogen Dioxide Annual Arithmetic Mean 100 100 100 

 

Ozone c 1-Hour Maximum d NA NA 235 

 eight-hour Maximum 0.08 ppm 0.08 ppm 

Lead Calendar Quarter 1.5 1.5 1.5 

 Arithmetic Mean 

Notes: 

μg/m3 = micrograms per cubic meters; ppm = parts per million 

NA = Not applicable, i.e., no standard exists. 

a Short-term maximum concentrations are not to be exceeded more than once per year, except PM10

and O3 AAQS, which are based on expected exceedances. b

 Maximum concentrations are not to be exceeded. 

c

 Due to a lack of evidence linking health problems to long-term exposure to coarse particle pollution, 

EPA revoked the annual PM10 standard in 2006 (effective December 17, 2006). On July 18, 1997, EPA 

promulgated revised AAQS for particulate matter and ozone. For particulate matter, PM2.5 standards 

were introduced with a 24-hour average standard of 35 μg/m3

 (based on the three-year averages of the 

98th percentile values) and an annual standard of15 μg/m3

 (three-year averages at community 

monitors). The O3 standard was modified to be 0.08 ppm (i.e., 160 μg/m3

) for the eight-hour average; 

achieved when the three-year average of 99th percentile values is 0.08 ppm or less. These standards 

must be implemented in the 2007-2008 timeframe. The FDEP has not yet adopted the revised 

standards. 

d

 To attain this standard, the three-year average of the fourth-highest daily maximum eight-hour 

average ozone concentrations measured at each monitor within an area over each year must not 

exceed 0.08 ppm. One-hour ozone standard was revoked in June 2005. 

Sources: Federal Register, Vol. 43, No. 118, June 19, 1978; 40 CFR 50; 40 CFR 52.21; Florida 

Chapter 62.204, F.A.C. 
4.0 – Environmental Analysis 4-60 

In addition to the pipeline and LNG storage facility, FGS would also install: 

• four diesel-fired emergency generators rated at 3,500 and 3,000 

kilowatts, respectively, which would each operate a maximum of 250 

hours per year; 

• one emergency fire water pump engine rated at 400 hp, which would 

operate a maximum of 250 hours per year; 

• two Amine System vents, which would each operate at a maximum of 

5,760 hours per year; and 

• a cooling tower consisting of four cells with a total circulating water 

flow rate of 300 gpm and unlimited hours of operation. 

Construction Emissions 

Air quality impacts associated with Project construction would include emissions from 

fossil-fueled construction equipment and fugitive dust. Such air quality impacts, 

however, would generally be temporary and localized. Large earth-moving equipment, 

wheel loaders, trucks, and other mobile sources may be powered by diesel or gasoline 

and are sources of combustion emissions, including NOx, CO, volatile organic 

compounds (VOCs - a precursor of ozone), SO2, PM10, PM2.5, and hazardous air 

pollutants (HAPs). These temporary impacts would be generally limited to the 

immediate vicinity of the construction area. FGS would maintain all fossil-fueled 

construction equipment in accordance with manufacturer’s recommendations to minimize 

construction-related emissions. 

The majority of air emissions during construction activities would be respirable 

particulate matter (PM10 and PM2.5) and total suspended particles in the form of fugitive 

dust. Fugitive dust would result from land clearing, grading, excavation, concrete work, 

and vehicle traffic on unpaved roads. The amount of dust generated would be a function 

of construction activities, soil type, moisture content, wind speed, frequency of 

precipitation, vehicle traffic, vehicle type, and roadway characteristics. Emissions would 

be greater during drier periods in areas of fine-textured soils. FGS would apply water 

sprays as appropriate to prevent excessive fugitive dust generation. Table 4.11-2 

summarizes the anticipated combustion emissions from construction equipment engines 

and fugitive dust emissions from unpaved roads. 

Operations Emissions 

The LNG storage facility would emit air pollutants as a result of combustion of natural 

gas in the heaters (i.e., WEG heaters, regeneration gas heaters, amine system heaters, and 

M&R station heaters) and in association with the periodic operation of the diesel-fired 

emergency generators, diesel-fired water pump, amine system vent, and cooling tower 

cells. Table 4.11-3 summarizes the anticipated emissions of NOx, CO, VOCs, SO2, total 

PM, and HAPs associated with the FGS Project during operations. The FGS Project 

emissions would be minimized through the use of low NOx burners for the WEG heaters; 

clean-burning natural gas fuels; and appropriate operation and maintenance procedures. 
4-61 4.0 – Environmental Analysis

Table 4.11-2 

Summary of Air Emissions from Project Construction (tons/year)

Year 1 Year 2 Year 3 

Pollutants 

Equip. 

Engines 

Unpaved 

Roads Total 

Equip. 

Engines 

Unpaved 

Roads Total 

Equip. 

Engines 

Unpaved 

Roads Total 

NOx 144.50 -- 144.50 145.10 -- 145.10 49.70 -- 49.70 

VOCs 17.00 -- 17.00 21.20 -- 21.20 6.70 -- 6.70 

SO2 7.24 -- 7.24 7.25 -- 7.25 2.48 -- 2.48 

CO 242.00 -- 242.00 284.00 -- 284.00 83.20 -- 83.20 

TSP NA 155.00 155.00 NA 70.00 70.00 NA 23.00 23.00 

PM10 5.10 48.10 53.20 5.20 23.10 28.30 1.80 6.50 8.30 

PM2.5 5.00 0.48 5.48 5.00 0.23 5.23 1.70 0.06 1.76 

HAPs 0.60 -- 0.60 0.60 -- 0.60 0.20 -- 0.20 

Note: 

NA = Not Applicable 

Emissions based on equipment hours of operation provided by FGS (Monday through Friday, with occasional Saturday use for 

some equipment) and appropriate emission factors for Tier II engines. 

VOC, CO, NOx, and PM emission factors were taken from EPA's Exhaust and Crankcase Emission Factors for Nonroad Engine 

Modeling-Compression-Ignition, Report No. NR-009c, April 2004; PM2.5 assumed equal to 97% of PM. 

SO2 emissions based on 0.05 % S Diesel and 100% conversion to SO2. SO2 gasoline emission factors are based on AP-42 

Table 3.3-1. SO2 emission factor = 5.91E-4 lb/hp-hr equivalent to 0.268 g/hp-hr. 

Diesel fuel use based on 14.75 hp-hr/gals. 

Gasoline emission factors from EPA AP-42 Section 3.3 Table 3.3-1 (EPA, 1996); PM2.5 assumed equal to 97% of PM. 

HAP emission factors were taken from Section 3.4 of EPA's AP-42 (EPA, 1996) 

Fugitive dust emissions from unpaved roads were calculated in accordance with EPA methods in AP-42, Section 13.2.2.2 (EPA, 

2006b); includes 60% emission control removal efficiency from water sprays. 

Operation of the proposed pipeline and ancillary facilities would not result in substantial 

air emissions under normal operating conditions. Typically, only minor fugitive 

emissions of natural gas occur from small connections at M&R stations and valve sites. 

Because such emissions are very small and discountable, they are not regulated by permit 

or source-specific requirements. 
4.0 – Environmental Analysis 4-62 

Table 4.11-3 

Summary of Air Emissions from Project Operations 

(Tons/Year) 

Pollutant 

WEG 

Heaters 

Regen 

Gas 

Heaters 

Amine 

System 

Heaters 

Emergency 

Generators 

Fire Water 

Pump 

Let Down 

Heaters 

Amine 

System 

Vent 

Cooling 

Tower Total 

PSD 

Significant 

Emission 

Rate 

PSD 

Review 

Required? 

SO2 5.6 0.1 0.32 0.85 0.019 0.68 NA NA 7.58 100 No 

Total PM 6.9 0.2 0.42 0.40 0.009 0.91 NA 2.0 11.00 100 No 

NOx 43.2 2.2 5.50 26.10 0.453 11.95 NA NA 89.00 100 No 

CO 77.5 1.9 4.70 2.10 0.028 10.03 NA NA 96.00 100 No 

VOC (as 

methane) 5.1 0.1 0.30 0.52 0.007 0.66 41 NA 48.00 100 No 

HAPs 0.1 2.83E-3 0.01 7.16E-02 1.62E-03 0.02 NA NA 0.22 NA No 

Notes: 

- NA - Not Applicable 

- The WEG heaters will employ Low NOx burners to achieve a NOx emission rate of 30 ppmvd, at 3 percent O2. 

- Natural gas fired equipment emissions based on EPA AP-42, Tables 1.4-1 and 1.4-2 (EPA, 1998). Total PM (condensable plus filterable) 

assumed less than one micrometer in diameter. 

- Diesel fired emergency equipment based on EPA, AP-42 Table 1.3-1 and 1.3-2 (EPA, 1998). VOC emissions from Amine System Vent was 

provided by equipment manufacturer. 

Source: Golder, 2007. 

Regulatory Requirements 

The Clean Air Act (CAA), 42 USC 7401 et seq., as amended in 1977 and 1990, is the 

basic federal statute governing air pollution. The provisions of the CAA that are 

potentially relevant to the Project include the following, which are discussed further 

below: 

• Air Quality Control Regions (AQCRs); 

• Prevention of Significant Deterioration (PSD); 

• New Source Performance Standards (NSPS); 

• National Emission Standards for Hazardous Air Pollutants 

(NESHAPs); 

• Title V Operating Permits; and 

• General Conformity. 

In addition, the Project would be subject to any applicable Florida state regulations that 

are more stringent than federal regulations. 

Air Quality Control Regions 

AQCRs are areas in which implementation plans describe how ambient air quality 

standards will be achieved and maintained. AQCRs were defined by EPA and state 

agencies in accordance with Section 107 of the CAA. The AQCRs are intra- and 

interstate regions such as large metropolitan areas where improvement of air quality in 

one portion of the AQCR requires emission reductions throughout the AQCR. The 

proposed Project would be in the Southeast Florida Intrastate AQCR as defined at 40 
4-63 4.0 – Environmental Analysis

CFR 81.49, which includes Broward, Dade, Indian River, Martin, Monroe, Okeechobee, 

Palm Beach, and St. Lucie counties in Florida. These eight counties are classified as 

attainment areas for all criteria pollutants for which EPA has made attainment 

designations. 

Prevention of Significant Deterioration 

The PSD regulations apply to proposed new major sources or major modifications to 

existing major sources located in an attainment area. The PSD regulations (40 CFR 

52.21) define a major source as any source type belonging to a list of 28 named source 

categories that emit or have the potential to emit 100 tons per year (tpy) or more of any 

regulated pollutant. A major source under PSD also can be defined as any source not on 

the list of named source categories with the potential to emit such pollutants in amounts 

equal to or greater than 250 tpy. 

The PSD review evaluates existing ambient air quality and the potential impacts of the 

proposed source on ambient air quality, noting in particular whether the source would 

contribute to any violation of the NAAQS, and reviews the best available control 

technology (BACT) to minimize emissions. The PSD regulations contain restrictions on 

the degree of ambient air quality deterioration that would be allowed. These increments 

for criteria pollutants are based on the PSD review classification of the area. Class I 

areas are specifically designated as pristine natural areas or areas of natural significance 

and receive special protections under the CAA because of their good air quality. If a new 

source or major modification is subject to the PSD program requirements and is within 62 

miles (i.e., 100 kilometers) of a Class I area, the facility is required to notify the 

appropriate federal officials and assess the impacts of the Project on the Class I area. 

Class II areas are designed to allow moderate, controlled growth. Class III areas allow 

for heavy industrial use. The Project would be located in a Class II area. The nearest 

Class I area, the Everglades National Park, is located approximately 100 miles south of 

the Project; therefore a full Class I analysis is not required. 

The WEG heaters are one of the 28 named source categories (i.e., Fossil Fuel Boilers (or 

combination thereof)) totaling more than 250 MMBtu/hr heat input. The Project would 

emit less than 100 tpy of any criteria pollutant at the LNG storage facility. Table 4.11-3 

summarizes the anticipated annual operational emissions from the LNG storage facility 

for each regulated pollutant, including NOx, CO, VOCs, PM10, SO2, and hazardous air 

pollutants HAPs. The net emissions from the LNG storage facility for each of the criteria 

pollutants would be less than the major source applicability thresholds; PSD permitting is, 

therefore, not applicable. The Project would be considered a “minor source” with regards 

to PSD review, and BACT or PSD (i.e., air dispersion) modeling would not be required. 

New Source Performance Standards 

The NSPS, codified at 40 CFR 60, establish emission limits, monitoring, reporting, and 

record keeping for specific source categories. The following NSPS requirements were 

identified as potentially applicable to the specified sources at the proposed LNG storage 

facility. 

Subpart Dc of 40 CFR 60.40c applies to steam generating units that have heat input 

capacities from fuels combusted in the steam generating unit of between 10 and 100 
4.0 – Environmental Analysis 4-64 

MMBtu/hr. The WEG heaters would be natural gas-fired with a design heat input rating 

of 98 MMBtu/hr; therefore, these units would be subject to the requirements of Subpart 

Dc. 

Subpart Kb of 40 CFR 60, Standards of Performance for Volatile Organic Liquid Storage 

Vessels, lists affected emission sources as storage vessels containing volatile organic 

liquids. Regulatory applicability is dependent on the construction date, size, and vapor 

pressure of the storage vessel and its contents. On October 15, 2003, EPA promulgated 

changes to 40 CFR Part 60, Subpart Kb that would exempt light oil tanks containing No. 

2 light oil by virtue of its vapor pressure; therefore, the diesel fuel tanks associated with 

the Project are exempt from NSPS Subpart Kb. 

The applicable NSPS for emergency generators and fire water pumps are codified in 40 

CFR 60 Subpart III, Standards of Performance for Stationary Compression Ignition 

Internal Combustion Engines. The format of the final standard is an output-based 

emissions standard for PM, NOx, CO, and non-methane hydrocarbons and is tiered based 

on model year. The Project would utilize emergency generators and a fire water pump 

that comply with the recently promulgated NSPS. 

National Emission Standards for Hazardous Air Pollutants 

The NESHAPs (40 CFR Parts 61 and 63) regulate HAP emissions from existing and new 

sources. The Project is not expected to operate any processes that are regulated by Part 

61. Part 63 establishes Maximum Applicable Control Technology standards for major 

sources of HAPs. Maximum Applicable Control Technology standards are intended to 

reduce emissions of airborne toxins or HAPs through installation of control equipment 

rather than enforcement of risk-based emission limits. Applicability is triggered if 

potential emissions are greater than 10 tpy of any single listed HAP or if total HAP 

emissions exceed 25 tpy for the listed HAPs. Table 4.11-3 indicates that the potential 

HAP emissions resulting from operation of the Project would be well below these 

thresholds; therefore, no Maximum Applicable Control Technology standards apply to 

the Project. 

Title V Permitting 

The Title V permit program, as described in 40 CFR 70, requires sources of air emissions 

with criteria pollutant emissions that reach or exceed major source levels to obtain federal 

operating permits. These permits list all applicable air regulations and include a 

compliance demonstration for each applicable requirement. The major source threshold 

level in attainment areas is 100 tpy of any regulated air pollutant, 10 tpy of any individual 

HAP, or 25 tpy for all HAPs. The Project would not exceed any of these criteria 

thresholds, as shown in Table 4.11-3; therefore, the Project would not require a Title V 

permit. 

General Conformity 

A conformity determination must be conducted by the lead federal agency if a federal 

action would generate emissions exceeding the conformity threshold levels (de minimis) 

of the pollutant(s) for which an air basin is designated as a nonattainment area or a 
4-65 4.0 – Environmental Analysis

maintenance area. Since the Project area is classified as in attainment for all criteria 

pollutants, a General Conformity Determination is not required. 

State Regulations 

The FDEP regulations require any new source to obtain an air permit prior to 

construction. Major new sources must meet the appropriate PSD requirements as 

discussed previously. Required permits and approvals for air pollution sources include 

PSD, NSPS, NESHAPs, Permit to Construct, and Permit to Operate. The requirements 

for construction permits and approvals are contained in Rules 62-4.030, 62-4.050, 62-

4.210, 62-210.300(1), and 62-212.400, Florida Administrative Code. Specific emission 

standards are set forth in Chapter 62-296. The Project is not subject to PSD or NESHAP 

regulations. On March 12, 2008, FDEP issued a minor source air construction permit for 

the FGS Project. 

Based on the above analysis, construction and operation of the FGS Project would not 

have a significant impact on air quality in the Project area; therefore, no additional air 

mitigation measures are proposed. 

Greenhouse Gas Emissions 

Combustion of fossil fuels during Project construction and operation would result in the 

emission of greenhouse gasses such as carbon dioxide (CO2), nitrous oxide, and methane. 

Greenhouse gas emissions are currently not subject to regulation in the United States. 

Although there are some regional initiatives to develop greenhouse regulations (i.e., the 

Regional Greenhouse Gas Initiative), none have been approved or would apply to the 

Project. 

Greenhouse gases are usually expressed in terms of carbon dioxide equivalents (CO2-e), 

where the potential of each gas to increase heating in the atmosphere is expressed as a 

multiple of the heating potential of CO2, or its global warming potential. Projected 

greenhouse gas emissions from Project construction and operation are provided in Tables 

4.11-4 and 4.11-5 respectively. 

Table 4.11-4 

Summary of Greenhouse Gas Emissions from Project Construction (Tons/Year)1

Greenhouse Gases (GHG) Year 1 Year 2 Year 3 

Carbon dioxide 6,429 6,513 2,206 

Nitrous oxide 0.2 0.2 0.1 

methane 0.4 0.4 0.1 

Total GHG emissions in CO2

equivalents (CO2-e)2 6,491 6,575 2,227 

Notes: 

1

 Greenhouse gas emissions (CO2, N2O, and CH4) were calculated based on emission factors taken from 

the Intergovernmental Panel on Climate Change Emission Factor Database: http://www.ipccnggip.iges.or.jp/efdb/find_ef.php. 

Gasoline emission factors for CO2 are based on EPA's AP-42 Section 3.3 Table 3.3-1 (EPA, 1996). 2

 Total GHG emissions in CO2 equivalents (CO2-e) were calculated based on the global warming potential 

of 1, 310, and 21 for CO2, N2O, and CH4, respectively (EPA, 2007). 
4.0 – Environmental Analysis 4-66 

Table 4.11-5 

Summary of Greenhouse Gas Emissions from Project Operations (Tons/Year)1

Greenhouse 

Gases (GHG) 

Amine 

System 

Vent3

Emergency 

Firewater 

Pump 

Amine 

System 

Heaters 

M&R 

Let 

Down 

Heater 

Regen. 

Gas 

Heaters 

WEG 

Heaters 

Emergency 

Generators Total 

Carbon dioxide 28,800 61 3,323 7,167 1,329 117,228 2,705 160,614 

Nitrous oxide NA 0.00030 142 306 57 5,003 0.013 5,508 

methane NA 0.00014 148 320 59 5,231 0.0063 5,758 

Total GHG 

emissions in CO2

equivalents (CO2-

e)2 28,800 61 50,401 108,713 20,160 1,778,063 2,710 1,988,909 

Notes: 1

 The Greenhouse gas emissions (CO2, N2O, and CH4) were calculated based on emission factors taken from U.S 

EPA AP-42 - Table 1.4-2 for natural gas combustion and Tables 1.3-2, 1.3-8, and 1.3-12 for diesel oil combustion 

(EPA, 1998) 

2

 Total GHG emissions in CO2 equivalents (CO2-e) were calculated based on the global warming potential of 1, 310, 

and 21 for CO2, N2O, and CH4, respectively (EPA, 2007). 3

 CO2 emissions from amine system vent is based on vendor information (5,000 lbCO2/hr) 

NA = data not available 

Although construction equipment (e.g., wheel loaders, trucks, cranes, pumps) would be 

powered by diesel or gasoline fuels, which generate higher greenhouse gas emissions 

compared to natural gas combustion, such impacts would be minor and temporary. FGS 

would maintain all construction equipment in accordance with manufacturer’s 

recommendations to minimize construction-related emissions. 

Project operation is likely to cause an overall net reduction of greenhouse gas emissions 

due to the increased availability of natural gas as a substitute for alternative fuels such as 

oil and coal that emit more CO2 per unit of energy. In addition, most of the operational 

equipment would burn natural gas during normal day-to-day operations, further 

mitigating CO2 and other greenhouse gas emissions in comparison to other fuels. 

4.11.2 Noise Quality 

Project construction and operation would affect ambient noise levels in the surrounding 

area. The ambient sound level of a region is defined by the total noise generated, 

including sounds from both natural and artificial sources. The magnitude and frequency 

of noise may vary considerably over the course of the day and throughout the week, in 

part due to changing weather conditions and the effects of seasonal vegetative cover. 

Two measurement metrics commonly used by federal agencies to relate the time-varying 

quality of environmental noise to its known effect on people are the 24-hour equivalent 

sound level (Leq(24)) and the day-night sound level (Ldn). The Leq(24) is the level of steady 

sound with the same total (equivalent) energy as the time-varying sound of interest, 

averaged over a 24-hour period. The Ldn is the Leq(24) with 10 decibels on the A-weighted 

scale (dBA) added to nighttime sound levels between the hours of 10 p.m. and 7 a.m. to 

account for people’s greater sensitivity to sound during nighttime hours. 
4-67 4.0 – Environmental Analysis

In 1974, EPA published Information on Levels of Environmental Noise Requisite to 

Protect Public Health and Welfare with an Adequate Margin of Safety. This document 

provides information for state and local governments to use in developing their ambient 

noise standards. The EPA determined that an Ldn of 55 dBA protects the public from 

indoor and outdoor activity interference. The FERC has adopted this criterion and 

generally uses it to evaluate the impact of new facilities on noise quality. Specifically, 

FERC limits sound levels attributable to new compressor facilities (e.g., liquefaction gas 

compressors associated with the LNG storage facility) to an Ldn of 55 dBA at any noise 

sensitive area (NSA) such as a school, hospital, or residence. 

Due to the 10 dBA nighttime penalty added prior to calculation of the Ldn, the 

actuaconstant noise level required to produce a Ldn of 55 dBA is 48.6 dBA Leq. Thus, for 

a facility to meet the Ldn 55 dBA limit, it must be designed such that actual noise levels 

do not exceed a constant hourly average of 48.6 dBA Leq at any identified NSA. 

The State of Florida does not have noise regulations applicable to the Project; however, 

Martin County has a countywide noise control ordinance that establishes daytime (7 a.m. 

to 9 p.m.) and nighttime (9 p.m. to 7 a.m.) sound level limits ranging from 55 to 70 dBA 

and 50 dBA to 65 dBA, respectively, for different receiving land use categories (e.g., 

institutional, residential, commercial, industrial, and agricultural). The Martin County 

ordinance prohibits any source from projecting noise across a real property boundary in 

such a manner as to create a sound level that exceeds the limits set forth for the receiving 

land use designation described above. 

4.11.2.1 Existing Noise Levels 

The Project would be located in a predominantly industrial and agricultural area. The 

nearest noise sensitive area (NSA) consists of three single-family residences (i.e., NSA 

#1) located approximately 0.46 mile south of the LNG storage facility boundary. 

Another single-family residence (i.e., NSA #2) is located approximately 6,500 feet (1.23 

miles) east of the Project on southwest Allapattah Road. No other NSAs were identified. 

Other potential NSAs, such as schools, hospitals, churches, playgrounds, farms, and 

camping facilities were too far away to be considered NSAs. 

Surveys were performed at the two NSAs and four property boundary sites (six site 

locations) to document ambient noise levels. Table 4.11-6 summarizes the existing sound 

levels and noise limits for the six monitoring site locations. 
4.0 – Environmental Analysis 4-68 

Table 4.11-6 

Existing Sound Levels and Noise Limits

FERC Sound Level 

Limits at NSA

Martin County 

Noise Limit for 

Residential Land 

Use at Property 

Boundary

Distance/ 

Direction 

of NSA to 

Storage 

Site (feet)

Measured L90

Daytime Ld 

(dBA)

Measured 

L90

Nighttime 

Ln (dBA)

Calculated 

Ldn (dBA) 

using 

Measured 

L90 Ldn (dBA)

LAeq

(dBA)

Ld

(dBA) Ln (dBA)

Northwestern Property 

Boundary (Site 1) -- 57 59 65 NA NA 60 55 

Northeastern Property 

Boundary (Site 2) -- 57 58 64 NA NA 60 55 

Southwestern 

Property Boundary 

(Site 3) -- 43 38 46 NA NA 60 55 

Southeastern Property 

Boundary (Site 4) -- 53 38 52 NA NA 60 55 

NSA # 1 (Site 5) 

2,450 – 

southeast 44 45 51 55 48.6 NA NA 

NSA #2 (Site 6) 6,500 – east 42 44 50 55 48.6 NA NA 

Notes: 

NA = not applicable 

NSA = noise sensitive area 

4.11.2.2 General Impacts and Mitigation 

Construction Noise 

Project construction would be typical of other pipeline and natural gas storage projects in 

terms of schedule, equipment used, mode of operation, length of time the equipment is in 

use, and amount of equipment used simultaneously. All of these factors would be 

constantly changing throughout the construction period; therefore, the quantification of 

impacts would fluctuate. Construction equipment would be operated on an as-needed 

basis, mostly during daylight hours, and would be maintained to manufacturers’ 

specifications to minimize noise impacts. The major noise sources associated with the 

construction activities include bulldozers, front-end loaders, and dump trucks. Extremely 

noisy activities such as pile driving would not be associated with the construction of the 

LNG storage facility, including the storage tank foundation. 

We used the CADNA-A noise model to evaluate construction noise effects at the four 

property boundary locations and at the two NSAs. Table 4.11-7 shows that total 

estimated Project construction plus ambient Ldn noise levels are below FERC’s sound 

level limit of 55 dBA at both NSAs. The predicted noise increase at NSA #1 and NSA 

#2 would be 1.1 dBA and 0.2 dBA, respectively. 

Noise levels that are less than 3 dBA above background levels are generally considered to 

be undetectable by the human ear for instantaneous measurements and for day-night 

levels (Ldn or DNL) within a quiet background of 60 - 65 dBA Ldn. For background noise 

levels of less than 60 dB Ldn, an increase of 5 dBA or more is considered to be a major 

change. For background levels greater than 65 dBA Ldn, an increase of 1.5 dBA or greater 

is considered a major change (FICON 1992). Since the predicted noise level increase at 
4-69 4.0 – Environmental Analysis

the nearest NSAs would be less than 2 dBA, and the background levels measured at the 

NSAs are less than 60 dBA, we anticipate that typical construction activities at the LNG 

storage facility would result in a small and insignificant effect on the noise environment. 

Although the predicted construction noise levels at two of the four property boundary 

sites would exceed the FERC benchmark of 55 dBA, the FERC standard only applies at 

NSAs, not at the property boundary. 

Table 4.11-7 

Predicted Construction Noise Impacts for the FGS Project 

Predicted Project 

Construction Noise Levels

Monitoring Site 

Location 

Distance/ 

Direction of 

NSA to LNG

Storage 

Facility (feet) 

Existing 

Ambient 

Ldn (dBA) 

Modeled LAeq 

(dBA)a

Calculated 

Ldn (dBA)b

Total 

Project Plus 

Ambient Ldn

(dBA)c

Predicted 

Noise 

Increase 

(dBA)d

Northwestern 

Property Boundary 

(Site1) 

-- 65 44.2 50.6 65.2 0.2 

Northeastern 

Property Boundary 

(Site 2) 

-- 64 42.9 49.3 64.1 0.1 

Southwestern 

Property Boundary 

(Site 3) 

-- 46 52.1 58.5 58.7 12.7 

Southeastern 

Property Boundary 

(Site 4) 

-- 52 65 71.4 71.4 19.4 

NSA # 1 (Site 5) 

2,450 

southeast 51 39.3 45.7 52.1 1.1 

NSA #2 (Site 6) 6,500 east 50 30.8 37.2 50.2 0.2 

Notes: 

a

 Average hourly noise levels, LAeq during Project construction were modeled using Datakustic's CADNA_A noise 

propagation model 

b

 Project construction Ldn = modeled steady LAeq plus 6.4 dBA. 

c

 Total Project construction plus ambient Ldn = 10 Log (10(Ambient Ldn/10) + 10(Project construction Ldn/10)). 

d

 Estimated increase in the ambient Ldn sound levels due to Phase 1 and Phase 2 construction. 

The noise impacts associated with construction activities would be temporary and FGS 

would ensure that the impacts do not exceed allowable levels by limiting nighttime 

construction activities to those that do not generate high noise levels. Construction 

activities, as authorized by a Martin County Building Permit, are considered exempt from 

the noise restrictions identified in the Martin County Noise Control Ordinance. In 

addition, the predicted noise impact levels are conservative because the model does not 

incorporate any reduction in noise levels due to intervening vegetation. 

Operational Noise 

Operation of the pipeline facilities would not adversely affect noise quality, since the 

pipeline would be installed underground and no compressor stations are proposed. 

Project operational noise effects would therefore be limited to the vicinity of the LNG 

storage facility. Principal noise sources would include WEG heaters, BOG compressors, 

vaporizers, air compressors, gas meters, and emergency generators (only used during 

power outages). Other equipment such as pumps and other compressors would not 
4.0 – Environmental Analysis 4-70 

produce significant noise. Equipment noise levels for the proposed facility are based on 

specifications provided by equipment manufacturers or actual field measurements. 

We used the CADNA-A model to estimate the noise impacts that would result from 

Project operations at the four property boundary locations and at the nearest NSAs (Table 

4.11-8). The noise model assumed all sources to be point sources and accounted for 

hemispherical spreading (i.e., a ground level noise source rather than an elevated source, 

such as an airplane), atmospheric attenuation, and soft ground attenuation. Table 4.11-8 

shows that total estimated Project operations plus ambient Ldn noise levels are below the 

FERC’s sound level limit of 55 dBA at both NSAs. The predicted noise increase at NSA 

#1 and NSA #2 would be 2.0 dBA and 0.3 dBA, respectively. 

Table 4.11-8 

Predicted Operating Noise Impacts for the FGS Project 

Predicted Project 

Operating Noise Levels

Monitoring Site 

Location 

Distance/ 

Direction of 

NSA to LNG 

Storage 

Facility (feet) 

Existing 

Ambient 

Ldn (dBA) 

Modeled LAeq 

(dBA)a

Calculated 

Ldn (dBA)b

Total 

Project 

Plus 

Ambient 

Ldn (dBA)c

Predicted 

Noise 

Increase 

(dBA)d

Northwestern 

Property 

Boundary (Site1) 

-- 65 49.8 56.2 65.5 0.5 

Northeastern 

Property 

Boundary (Site 2) 

-- 64 42.7 49.1 64.1 0.1 

Southwestern 

Property 

Boundary (Site 3) 

-- 46 58.1 64.5 64.6 18.6 

Southeastern 

Property 

Boundary (Site 4) 

-- 52 61.7 68.1 68.2 16.2 

NSA # 1 (Site 5) 

2,450 

southeast 51 42.4 48.8 53.0 2.0 

NSA #2 (Site 6) 6,500 east 50 32.3 38.7 50.3 0.3 

Notes: 

a

 Average hourly noise levels, LAeq during Project operation were modeled using Datakustic's CADNA_A noise 

propagation model 

b

 Project operation Ldn = modeled steady LAeq plus 6.4 dBA. 

c

 Total Project operations plus Ambient Ldn = 10 Log (10(Ambient Ldn/10) + 10(Project operation Ldn/10)). 

d

 Estimated increase in the ambient Ldn sound levels due to Phase 1 and Phase 2 operation. 

Since the predicted noise level increase at the nearest NSAs would not exceed 2 dBA, we 

anticipate that typical operations at the LNG storage facility would result in a small and 

insignificant effect on the noise environment. Because the LNG storage facility is 

expected to contribute a 19 dBA and 16 dBA noise increase at the southwestern and 

southeastern property boundary locations (Sites 3 and 4), respectively, FGS proposes to 

contain all major noise-generating equipment within shelters or enclosures to attenuate 

operational noise levels and ensure that noise impacts do not exceed Martin County 

standards. Other non-major noise-generating equipment, such as booster air compressor, 

would not be contained in outside shelters; however, the insignificant noise levels from 

the unsheltered equipment are not expected to impact nearby NSAs. 
4-71 4.0 – Environmental Analysis

Although this analysis is conservative in that it does not incorporate any reduction in 

noise levels due to intervening vegetation, we believe that the actual noise levels resulting 

from operation of the proposed LNG storage facility should be measured to ensure that 

they do not exceed those levels analyzed in this EIS. Therefore, we recommend that: 

• FGS should make all reasonable efforts to assure its predicted noise levels 

from the LNG storage facility are not exceeded at nearby NSAs and file noise 

surveys showing this with the Secretary no later than 60 days after placing 

the LNG storage facility in service. However, if the noise attributable to the 

operation of the LNG storage facility at full load exceeds an Ldn of 55 dBA at 

any nearby NSAs, FGS 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. FGS should confirm compliance with this requirement by 

filing a second noise survey with the Secretary no later than 60 days after it 

installs the additional noise controls. 

If FGS provides assurance that any noise impacts have been mitigated as required by the 

above recommendations, we believe that the Project-related operations would not result 

in a significant effect on the noise environment. 

4.12 RELIABILITY AND SAFETY 

The operation of the proposed Project poses a potential hazard that could affect public 

safety without strict design and operational measures to control potential accidents. The 

primary concerns are those events that could lead to an LNG spill of sufficient magnitude 

to create an offsite hazard. However, it is also important to recognize the stringent 

requirements for the design, construction, operation, and maintenance of the facility as 

well as the extensive safety systems to detect and control potential hazards. 

With the exception of the October 20, 1944 fire at the LNG facility in Cleveland, Ohio, 

the operating history of U.S. LNG facilities has been free of LNG safety-related incidents 

resulting in adverse effects to the public or the environment. The 1944 Cleveland 

incident was attributed to the use of materials inadequately suited for cryogenic 

temperatures and the lack of spill impoundments at the site.1

 An operational accident 

occurred in 1979 at the Cove Point LNG facility in Lusby, Maryland, when a pump seal 

failed, 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, resulting in heavy 

damage to the building and a worker fatality. Lessons learned from this accident resulted 

in changing the national fire codes, with the participation of the FERC, to ensure that the 

situation would not occur again. The proposed facilities would be designed, constructed, 

and operated in compliance with these codes. 

On January 19, 2004, a blast occurred at Sonatrach’s Skikda, Algeria LNG liquefaction 

facility that killed 27 and injured 56 workers. No members of the public were injured. 

 

1

 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. 
4.0 – Environmental Analysis 4-72 

Preliminary findings of the accident investigation suggest that a cold hydrocarbon leak 

occurred at Liquefaction Train 40 and was introduced to the high-pressure steam boiler 

by the combustion air fan. An explosion developed inside the boiler fire box 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 separation equipment of Train 40, and spread to Trains 20 and 30. 

Although Trains 10, 20, and 30 had been modernized in 1998 to 1999, Train 40 had been 

operating with its original equipment since start-up in 1981. 

Although there are major differences between the equipment involved in the accident to 

Skikda and that of the proposal by FGS (i.e., high-pressure steam boilers that power 

refrigerant compressors would not be used here nor are they used at any LNG facility 

under FERC jurisdiction), the sequence of cascading events identifies potential failure 

modes that warrant further evaluation. To ensure that all potential hazards are addressed, 

we have provided a recommendation Section 4.12.2, Front-End-Engineering Design 

Review, to address this issue. 

A discussion of the principal properties and hazards associated with LNG is presented in 

Section 4.12.1. A summary of our preliminary design and technical review of the frontend engineering design (FEED) and cryogenic aspects of the LNG facility is presented in 

Section 4.12.2. An analysis of the thermal radiation and flammable vapor cloud hazards 

used as siting criteria is presented in Section 4.12.3. LNG and NGL truck safety issues 

are examined in Section 4.12.4. Emergency response and evacuation planning is 

discussed in Section 4.12.5. A discussion on security awareness related to terrorism is 

presented in Section 4.12.6. The reliability and safety issues related to natural gas 

pipelines are discussed in Section 4.12.7. 

4.12.1 LNG Hazards 

LNG’s principal hazards result from its cryogenic temperature (-260°F), flammability, 

and vapor dispersion characteristics. As a liquid, LNG will neither burn nor explode. 

Although it can cause freeze burns and, depending on the length of exposure, more 

serious injury or death, its extremely cold state does not present a significant hazard to 

the public, which rarely, if ever, comes in contact with it as a liquid. As a cryogenic 

liquid, LNG will quickly cool materials it contacts, causing extreme thermal stress in 

materials not specifically designed for ultra-cold conditions. Such thermal stresses could 

subsequently subject the material to brittleness, fracture, or other loss of tensile strength. 

These hazards, however, are not substantially different from the hazards associated with 

the storage and transportation of liquid oxygen (-296°F) or several other cryogenic gases 

that have been routinely produced and transported in the United States. 

LNG vaporizes rapidly when exposed to ambient heat sources such as water or soil. 

When released from its containment vessel and/or transfer system, LNG will generally 

produce 620 to 630 standard cubic feet of natural gas for each cubic foot of liquid. A 

large quantity of LNG spilled without ignition would form a vapor cloud that would 

travel with the prevailing wind until it either dispersed below the flammable limits or 

encountered an ignition source. If a large quantity of LNG is spilled in the presence of an 
4-73 4.0 – Environmental Analysis

ignition source, the resulting pool fire would produce high levels of radiant heat in the 

area surrounding the LNG pool. 

A rapid phase transition (RPT) can occur when a portion of LNG spilled onto water 

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. The rapid expansion from 

the liquid to vapor state can cause locally large overpressures. RPTs have been observed 

during LNG test spills onto water. In some test cases, the events 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 estimated to be equivalent to 

several pounds of trinitrotoluene (TNT). The RPT may increase the rate of LNG pool 

spreading and the LNG vaporization rate for a spill on water. 

Methane vapors, the primary component of natural gas, are colorless, odorless, and 

tasteless, and are classified as a simple asphyxiant. Methane vapors may cause extreme 

health hazards, including death, if inhaled in significant quantities within a limited time. 

Although very cold methane vapors could cause freeze burns, any cloud resulting from an 

LNG spill would be continuously mixing with the warmer air surrounding the spill site. 

Dispersion modeling indicates the majority of the cloud would generally be within 25°F 

of the surrounding atmospheric temperature, with colder temperatures closest to the spill 

source. In addition, this modeling estimates that most of the cloud would be below 

concentrations resulting in oxygen deprivation effects, including asphyxiation, with the 

highest methane concentrations closest to the spill source. Therefore, asphyxiation and 

freezing normally represent a negligible risk to the public from LNG facilities. 

Although LNG will not burn, methane vapors in a 5 to 15 percent mixture by volume 

with air are flammable. Once a flammable vapor-air mixture from an LNG spill has been 

ignited, the flame front will propagate back to the spill site if the vapor concentration 

along this path is sufficiently high to support the combustion process. Combustible 

materials within the flammable portion of the cloud may be within the flame and could be 

ignited. However, any events leading to a containment failure would most likely be 

accompanied by a number of ignition sources. The result would be an LNG pool fire, 

and subsequent radiant heat hazards, rather than the formation of a large unconfined 

vapor cloud. 

Although LNG is not explosive as it is normally transported and stored, natural gas 

vapors (primarily methane) can explode if contained within a confined space, such as a 

building or structure, and ignited. Occasionally, various parties have expressed the 

energy content of an LNG storage tank in equivalent tons of TNT as an implied measure 

of its explosive potential. However, such a simplistic analogy fails to consider that 

explosive forces are not just a function of the total energy content but also of the rate of 

energy release. For a detonation to occur, the rate of energy release must be nearly 

instantaneous, such as with a TNT charge initiated by a blasting cap. Unlike TNT or 

other explosives, which inherently contain an oxidizer, an unconfined vapor cloud must 

be mixed with oxygen within the flammability range of the fuel for combustion to occur. 

For a large unconfined vapor cloud, the flammability range tends to exist at the mixing 

zone at the edges of the cloud. When ignited, flame speeds of about 20 to 25 meters per 
4.0 – Environmental Analysis 4-74 

second (66 to 82 feet per second) and local over pressures up to 0.2 psig have been 

estimated for unconfined methane-rich vapor clouds. These are well below the flame 

speeds and over-pressures associated with detonation. 

The potential for unconfined LNG vapor cloud detonations was investigated by the 

USCG in the late 1970s at the Naval Weapons Center at China Lake, California. These 

experiments, as well as other subsequent tests, are mentioned in Appendix C of the 

Sandia National Laboratories report entitled, Guidance on Risk Analysis and Safety 

Implications of a Large Liquefied Natural Gas (LNG) Spill Over Water, December 2004 

(Sandia Report). Using methane, the primary component of natural gas, several 

experiments were conducted to determine if unconfined vapor clouds would detonate. 

The tests indicated unconfined methane-air mixtures could be ignited, but no test 

produced unconfined detonation. There is no evidence suggesting that methane-air 

mixtures will detonate in unconfined open areas. 

Further tests were conducted in the late 1970s to examine the level of sensitivity of an 

unconfined cloud to the presence of heavier hydrocarbons such as ethane and propane. 

As stated in section 5 of Appendix C of the Sandia Report, detonation sensitivity is 

affected by the level of refinement of natural gas stored as LNG. The series of tests on 

ambient-temperature fuel mixtures of methane-ethane and methane-propane indicated 

that the addition of heavier hydrocarbons influenced the tendency of an unconfined vapor 

cloud to detonate. Less processed product with greater amounts of heavier hydrocarbons 

is more sensitive to detonation. During these experiments, all successful detonations 

were initiated with an explosive charge in well mixed vapor clouds at correct 

stoichiometric proportions. These are not representative of conditions that would be 

expected during a large scale LNG spill. The precise timing, necessary mixing, and 

required amount of initiating explosives render the possibility for detonation of a large 

unconfined vapor cloud as unrealistic. Detonation of the unconfined natural gas cloud is 

extremely difficult to achieve and is generally considered by scientists and researchers to 

be very unlikely to occur during an LNG spill. 

Consequently, the primary hazards to the public from an LNG spill either on land or 

water would be from dispersion of the flammable vapors or from radiant heat generated 

by a pool fire. 

4.12.2 Front-End Engineering Design Review 

Two federal agencies share in the oversight of the safety and security of LNG peakshaver 

and storage facilities: the FERC and DOT. The FERC authorizes the siting and 

construction of LNG facilities involved in interstate commerce and is the lead federal 

agency under NEPA to analyze the environmental safety, security, and cryogenic design 

of proposed facilities. The DOT has exclusive authority to promulgate and enforce safety 

regulations and standards over onshore LNG facilities. In 1980, the DOT established a 

set of safety standards, Liquefied Natural Gas Facilities: Federal Safety Standards, under 

Title 49, CFR, Part 193 which apply to the construction, operation, and maintenance of 

the on-shore LNG facilities. The FERC closely coordinates its pre-authorization review 

of proposals with the DOT to ensure a seamless safety and security review. 
4-75 4.0 – Environmental Analysis

As part of its application and in response to FERC staff’s data requests, FGS provided a 

FEED for the Project. The FEED and technical review emphasizes the engineering 

design and safety concepts, as well as the projected operational reliability of the proposed 

facilities. The principle areas of coverage include materials in cryogenic environments; 

insulation systems; cryogenic safety; thermodynamics; heat transfer; instrumentation; 

cryogenic processes; and other relevant safety systems. 

In the course of the application review, FERC staff has evaluated information for the 

proposed design and installation of the LNG storage facility. As a result of the technical 

review of the information provided by FGS in the submittal documents, a number of 

concerns were identified by FERC staff relating to the reliability, operability, and safety 

of the proposed design. In response to staff’s questions, FGS provided written responses 

prior to the technical conference held on February 20, 2008. However, 39 of FGS’s 

responses indicated that corrections or modifications would be made to the design in 

order to address issues raised in the information request. As a result, we recommend 

that: 

• FGS should provide information/revisions related to the 39 responses to the 

January 17, 2008 Engineering Information Request which stated that 

corrections, or modifications would be made to the design. The final design

should specifically address response numbers 4, 6, 7, 11, 17, 18, 21, 22, 24, 27, 28, 

29, 30, 33, 35, 36, 37, 38, 41, 42, 43, 49, 55, 58, 60, 61, 62, 63, 65, 67, 73, 76, 77, 78, 

80, 83, 91, 94, and 99 using management of change procedures. 

The FEED and specifications submitted for the proposed facilities are considered to be 

preliminary but would be the basis for any detailed design to follow. A significant 

amount of the design involving final selection of equipment manufacturers, process 

conditions, and resolution of some safety related issues would be completed in the next 

phase of project development if authorization is granted by the Commission. This 

information would need to be submitted to the FERC staff for review and approval. In 

addition, several areas of concern related to the LNG storage facility design and 

construction details have been noted and require additional consideration and/or action on 

behalf of the company. Follow up on those items requiring additional action should be 

documented in reports to be filed with the FERC. On May 5, 2008, FGS submitted 

comments to the engineering recommendations contained in the draft EIS. Responses to 

these comments are included in Appendix D and, where appropriate, the 

recommendations have been revised. As a result, we now recommend that: 

The following measures should apply to the FGS design and construction details. 

Information pertaining to these specific recommendations should be filed with the 

Secretary for review and approval by the Director of OEP either: prior to initial site 

preparation; prior to construction of final design; prior to commissioning; or prior 

to commencement of service as indicated by each specific condition. Specific 

engineering, vulnerability, or detailed design information meeting the criteria 

specified in Order No. 683 (Docket No. RM06-24-000), including security 

information, should be submitted as critical energy infrastructure information 

(CEII) pursuant to 18 CFR 388.112. See Critical Energy Infrastructure 

Information, Order No. 683, 71 Fed. Reg. 58,273 (October 3, 2006). FERC Stats. & 
4.0 – Environmental Analysis 4-76 

Regs. ¶ 31,228 (2006). Information pertaining to items such as: offsite emergency 

response; procedures for public notification and evacuation; and construction and 

operating reporting requirements would be subject to public disclosure. This 

information should be submitted a minimum of 30 days before approval to proceed 

is required. 

• Complete plan drawings and a list of the hazard detection equipment should be 

filed prior to initial site preparation. The list should include the instrument tag 

number, type and location, alarm locations, and shutdown functions of the 

proposed hazard detection equipment. Plan drawings should clearly show the 

location of all detection equipment. 

• FGS should provide a technical review of its proposed facility design that: 

a. identifies all combustion/ventilation air intake equipment and the distances 

to any possible hydrocarbon release (LNG, flammable refrigerants, 

flammable liquids and flammable gases); and 

b. demonstrates that these areas are adequately covered by hazard detection 

devices and indicate how these devices would isolate or shutdown any 

combustion equipment whose continued operation could add to or sustain an 

emergency. 

FGS should file this review prior to initial site preparation. 

• Complete plan drawings and a list of the fixed and wheeled dry-chemical, fire 

extinguishing, and other hazard control equipment should be filed prior to 

initial site preparation. The list should include the equipment tag number, type, 

size, equipment covered, and automatic and manual remote signals initiating 

discharge of the units. Plan drawings should clearly show the planned location 

of all fixed and wheeled extinguishers. 

• Facility plan drawings showing the proposed location of, and area covered by, 

each monitor, hydrant, deluge system, hose, and sprinkler, as well as piping and 

instrumentation diagrams of the fire water system, should be filed prior to initial 

site preparation. 

• FGS should perform a hazard design review, which addresses operability, 

reliability, and safety, of the updated intermediate process and instrumentation 

diagrams (P&IDs). A copy of the hazard design review, the list of 

recommendations that are to be incorporated in the final facility design, and the 

updated intermediate P&IDs should be filed prior to initial site preparation. 

• Drawings of the storage tank piping support structure and support of horizontal 

piping at grade should be filed prior to initial site preparation. 

• Procedures should be developed for offsite contractors’ responsibilities, 

restrictions, limitations and supervision of these contractors by FGS staff, prior 

to initial site preparation. 
4-77 4.0 – Environmental Analysis

• The final design should clearly and consistently show the design of the process 

systems on both the process flow diagrams (PFDs) and P&IDs. 

• The P&IDs in the final design should show and number all valves including 

drain, vent, main, and car sealed. 

• The final design should specify that the set pressure of PAH-11055 should not be 

greater than 50 psig below the design pressure of the system. 

• The final design should include layout provisions for the installation of an 

adsorber feed gas cooler and chiller system. 

• In the event that ceramic support material is used to retain the molecular sieve, 

the final design should include a witch hat type strainer at the bottom outlet of 

each adsorber, designed to retain support material. 

• The final design should include a shutoff valve at the inlet to the NGL extraction 

exchanger. This valve may be the proposed manual isolation valve equipped 

with an actuator operated by the Safety Instrumentation System (SIS). 

• The final design should include an isolation valve downstream of the ethylene 

pressure regulator. 

• The final design should include a hazard and operability review of the completed 

design. A copy of the review and a list of the recommendations should be filed 

with the Secretary. 

• The final design should specify that the LNG tank carbon steel piping support 

plates and connections to piping supports should be designed to ensure that 

corrosion protection is adequately provided and provisions for corrosion 

instrumentation diagrams of the fire water systems, should be filed prior to 

initial site preparation. 

• The final design of the tank foundation should include an inclinometer, 

instrumented to record and display tank settlement, with a minimum of eight 

permanent reference points equally spaced round the base for elevation survey 

measurement. 

• The final design should include details of the LNG tank tilt settlement and 

differential settlement limits between each LNG tank and piping and procedures 

to be implemented in the event that limits would be exceeded. 

• The final design should include detailed drawings of the spill control system to 

be applied to the LNG tank roof. 

• The final design should provide a discretionary vent for each LNG tank that can 

relieve the tank pressure when the tank is isolated from the boiloff vapor system. 

• The final design should include a recycle line from the top of the sendout pump 

suction header to storage. 
4.0 – Environmental Analysis 4-78 

• The final design should specify that the first isolation valve at the inlet to the 

sendout pumps would be a weld end shutoff valve. In the case that flanged 

valves would be specified, the sendout system should be shutdown in the event of 

a leak. 

• The final design should provide a minimum flow recycle line from the sendout 

pumps to the LNG storage tanks. The piping including the isolation valve 

upstream of the discharge to the storage tanks should be the same pressure and 

temperature rating as the piping at the discharge of the sendout pumps. 

• The final design should include provisions to drain and purge the LNG inlet 

piping to the vaporizer to a safe location. 

• The final design should specify that the LNG isolation valve from the inlet 

header to the vaporizer is to be a weld end shutoff valve operated by the SIS. In 

the case that flanged valves would be specified, the sendout system should be 

shutdown in the event of a leak. 

• The final design should specify the vaporizer discharge valve to the outlet header 

to be a weld end shutoff valve operated by the SIS. In the case that flanged 

valves would be specified, the sendout system should be shutdown in the event of 

a leak. 

• The final design should specify that the shell side of the LNG vaporizer is to be 

equipped with a full flow bursting disc sized for tube failure. 

• The final design should include provisions to transmit the flow measurement of 

the WEG solution to each LNG vaporizer to the distributed control system 

(DCS). 

• The final design should include provisions to limit the LNG flow to the effective 

vaporization capacity of the circulating WEG at any time. 

• The final design should include a pilot relief valve, or operated vent valve, sized 

for thermal relief and located at the discharge of each vaporizer upstream of the 

isolation valves. 

• The final design should include shutoff valves operated by the SIS at the suction 

and discharge of the boiloff, tail gas, and NGL compressors. 

• The final design should specify that manual bypass valves should be car sealed 

closed. 

• The final design should specify that all drains from LNG and refrigerant 

systems are to be equipped with double isolation and bleed valves. 

• The final design should specify that, for LNG and natural gas service, branch 

piping and piping nipples less than 50mm (2 inches), are to be no less than 

schedule 160. 
4-79 4.0 – Environmental Analysis

• The final design should include provisions to flare cryogenic and heavy 

hydrocarbon vapors currently shown as being discharged to atmosphere 

through the vent stack. 

• The final design should specify that the vent/flare stack separator vessel should 

be equipped with low level alarm, high level alarm and high-high level alarm. 

• The final design should specify that in the event that high-high level occurs in 

vent/flare stack separator vessel, the facility should be shut down until the liquid 

has been removed to below the low level alarm limit. 

• The final design should provide P&IDs, specifications and procedures that 

clearly show and specify the tie-in details required to safely connect the Phase 2 

expansion. 

• Layout and elevation drawings of the process equipment that are appropriate 

for the proposed operation and maintenance of the facility should be included in 

the final design and submitted to the FERC at the time that the EPC contractor 

issues the drawing for review. This milestone should be included in the project 

schedule. 

• The final design should specify that the hazardous area classification of the areas 

containing liquefaction exchangers, LNG pumps, LNG vessels, and inlet and 

outlet of LNG vaporizers would be as Class 1, Group D, Division 1. 

• The final design should include details of the air gaps to be installed downstream 

of all seals or isolations that are located 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 include audible and visual warning at buildings with 

instrument air service when nitrogen is supplied to the instrument air system. 

• The final design should provide automatic shutoff of the fuel gas to the fuel gas 

heaters, upstream of the pressure regulators. 

• The final design should include detection of flammable gas from the shell side 

vent of the LNG vaporizer and in the WEG system. Alarm and shutdown of 

equipment should be provided as appropriate. 

• The final design of the hazard detection equipment should identify 

manufacturer and model. 

• The final design should specify that all hazard detection equipment should 

include redundancy fault detection and fault alarm monitoring in all potentially 

hazardous areas and enclosures. 

• The final design of the fixed and wheeled dry-chemical, fire extinguishing and 

high expansion foam hazard control equipment should identify manufacturer 

and model. 
4.0 – Environmental Analysis 4-80 

• The final design should include an updated fire protection evaluation in 

accordance with the requirements of NFPA 59A 2001, chapter 9.1.2. 

• The final design should specify that multiple cameras should be installed to 

monitor the entry/exit gate and approach to the facility entrance. 

• The final design of the firewater system should include provisions to measure 

and record the discharge flow and pressure from each of the firewater pumps. 

• The final design should include an uninstalled spare firewater jockey pump. 

• The final design should include details of the shut down logic, including cause 

and effect matrices for alarms and shutdowns. 

• The final design should specify that all ESD valves are to be equipped with open 

and closed position switches connected to the DCS/SIS. 

• The final design should include emergency shutdown of equipment and systems 

activated by hazard detection devices for flammable gas, fire, and cryogenic 

spills, when applicable. 

• The maintenance procedures to be filed prior to commissioning should state that 

a foundation elevation survey of all LNG tanks should be made on an annual 

basis. 

• All valves including drain, vent, main, and car sealed, or locked valves should be 

tagged in the field during construction and prior to commissioning. 

• The car seal procedure and car seal control logs for all valves should be provided 

prior to commissioning. 

• A tabulated list of the proposed hand-held fire extinguishers should be filed 

prior to commissioning. The information should include a list with the 

equipment number, type, size, number, and location. Plan drawings should 

include the type, size, and number of all hand-held fire extinguishers. 

• Operation and Maintenance procedures and manuals, as well as emergency 

response plans and safety procedures, should be filed prior to commissioning. 

• The Operations and Maintenance procedures to be provided prior to 

commissioning, should state that filters are not to be opened unless the unit can 

be completely depressurized when isolated. 

• The contingency plan for failure of the LNG tank outer containment should be 

filed prior to commissioning. 

• A copy of the criteria for horizontal and rotational movement of the inner tank 

for use during and after cool down should be filed prior to commissioning. 

• The FERC staff should be notified of any proposed revisions to the security plan 

and physical security of the facility prior to commencement of service. 
4-81 4.0 – Environmental Analysis

• Progress on construction of the project should be reported in monthly reports

filed with the Secretary. Details should include a summary of activities, 

projected schedule for completion, problems encountered and remedial actions 

taken. 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 a biennial basis or more frequently as circumstances 

indicate. Prior to each FERC staff technical review and site inspection, FGS 

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 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 trucking, quantity and composition of feed gas 

and trucked LNG, vaporization quantities, boil-off/flash gas, etc.), plant 

modifications including future plans and progress thereof. Abnormalities 

should include, but not be limited to: trucking problems, 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, vapor 

or liquid releases, fires involving natural gas and/or from other sources, negative 

pressure (vacuum) within a storage tank and higher than predicted boiloff 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 the FERC staff with early notice of anticipated future 

construction/maintenance projects at the LNG facility. 

• FGS should include completed car seal control logs with the first two Semiannual operational reports filed with the Commission. 

• In the event the temperature of any region of any secondary containment 

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. 
4.0 – Environmental Analysis 4-82 

• Significant non-scheduled events, including safety-related incidents (i.e., LNG or 

natural gas releases, fires, explosions, mechanical failures, unusual over 

pressurization, and major injuries) and security related incidents (i.e., attempts 

to enter site, suspicious activities) should be reported to FERC staff. In the event 

an abnormality is of significant magnitude to threaten public or employee safety, 

cause significant property damage, or interrupt service, notification should be 

made immediately, without unduly interfering with any necessary or 

appropriate emergency repair, alarm, or other emergency procedure. In all 

instances, notification should be made to the Commission within 24 hours. This 

notification practice should be incorporated into the LNG facility's emergency 

plan. Examples of reportable LNG-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. free flow of LNG that results in pooling; 

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 gas or LNG; 

g. any crack or other material defect that impairs the structural integrity or 

reliability of an LNG facility that contains, controls, or processes gas or 

LNG; 

h. any malfunction or operating error that causes the pressure of a pipeline 

or LNG facility that contains or processes gas or LNG 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 an LNG facility that contains or processes gas or LNG 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 condition that could lead to a hazard and cause a 20 percent 

reduction in operating pressure or shutdown of operation of a pipeline or 

an LNG facility; 

l. safety-related incidents with LNG and NGL trucks 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. 
4-83 4.0 – Environmental Analysis

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, the Commission staff would determine the need for an on-site 

inspection by Commission staff, and the timing of an initial incident report 

(normally within 10 days) and follow-up reports. 

As part of the FEED, FGS performed a wind speed analysis using available wind speed 

historical data from 1950 to March 2007 to determine design wind conditions for the 

proposed site. FGS determined that the highest wind speed based on a 10,000-year return 

period storm event with a probability of exceedance of 0.01 percent would cause wind 

speeds for the proposed site of 118 mile per hour (mph). The storage tanks and control 

building would be designed to withstand sustained wind speeds up to 200 mph. However, 

the LNG Tank Data Sheet (1592609-000-TK-DS-2001) in FGS’ application also stated 

that a wind speed of 184 mph (3-second gust) would be used for the LNG storage tanks. 

This discrepancy was discussed at the cryogenic technical conference held on February 

20, 2008 and FGS agreed to correct the discrepancy in the final design through its 

management of change procedure. In addition, FGS would be designing all other 

facilities to withstand sustained wind speeds up to 130 mph. The wind design criteria 

were established in accordance with the wind velocity requirements of 49 CFR 193.2067. 

The terminal site elevations were established based on storm surge and flood elevation 

data available for Indiantown in Martin County, Florida. The site location is 

approximately 15 miles from any areas affected by storm zone flooding from a Category 

5 hurricane. FGS stated that the predicted storm surge height in Martin County due to a 

Category 5 hurricane would be nearly equivalent to the 500-year return storm at an 

elevation of approximately 13 feet. The proposed location of the FGS facility would be 

at an approximate elevation of 36 feet NGVD. All process areas and major equipment 

would be located at 38 feet NGVD. In addition, the tertiary earthen berm around the 

storage tanks and vaporization area would be constructed to an elevation of 43 feet 

NGVD. Since the proposed site would be at an approximate elevation of 36 feet NGVD, 

no storm surge effects would be likely at the proposed site. 

4.12.3 Siting Requirements – Thermal and Dispersion Exclusion Zones 

Regulatory Requirements 

The LNG facilities proposed in this project must comply with the siting requirements of 

49 CFR 193, Subpart B. On March 30, 2000, the DOT revised 49 CFR 193 to 

incorporate the 1996 edition of NFPA 59A into the LNG regulations. On April 9, 2004, 

the DOT further revised 49 CFR 193 to incorporate the 2001 edition of NFPA 59A. The 

following sections specifically address siting requirements: 

• 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 
4.0 – Environmental Analysis 4-84 

NFPA 59A, 2001 edition. In the event of a conflict with NFPA 59A, 

then Part 193 prevails. 

• Part 193.2057, 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, 2001 edition. 

• 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 Section 2.2.3.3 and 

2.2.3.4 of NFPA 59A, 2001 edition. 

• Part 193.2155(b), Structural requirements, requires that an LNG 

storage tank must be at least 1 mile from the ends of an airport runway 

and 0.25 mile from the nearest point on a runway. The proposed 

storage tanks would be located more than 13 miles from the William P. 

Gwinn private airport. 

For the following LNG facilities that are proposed in this project, we have identified the 

applicable siting requirements from Part 193 and NFPA 59A, 2001 edition: 

• Two 1,162,000 barrel (184,750 m3) full containment LNG storage 

tanks - Parts 193.2057 and 2059 require the establishment of thermal 

and flammable vapor exclusion zones for LNG tanks. NFPA 59A, 

2001 edition, Section 2.2.3.2 specifies four thermal exclusion zones 

based on the design spill and the impounding area. Sections 2.2.3.3 

and 2.2.3.4 specify a flammable vapor exclusion zone for the design 

spill which is determined in accordance with Section 2.2.3.5; 

• Six 2,100 gpm in-tank pumps (two per tank, two spares) and five 

1,800 gpm booster pumps (one spare) - Parts 193.2057 and 2059 

require thermal radiation and flammable vapor exclusion zones. 

NFPA 59A, 2001 edition, 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 spill; 

• Four shell and tube vaporizers each rated for 200 MMscfd - Same 

requirements as for LNG pumps; 

• Four liquefaction platefin heat exchangers each rated for 86.33 

MMBTU/hr – Same requirements as for the LNG pumps; 

• Two LNG truck loading stations – Same requirements as for the LNG 

pumps. 

The incorporation of the NFPA 59A requirements into Part 193 has resulted in some 

confusion and possible misinterpretation in applying the siting requirements. Parts 

193.2057 and 2059 require exclusion zones for LNG transfer systems, which are 

designed to include transfer piping. However, NFPA 59A only requires exclusion zones 

for “transfer areas,” which are defined as the part of the plant where liquids are 
4-85 4.0 – Environmental Analysis

introduced or removed from the facility, such as truck loading or where piping 

connections are connected or disconnected routinely. The definition of transfer area in 

NFPA 59A specifically excludes permanent plant piping or product sampling devices. 

When the DOT originally incorporated NFPA 59A into its regulations, it removed the 

requirement for impounding systems around transfer piping (old Part 193.2149). In the 

preamble to the final rule, the DOT determined that the most likely sources of leaks 

within an LNG plant are LNG storage tanks, cargo transfer areas, and vaporizers and 

process equipment, which are all addressed in NFPA 59A Section 2.2.1.2. The result is 

that while Part 193 requires exclusion zones for LNG transfer systems, neither Part 193 

nor NFPA 59A requires the impoundment from which to base the calculations. We do 

not believe that this was the intent, nor do we believe that omitting containment for 

transfer piping is a sound engineering practice. The FERC staff will continue to require 

containment for all LNG transfer piping within a plant site. 

The incorporation of NFPA 59A also changed the way in which design spills and 

impoundment capacities may be determined. Under Section 2.2.2.2, the capacity of 

impounding areas for vaporization, process, or LNG transfer areas must equal the greatest 

volume during a 10-minute period from any single accidental leakage source or during a 

shorter time period based upon demonstrable surveillance and shutdown provisions 

acceptable to the authority having jurisdiction. Similar criteria appear in Section 2.2.3.5 

for determining the design spill used in thermal and flammable vapor exclusion zone 

calculations. Prior to the incorporation of NFPA 59A, the design spill in Part 193 

assumed the rupture of a single transfer pipe with the greatest overall flow capacity for 

not less than 10 minutes (old Part 193.2059(d)). After the adoption of NFPA 59A, the 

spill rate for vaporization, process, or LNG transfer areas may be assumed to be a 

"leakage source" rather than a full pipe rupture; however, the spill duration must be 10 

minutes unless the authority having jurisdiction (i.e., DOT or PHMSA), determines that a 

shorter time is acceptable. Again, given the confusion in applying the two requirements, 

the FERC staff will continue to use the 10-minute spill criteria at the maximum flow 

possible for containment sizing. This will ensure that impoundments are sized for a 

catastrophic failure, while recognizing that less conservative spill scenarios may be 

appropriate to calculate exclusion zones. In giving recognition to the integrity of allwelded transfer piping, the determination of the single accidental leakage source should 

be based on an evaluation of all small diameter attachments to the transfer piping (e.g., 

instrumentation, pressure relief, recirculation), and any flanges that may be used at valves 

or other equipment, in order to determine the largest spill rate. This approach is the result 

of discussion with DOT concerning the basis for design spills and application to 

exclusion zone determinations for proposals before the Commission. 

Impoundment Systems and Design Spills 

Title 49, CFR, Part 193.2181 specifies that the impoundment system serving a single 

LNG storage tank must have a volumetric capacity of 110 percent of the LNG tank’s 

maximum liquid capacity. FGS proposes two full containment LNG storage tanks (Tank 

T-1001 and T-1002) in which the outer tank wall serves as the impoundment system. 

Each LNG storage tank’s maximum liquid capacity would be 52,401,854 gallons. The 

outer tank would have an impounding volumetric capacity of 59,211,917 gallons, which 
4.0 – Environmental Analysis 4-86 

exceeds the 110 percent requirement by 1,569,878 gallons when accounting for the 

volume of perlite in the annular space. 

In addition, FGS proposes to construct a tertiary earthen berm around the perimeter of the 

LNG tanks and vaporization area. The structure would be constructed to an elevation of 

seven feet above the finished grade level and would enclose an area of approximately 27 

acres. After accounting for the estimated space occupied by features inside the berm, the 

available volume would be 56,954,184 gallons. This tertiary earthern berm would 

confine LNG on the project site in the event of any hypothetical catastrophic event. 

Potential spills occurring from piping to and from the storage tanks and piping serving 

the vaporization area would be contained in concrete curbing that slopes towards the 

concrete transmission troughs to the sendout spill sump. In accordance with Section 

2.2.3.5 of NFPA 59A, 2001 edition, the design spill for an LNG storage tank with overthe-top fill and no penetrations below the liquid level is defined as the largest flow from 

any single line that could be pumped into the impounding area with the tank withdrawal 

pumps considered to be operating at full rated capacity over a 10-minute period. For the 

proposed design, this would be a guillotine rupture of the 14-inch-diameter in-tank pump 

common withdrawal header. Each LNG storage tank would be equipped with three intank pumps (two operating, one spare) individually rated for 2,111 gpm. With two 

pumps operating for two storage tanks, the volume for a 10-minute spill from the in-tank 

pump withdrawal header would be 97,110 gallons. FGS also included a contingency of 

15 percent to account for increased pump run out flow after the line break. The sendout 

spill sump would be 50-feet-long by 50-feet-wide and 6-foot-deep. The total 

containment capacity would be 112,208 gallons. Therefore, any potential spills from the 

14-inch-diameter in-tank pump common withdrawal header would be contained in the 

sendout spill sump located within the berm surrounding the tank area. 

Any potential spills from the transfer piping between the pretreatment/liquefaction area 

and the storage tanks and between the storage tanks and truck station would be captured 

by the truck station and process area sump. The largest potential spill would be from the 

4-inch-diameter truck station liquid fill line from the LNG storage tanks, corresponding 

to a 10-minute spill volume of 13,686 gallons. The truck station and process area sump 

would be 21-feet-wide by 21-feet-long by 6-feet-deep, with an impoundment capacity of 

19,793 gallons. The truck station and process area sump would be capable of containing 

a full rupture of the truck station fill line piping for 10 minutes. 

Table 4.12-1 presents the impoundment sizes and design spill volumes used in the 

thermal radiation and flammable vapor dispersion modeling. 
4-87 4.0 – Environmental Analysis

Table 4.12-1 

Impoundment Areas 

Source Spill Size 

(gallons) Impoundment System Impoundment Size (gallons)

Impoundment Sizing Spills:

LNG Storage Tank 52,401,854 Outer concrete tank 59,211,917 

In-Tank Pump Withdrawal 

Header - 14-inch line 97,110 Sendout spill sump 112,208 

Truck Station Liquid Fill 

Line- 4-inch line 13,686 

Truck station and process 

area sump 19,793* 

NGL Storage Vessel 

Discharge Line - 4-inch line 89,216 NGL spill sump 90,888 

Design Spills:

In-Tank Pump Withdrawal 

Header 97,110 Sendout spill sump 112,208 

Truck Station Liquid Fill Line 

- 4-inch connection 13,686 

Truck station and process 

area sump 19,793* 

NGL Vessel Discharge Line 

- 4-inch connection 89,216 NGL spill sump 90,888 

*Pretreatment/liquefaction area and truck loading area share a common impoundment system.

FGS proposes to install a natural gas liquids (NGL) storage system that would be 

constructed in accordance with all applicable design codes and standards, including 

NFPA 58 Liquefied Petroleum Gas Code. The NGL storage system would consist of two 

60,000-gallon horizontal pressurized storage vessels for Phase 1. Phase 2 would include 

two additional 60,000-gallon horizontal pressurized storage vessels. The stored NGLs 

would consist of heavy hydrocarbons (primarily n-butane, propane, and hexane) removed 

from the feed gas prior to the liquefaction process. 

The NGL extraction system would be designed to remove high molecular weight 

components typically present in the feed gas. During normal operations, FGS would reinject NGLs back into the sendout gas to meet pipeline tariff requirements and for BTU 

adjustment. However, during the aftermath of a hurricane or other natural gas supply 

interruption, excessive high molecular weight components would be present in the feed 

gas. Therefore, FGS proposes to install a NGL storage system to accommodate the 

additional NGLs that would accumulate during an upset condition. In addition, FGS 

proposes to use a NGL truck loading station to remove the excessive NGLs stored on-site. 

At the cryogenic technical conference held on February 20, 2008, FGS indicated it was 

considering revising the design to mound the NGL storage vessels. On May 5, 2008, 

FGS filed a response to the draft EIS recommendation requesting information on whether 

the NGL storage vessels would be installed as proposed in the application or whether the 

vessels would be mounded. FGS also indicated in that response one 12,000-gallon 

propane vessel and one 2,000-gallon iso-pentane vessel would be mounded. These 

vessels are part of the MR cycle that would be used in the liquefaction system as 

discussed in Section 2.1.1.1 of the EIS. All vessels would be buried or mounded in 

accordance with the mounding requirements specified in Section 3.2.9 of the NFPA 58 
4.0 – Environmental Analysis 4-88 

Liquefied Petroleum Gas Code and enclosed within concrete retaining walls. A concrete 

floor would be cast inside the retaining walls to provide containment of the contents of 

any spills from the vessels. A drainage system would be provided to evacuate water from 

the mounded earth and direct the flow into the NGL spill sump. 

The NGL spill sump would be located at the lowest drainage point within the curbed area 

around the NGL storage vessels. The NGL spill sump would be 45-feet-wide by 45-feetlong by 6-feet-deep, with an impoundment capacity of 90,888 gallons. 

On May 29, 2008, FERC issued a data request to FGS requesting a description of how the 

mounded vessels would be protected against corrosion and a description of the 

maintenance and inspection procedures for the mounded vessels. On June 18, 2008, FGS 

responded to the data response and proposed to protect the vessels against external 

corrosion by using a paint system that satisfies the requirements of the National 

Association of Underground Corrosion Engineers (NACE). In addition, the vessels 

would be designed with a cathodic protection system. FGS stated that more details of the 

coatings and cathodic protection system would be provided during the final design. FGS 

also stated that the vessels would have a maintenance program of periodic inspection and 

written procedures would be developed in the event that the vessel(s) would need to be 

removed for further evaluation or repair. Therefore, we recommend that: 

• The final design should include drawings, P&IDs, and specifications for the 

mounding system and the coatings and cathodic protection system for the 

vessels. 

Thermal Radiation Exclusion Zone 

If a large quantity of LNG is spilled in the presence of an ignition source, the resulting 

pool fire would produce high levels of radiant heat in the area surrounding the 

impoundment. Exclusion distances for various flux levels were calculated according to 

49 CFR 193.2057 and Section 2.2.3.2 of NFPA 59A, 2001 edition, using the "LNGFIRE 

III" computer program model developed by the Gas Research Institute. NFPA 59A, 2001 

edition, establishes certain atmospheric conditions (0 mph wind speed, 70°F, and 50 

percent relative humidity), which are to be used in calculating the distances. However, 

Part 193.2057 supersedes these requirements and 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. For its analysis, FGS selected the following ambient conditions to 

produce the maximum distances: wind speed of 18.7 mph; ambient temperature of 66°F; 

and 50 percent relative humidity. These conditions yield longer distances than the 0 mph 

wind speed, 70°F ambient temperature, and 50 percent relative humidity specified in 

NFPA 59A, 2001 edition. FERC staff agrees with FGS’s selection of atmospheric 

conditions. 

Under Title 49, Code of Federal Regulations, Section 193.2057, the LNG storage tank 

impoundment must have a thermal exclusion zone in accordance with NFPA 59A, 2001 

edition. The referenced Section 2.2.3.2 of NFPA 59A, 2001 edition, requires thermal 

radiation distances ranging from 1,600 to 10,000 British thermal units per square foot per 
4-89 4.0 – Environmental Analysis

hour (Btu/ft2-hr) to be calculated for a volume of LNG determined in accordance with 

Section 2.2.2.1. 

Thermal radiation distances calculated for 1,600 to 10,000 Btu/ft2

-hr incident flux levels 

for an LNG storage tank impoundment fire were based on the outer tank’s concrete wall 

diameter (280 feet) as the pool diameter and the flame height equal to the top of the 

concrete wall (133 feet). The target height was set at ground level (0 feet). The resulting 

distances would be 401 feet for the 10,000 Btu/ft2-hr zone; 742 feet for the 3,000 

Btu/ft2-hr zone; and 951 feet for the 1,600 Btu/ft2-hr- zone (see Figure 4.12-1). The 

exclusion zones for the 1,600 and 3,000 Btu/ft2-hr incident fluxes from the storage tanks 

would extend beyond the property line of the site onto a five (5) acre double-lined landfill 

(referred to as the “vault”) containing remediated soil as discussed in Section 4.7.5. The 

vault is owned by Gerdau Ameristeel US Inc. On April 7, 2007, FGS entered into an 

option agreement with Ameristeel restricting the use or occupancy of the landfill vault in 

any manner that would conflict with the prohibited uses under the provisions of NFPA 

59A, 2001 edition. Therefore, the thermal exclusion zones for an LNG storage tank 

impoundment fire would remain on the site, with the exception of the landfill vault, and 

would be in compliance with 49 CFR 193.2057. 

The thermal radiation distances were determined for 1,600 Btu/ft2

-hr incident flux levels 

centered on the sendout spill sump, truck station and process area sump in accordance 

with 49 CFR 193.2057. The 1,600 Btu/ft2

-hr flux level would extend 274 feet from the 

center of the sendout spill sump and 137 feet from the center of the truck station and 

process area sump. These zones would not extend beyond the property line of the site. 

Therefore, the thermal exclusion zones would remain on the site and would be in 

compliance with 49 CFR 193.2057. 

 
Land Vault 

Property Line

1,600 BTU/sq.ft.-hr level

3,000 BTU/sq.ft.-hr level

10,000 BTU/sq.ft.-hr level

0 305 610 1,220

Feet

Figure 4.12-1

FGS Project

Thermal Radiation Exclusion Zones

Legend

Storage Facility Site

Thermal Radiation Exclusion Zones for LNG Tanks

4-90
4-91 4.0 – Environmental Analysis

Although LNGFIRE III is specifically designed to calculate thermal radiation flux levels 

for LNG pool fires, LNGFIRE III was used by FGS to calculate the thermal radiation 

distance for the 1,600 Btu/ft2

-hr incident flux level for the NGL spill sump. The 1,600 

Btu/ft2

-hr flux level would extend 251 feet from the center of the NGL spill sump. This 

thermal radiation distance would not extend beyond the property line of the site. The 

potential for high levels of radiant heat in the area surrounding the impoundment would 

be minimized in the event that FGS decides to mound the NGL storage vessels. 

Table 4.12-2 presents the calculated maximum distances for thermal radiation flux levels 

ranging from 1,600 to 10,000 Btu/ft2

-hr, as verified by FERC staff. 

Table 4.12-2 

Thermal Radiation Exclusion Zones 

Source Exclusion Area 

NFPA 59A Section 2.2.3.2(a) 

Incident 

Flux 

(Btu/ft2-hr) 

a/ 

Exclusion 

Zone (feet) 

b/ 

LNG Storage Tank 

Impoundment 

Outdoor assembly area occupied by 50 or more 

people. 1,600 951 

LNG Storage Tank 

Impoundment 

Off-site structures used for occupancies or 

residences. 3,000 742 

LNG Storage Tank 

Impoundment Property line that can be built upon. 10,000 401 

Sendout Spill Sump Property line that can be built upon 1,600 274 

Truck Station and 

Process Area Sump Property line that can be built upon 1,600 137 

a/ The 1,600 Btu/ft2-hr flux level is associated with an exposed person experiencing burns within about 30 

seconds. At 3,000 Btu/ft2

-hr, an exposed person would experience burns within 10 seconds; however, a 

wooden structure would not be expected to burn and affords protection to sheltered persons. At 10,000 

Btu/ft2

-hr, clothing and wood can ignite spontaneously. 

b/ Exclusion zone distances are measured from the center of the impoundment. For rectangular sumps, 

the longest exclusion zone distance is listed. 

Vapor Dispersion Zone 

A large quantity of LNG spilled without ignition could form a flammable vapor cloud 

that would travel with the prevailing wind until it either dispersed below the flammable 

limits or encountered an ignition source. Sections 2.2.3.3 and 2.2.3.4 of NFPA 59A, 

2001 edition, and Part 193.2059 require that provisions be made to minimize the 

possibility of flammable vapors from reaching a property line that can be built upon and 

that would result in a distinct hazard. Part 193.2059 requires that dispersion distances be 

calculated for a 2.5 percent average gas concentration (one-half the lower flammability 

limit of LNG vapor) under meteorological conditions that result in the longest downwind 

distances at least 90 percent of the time. Alternatively, maximum downwind distances 
4.0 – Environmental Analysis 4-92 

may be estimated for stability Class F, a wind speed of 4.5 mph, 50 percent relative 

humidity, and the average regional temperature. The section allows the use of the 

DEGADIS Dense Gas Dispersion Model, or the FEM3A model, to compute dispersion 

distances. Design spills into impounding areas serving LNG containers, transfer systems 

and piping are to be determined in accordance with Section 2.2.3.5 of NFPA 59A, 2001 

edition. In accordance with Section 2.2.3.3 of NFPA 59A, 2001 edition, an average 

concentration of methane in air of one-half of the lower flammability level cannot cross 

the property line from a design spill into each tank impoundment. In this case, 

compliance with Section 2.2.3.3 would also meet the requirements of Section 2.2.3.4 of 

NFPA 59A, 2001 edition. 

In performing the vapor dispersion analysis required by 49 CFR 103.2059, FGS selected 

a wind speed 4.5 mph, an atmospheric temperature of 85°F, a relative humidity of 50 

percent, and atmospheric Stability Class F. FGS selected the largest design spill that 

would be directed to the sendout spill sump based on a guillotine failure of the 14-inchdiameter in-tank pump common withdrawal header. This design spill rate would be 

9,711 gallons per minute. For this design spill rate, FGS calculated a distance of 298 feet 

to the 2.5 percent average gas concentration isopleths. Based on historical weather data, 

FERC selected an atmospheric temperature of 75°F to predict the longest downwind 

flammable vapor dispersion distance for all sumps. FERC staff performed a vapor 

dispersion analyses for the sendout spill sump using SOURCE5 and DEGADIS. A 

distance of 326 feet to the 2.5 percent average gas concentration isopleths was calculated 

(Figure 4.12-2). However, the flammable vapor exclusion zone associated with the 

sendout spill sump would still remain within the facility property. 

FGS selected a spill that would be directed to the truck station and process area spill 

sump based on complete failure of the 4-inch-diameter truck station fill line. The spill 

rate from this line would be approximately 1,369 gpm. Using this spill rate, FGS 

calculated a distance of 121 feet to the 2.5 percent average gas concentration isopleths. 

FERC staff also used SOURCE5 and DEGADIS to verify the vapor dispersion distances 

for the truck station and process area spill sump. A distance of 128 feet to the 2.5 percent 

average gas concentration isopleths was calculated. This exclusion zone associated with 

the truck station and process area sump would remain on-site. Based on our review, the 

proposed LNG facility location would satisfy the vapor exclusion zone requirements of 

49 CFR 193.2059. 

FGS selected a spill that would be directed to the NGL spill sump based on complete 

failure of the 4-inch-diameter discharge line from the NGL storage vessel. The 

corresponding spill rate would be approximately 8,922 gpm. FGS assumed since the 

NGLs are denser than air, the resulting vapors would stay very low to ground level and 

spread width–wise. As a result, FGS approximated the furthest distance that the cloud 

would travel to be 406 feet. FERC staff performed a similar vapor dispersion analysis 

using SOURCE5 and DEGADIS for the NGL spill using the same spill rate. Properties 

of n-butane were used to simulate NGL. This spill would result in a calculated distance 

of 394 feet to the 2.5 percent average gas concentration isopleths, which is comparable to 

FGS’ results. This vapor dispersion distance associated with the NGL spill sump would 

remain on-site. The potential for the formation of a flammable vapor cloud would be 

minimized in the event that FGS decides to mound the NGL storage vessels. 
Land Vault

Property Line

Sendout Spill

Sump Exclusion

Zone

Truck Station and 

Process Area Spill 

Sump Exclusion Zone

0 260 520 1,040

Feet

Figure 4.12-2

FGS Project

Vapor Dispersion Exclusion Zones

Note: Vapor dispersion exclusion zones are the distance to the 

1/2 lower flammability limit of methane.

Legend

Storage Facility Site

Vapor Dispersion Exclusion Zones

4-93
4.0 – Environmental Analysis 4-94 

Although the impoundment system technically complies with 49 CFR 193.2059, the issue 

of the lengthy distance from potential spill locations to the sumps needs to be addressed. 

As a result, the control of vapors produced in the channels or trenches leading to these 

sumps must be considered. Long trenches increase the surface area available for heat 

transfer and, correspondingly, increase vapor generation. 

On September 27, 2007, FERC issued a data request to FGS requesting detailed vapor 

production rate (source strength) and vapor dispersion calculations for the trenches. On 

February 15, 2008, FGS responded to the data request with a report entitled, “Vapor 

Generation and Flammable Dispersion Modeling of LNG Releases in the Floridian Gas 

Storage Facility.” The report, prepared by Quest Consultants Inc., provided vapor 

production rates and dispersion calculations for wind blowing from west to east, and 

south to north, for the following LNG spill scenarios: 

1. LNG spill from the 14-inch-diameter in-tank pump withdrawal header at a 

volumetric flow rate of 9,711 gpm into a 3-ft wide by 2-ft deep trench; 

2. LNG spill from the truck loading piping located inside the tertiary earthen 

berm at a volumetric flow rate of 1,366 gpm into a 3-ft wide by 2-ft deep 

trench. In addition, a LNG spill from the truck loading piping outside the 

tertiary earthen berm based on the same volumetric flow rate into a 2-ft wide 

by 1-ft deep trench was modeled; and 

3. LNG spill at the process area at a volumetric flow rate of 1,190 gpm into a 2-

ft. wide by 1-ft deep trench. 

However, the report did not justify the trench geometry and LNG flow velocity 

assumptions that were used to calculate the vapor production rate for the LNG releases 

listed above. For scenario 1, the flow velocity was determined by assuming the depth of 

flow was equal to the trench height. For scenarios 2 and 3, the depth of flow was 

determined using the flow velocity established for scenario 1 rather than with the spill 

rate, geometry, and slope associated with those trenches. This approach assumes that the 

LNG flow velocity calculated for scenario 1 would be the same for all trenches even 

though the trench geometry and design spill flows are different. Additionally, FGS 

referenced the 1974 Arthur D. Little report, “Evaluation of LNG Vapor Control 

Methods,” but did not provide the calculations demonstrating the methodology used to 

determine the vapor production rates. As a result, we recommended in the draft EIS that 

FGS revise the vapor production calculations to reflect LNG flow velocities and LNG 

liquid heights consistent with those that were calculated when sizing the trenches and to 

provide the calculations showing how the vapor production rate from a single trench 

element over a 10 minute period were determined. On May 5, 2008, FGS responded with 

the supplementary report to their original February 15, 2008 report. The report provided 

revised vapor production calculations, as requested, and provided some information 

regarding the methodology to determine the vapor production rate. The variations in the 

vapor production rates using the revised LNG velocities and LNG heights within the 

trenches were small compared to the previously calculated vapor production rates in the 

February 15, 2008 report and therefore no significant difference in the downwind 

distance to the 1⁄2 LFL would be expected. However, the vapor production rate 

methodology used in the reports produced vapor production rates that are approximately 
4-95 4.0 – Environmental Analysis

one-half that of other applications with similar spill rates and trench configurations. 

FGS’ information pertaining to the methodology still did not provide step-by-step 

calculations showing how the vapor production rates were determined. As a result, 

FERC staff issued a data request on May 29, 2008, requesting more information on some 

of the assumptions for the vapor production rate calculations and for the technical 

justifications for those assumptions. On June 18, 2008, FGS responded with information 

pertaining to some of the assumptions in the methodology; however the information 

provided still did not clarify the step-by-step calculation methodology showing how the 

vapor production rates were calculated. As a result, we recommend that: 

• FGS should file with the Secretary, for review and approval by the Director 

of OEP, step-by-step calculations showing how the vapor production rate 

from a single trench element over a 10 minute period was determined, prior 

to initial site preparation. 

Using the source strength calculations, FGS employed the Fire Dynamics Simulator 

(FDS) Version 5.0 to simulate the vapor dispersion distances. Although, the results of 

the report indicated that the flammable vapors would remain within the facility property, 

FGS did not provide justification for the meteorological conditions used in the vapor 

dispersion modeling. In addition, similar dispersion modeling efforts have indicated that 

longer dispersion distances may result when the wind direction is opposite to the LNG 

flow direction, which in this case, would be in a north to south direction. FGS also did 

not provide the input files for FERC staff’s review or a grid sensitivity analysis that 

demonstrates the convergence of the downwind dispersion distances. As a result, FERC 

staff recommended in the draft EIS that FGS should provide: 1) justification for the 

selected weather conditions, and subsequently revise the vapor dispersion calculations, as 

appropriate, 2) provide a third simulation for wind blowing from north to south towards 

the property line for the spill at the process area, 3) provide a grid sensitivity analysis 

demonstrating that the results converge, and 4) provide the input files and output files 

used to determine the downwind dispersion distances for FERC review. 

On May 5, 2008, FGS submitted a report that concluded that the vapor dispersion 

distances were insensitive to weather conditions. The report did not provide any 

quantitative results to demonstrate that the solution converges. Additionally, FERC staff 

noted several concerns in the submitted input files for the FDS simulations. Therefore, 

on May 29, 2008, FERC staff issued an additional data request regarding the concerns in 

the submitted input files for the FDS simulations. 

The input files indicated the use of “open” boundaries along the direction of flow/wind 

(sides and top) in the simulations. It has been shown that prescribing open boundaries 

will cause artificial mixing and subsequent dilution near those boundaries. FGS 

maintains that prescribing a “mirror” boundary condition will produce idealized 

“smooth” clouds since this forces the wind profile to remain laminar and no terrain 

elements are represented that would, in reality, generate turbulence in the domain. 

FERC staff does not agree with this approach. The prescription of “open” boundary 

conditions at the boundaries parallel to the flow/wind (top and sides) will cause artificial 

mixing near those boundaries that may greatly reduce and/or limit the dispersion 

distances close to the boundaries. Since the boundaries are specified at locations 
4.0 – Environmental Analysis 4-96 

representative of the facility property line, this may essentially prevent vapors from ever 

exceeding the property line. FERC’s recommendation to mitigate this artificial mixing 

near the boundary conditions is consistent with recommendations made by Sandia in the 

report, “Review of the Independent Risk Assessment of the Proposed Cabrillo Liquefied 

Natural Gas Deepwater Port Project” (Cabrillo Report), which evaluated the use of the 

same model, FDS, for determining dispersion distances in the Cabrillo Deepwater Port 

Project. The Cabrillo Report was also referenced in the FGS submittal. Additionally, the 

ingress of LNG vapors into the domain was initiated before the wind profile reached a 

quasi-steady state, which could cause excess mixing and dilution. FGS stated that Quest 

conducted internal sensitivity analyses showing that the effect of initial wind speed is 

minor at the low wind speeds used for this analysis. However, FGS did not provide this 

internal sensitivity analysis. Furthermore, other submittals, including others prepared by 

Quest, have consistently allowed the wind profile to reach a steady or quasi-steady state 

before injecting LNG vapor into the domain. This recommendation is also consistent 

with the recommendations made in the Cabrillo Report. 

Another concern that affects the wind profile is the effect of the slip factor on the 

“ground” or “bottom” boundary condition. The slip factor is not specified for the ground 

boundary condition, resulting in a default value of 0.5 being used. Values other than 1 (a 

free-slip condition) affect the wind profile. Consequently, the slip factor may also affect 

the spreading and dispersion of the LNG vapors. Therefore, FERC staff requested a 

technical justification for their selection of the slip factor or a sensitivity analysis 

supporting the use of the selected slip factor. FGS pointed to the FDS manual for its 

technical justification, which states that it is not recommended that the default velocity 

boundary condition is changed unless the effect on the overall flow is of interest. We 

believe that the slip factor may have a significant impact on the overall flow and 

flammable vapor downwind dispersion distance and therefore we feel the selection of the 

slip factor value warrants further study. 

In addition, a “reaction flag” in the source code of FDS may cause a local temperature 

increase shortly after the initial release of methane. This local temperature rise indicates 

the call of this reaction flag signifying a combustion process and may have an effect on 

the dispersion of the LNG vapors. FGS erroneously interpreted the question and assumed 

that we were referring to a parameter in the input file that was not specified. We were 

actually referring to the source code of FDS. The source code would have to be modified 

and recompiled to eradicate the reaction flag. Once again, this recommendation is also 

consistent with the Cabrillo report. 

Other questions regarding the selection of temperature, relative humidity, lapse rate, and 

ground surface material were also presented. FGS did not provide sufficient technical 

justifications for why the appropriate values were not prescribed, but rather argued that 

the values selected are fairly insensitive to these parameters. 

The recommended modifications to the dispersion calculations may cause the LNG 

vapors to go offsite. However, this is largely because the dispersion modeling has not 

accounted for the variation in terrain or obstacles that would actually be present. Other 

dispersion modeling submittals have shown that the turbulent kinetic energy near 

obstacles in the flow field may be more than an order of magnitude larger than the 
4-97 4.0 – Environmental Analysis

turbulent kinetic energy associated with the atmospheric wind profile of F stability. We 

believe the inclusion of obstacles in the flow field would greatly reduce the vapor 

dispersion distances due to increased turbulence. In addition, mitigation measures (i.e. 

vapor fences) may be implemented to reduce the downwind dispersion distance. We 

believe if these measures are taken into consideration the vapors would remain on-site. 

In order to prove quantitatively that the flammable vapors would remain on-site, we 

recommend that:

• FGS should file with the Secretary, for review and approval by the Director 

of OEP, revised vapor dispersion simulations with the following information, 

prior to initial site preparation: 

a. a quantitative grid sensitivity analysis that supports the selection of 

grid size and demonstrates the convergence of the downwind 

dispersion distances; 

b. simulations with mirror boundary conditions for the side and top 

boundaries; 

c. simulations that allow the wind profile to reach a steady or quasisteady state before injecting LNG vapor into the domain; 

d. a sensitivity analysis and technical justification that supports the slip 

factor value used to determine the downwind dispersion distances; 

e. an evaluation of the effect that the “reaction flag” in the source code 

to FDS has on the downwind dispersion distances; 

f. technical justification and/or sensitivity analyses that support the 

selection of the lapse rate, ground surface material properties, 

temperature, humidity, and wind profile used to determine the 

downwind dispersion distances; and 

g. all pertinent input files (*.fds) and output files (*.out) used to 

determine the downwind dispersion distances. 

4.12.4 LNG and NGL Truck Operations 

FGS is proposing to install a dual LNG truck loading station at the facility to be used 

only for emergency events, such as during the aftermath of a hurricane or other natural 

gas supply interruption. Loaded LNG trucks from the facility could be sent to hospitals, 

gas distribution companies, power plants, and other essential services during emergency 

events. The proposed travel route for outbound LNG trucks would be along SR 710 

adjacent to the facility, either north through Okeechobee, Florida, or south through 

Indiantown, Florida. FGS does not expect to receive any LNG trucks at its facility. 

LNG trailers are of a double-shell construction – an inner tank constructed of a cryogenic 

alloy to contain the LNG, an outer tank of carbon steel, and an evacuated annular space 

containing perlite insulation. Stiffening rings are incorporated into the outer shell to 

improve its structural strength and prevent its collapse. A typical LNG truck carries 

between 10,000 to 12,000 gallons of LNG. LNG trailer design must comply with the 
4.0 – Environmental Analysis 4-98 

requirements of 49 CFR Part 173, while truck drivers must meet the training 

requirements of Title 49 CFR Part 172. 

Additionally, FGS is proposing to install a NGL truck loading station to remove excess 

NGLs that could not be stored or re-injected into the vaporized gas or tailgas. During the 

cryogenic technical conference, FGS indicated that NGLs could be sent to power plants 

for use in boilers. The NGL trucks would utilize the same travel route as proposed for 

LNG trucks. The capacity of a NGL truck is also typically between 10,000 and 12,000 

gallons. However, weight, rather than volume, is the controlling factor in determining 

NGL truck capacity due to the NGL compositions and truck “on-road” weight limitations. 

The NGL truck capacity is dependent whether heavier NGLs are being transported, 

which would reduce the volumetric capacity of the truck. NGL truck transportation must 

comply with the requirements of 49 CFR Part 180. 

The proposed LNG and NGL truck loading stations would be equipped with multiple 

safety features. The LNG truck loading area would be provided with concrete curbing to 

direct any potential LNG spills into spill transmission troughs and into an impoundment 

sump. A hazard detection system would consist of separate detection units for 

combustible gas, fire, and high and low temperature and would be hard wired to the main 

control system for alarm and emergency shutdown. A dry chemical fire suppression 

system would also be provided. In addition, hydrants, manual monitors, and hose reels 

would be located throughout the facility. 

At the cryogenic technical conference, representatives from the Martin County 

Emergency Services raised concerns about loaded LNG trucks exiting the FGS property 

and merging with faster traffic onto SR 710. Therefore, in the event trucking operations 

would be conducted, we recommend that: 

• FGS should develop a traffic control plan coordinated with local authorities 

to address LNG and NGL truck transportation from the facility. This plan 

should be incorporated into the facility’s operation and maintenance 

procedures and manuals prior to any trucking activities at the LNG facility. 

4.12.5 Emergency Response and Evacuation Planning 

Prior to commencing operations, FGS would have to prepare emergency procedures 

manuals, as required by 49 CFR Part 193.2509, 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, Section 

193.2509(b)(3) requires “Coordinating with appropriate local officials in preparation of 

an emergency evacuation plan...” To aid in the preparation of emergency response 

procedures, FGS would coordinate with the State Fire Marshal’s office, Indiantown Fire 

Department, and Martin County Emergency Services Department, Martin County Fire & 

Rescue, and the Indiantown Sheriff’s Department. In its application, FGS has stated that 

it would provide for installation of safety systems and specific gas detection equipment 

on the Martin County emergency service providers’ vehicles. In addition, FGS would 

provide direct communication systems and training to the Martin County emergency 

service providers. 
4-99 4.0 – Environmental Analysis

4.12.6 Terrorism and Security Issues 

Since September 11, 2001, the FERC has been involved with other federal agencies in 

developing a coordinated approach to protecting the energy facilities of the United States. 

The FERC continues to coordinate with these agencies to address this issue. Safety and 

security are important considerations in any Commission action. The attacks of 

September 11, 2001 have changed the way pipeline operators as well as regulators must 

consider terrorism, both in approving new projects and in operating existing facilities. 

The likelihood of future acts of terrorism or sabotage occurring at the proposed FGS 

project, or at any of the myriad of natural gas facilities throughout the United States is 

unpredictable given the disparate motives and abilities of terrorist groups. 

It is possible that a release from the LNG storage tanks could be caused by an intentional 

act, such as a terrorist attack. Although an intentional breach scenario could result in 

greater thermal radiation in the immediate vicinity of the release, such scenarios are 

typically associated with the desire to inflict damage to major infrastructure and heavily 

populated areas, rather than a remote industrial area. The continuing need to construct 

facilities to support the future natural gas pipeline infrastructure is not diminished from 

the threat of any such unpredictable acts. 

The security requirements for the Project would be governed by 49 CFR Part 193, 

Subpart J - Security, and include the following: 

• conducting security inspections and patrols; 

• providing a liaison with local law enforcement officials; 

• providing protective enclosures specified in Section 193.2905 for the 

following facilities: (1) Storage tanks; (2) Impounding systems; (3) 

Vapor barriers; (4) Process, liquefaction, and vaporization equipment; 

(5) Control rooms and stations; (6) Control systems; (7) Fire control 

equipment; (8) Security communication systems; and (9) Alternative 

power sources; 

• complying with the design and construction requirements specified in 

Section 193.2907; 

• providing prompt security communication between supervisory 

security and law enforcement officials. In addition, direct 

communication between on-duty security personnel and control room 

personnel must be ensured; 

• providing security lighting for protective enclosures; 

• providing security monitoring for all protective enclosures; 

• providing alternative power source required for security lighting and 

security warning systems; and 

• displaying warning signs for all protective enclosures. 
4.0 – Environmental Analysis 4-100 

In the application, FGS described the proposed facility’s preliminary security plan and 

stated that final plans would be developed as part of the emergency response procedures 

in accordance with 49 CFR Part 193.2903. FGS stated that the final plans would be 

developed with the input of appropriate agencies including the State Fire Marshal’s office, 

Indiantown Fire Department, and Martin County Emergency Services Department, 

Martin County Fire Marshal, Martin County Fire Rescue, and the Indiantown Sheriff’s 

Department. 

Under Section 550 of the Homeland Security Appropriations Act of 2007, the U.S. 

Department of Homeland Security (DHS) was provided with the authority to regulate the 

security of certain chemical facilities in the United States. Accordingly on April 9, 2007, 

DHS created the “Chemical Facility Anti-Terrorism Standards” under Title 6, CFR, Part 

27 to establish risk-based performance standards related to facility security. On 

November 20, 2007, DHS issued the list of threshold quantities of chemicals of interest 

which trigger Part 27 review. The quantities of methane typically stored on-site at LNG 

peakshaving facilities under FERC jurisdiction exceed the screening threshold quantities 

specified in Appendix A to Part 27. As a result, the proposed FGS project would be 

required to comply with the regulations under 6 CFR 27 within 60 calendar days of 

receiving natural gas. 

All facilities regulated under Part 27 must participate in an initial screening process, 

termed “Top-Screen,” to establish the risk level associated with the facility. Facilities for 

which the Top-Screen process indicates the potential that a terrorist attack could result in 

significant adverse consequences for human life or health, national security or critical 

economic assets are designated by the DHS as “covered facilities”. If the DHS 

determines that the FGS project would be considered a covered facility, the LNG plant 

would be preliminarily assigned to one of four risk-based tiers, ranging from highest risk 

in Tier 1 to lowest risk in Tier 4. 

In accordance with 6 CFR 27.215, covered facilities must complete a Security 

Vulnerability Assessment (SVA) which identifies: 

• hazards and consequences of concern for the facility and its 

surroundings; 

• existing layers of protection; 

• possible internal threats, external threats, and internally-assisted 

threats; 

• potential security vulnerabilities and existing countermeasures; and 

• strategies that reduce the probability of a successful attack or reduce 

the probable degree of success. 

Following review of the SVA, the DHS would reassess the facility’s preliminary ranking. 

If the FGS project still qualified as a covered facility, DHS would determine the facility’s 

final placement within Tiers 1 through 4. After final placement, covered facilities are to 

provide the DHS with a plan which describes how on-site security measures would meet 

or exceed the performance standard associated with the facility’s Tier ranking. This Site 

Security Plan, which must be approved by the DHS, would list the security measures to 
4-101 4.0 – Environmental Analysis

be used to address the vulnerabilities identified by the SVA and potential modes of 

terrorist attack. 

4.12.7 Natural Gas Pipelines 

The transportation of natural gas by pipeline involves some risk to the public in the event 

of an accident and subsequent release of gas. The greatest hazard is a fire or explosion 

following a major pipeline rupture. 

The DOT is mandated to provide pipeline safety under Title 49, U.S.C. Chapter 601. 

Within the DOT, the Pipeline and Hazardous Materials Safety Administration (PHMSA), 

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 that set the level of safety to be 

attained and allow the pipeline operator to use various technologies to achieve safety. 

PHMSA ensures that people and the environment are protected from the risk of pipeline 

incidents. This work is shared with state agency partners and others at the federal, state, 

and local level. 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. A 

state may also act as DOT’s agent to inspect interstate facilities within its boundaries; 

however, the DOT is responsible for enforcement action. The majority of the states have 

either 5(a) certifications or 5(b) agreements, while nine states act as interstate agents. 

The DOT pipeline standards are published in 49 CFR Parts 190 to 199, Part 192 of 49 

CFR specifically addresses natural gas pipeline safety issues. Under a Memorandum of 

Understanding on Natural Gas Transportation Facilities (Memorandum) dated January 15, 

1993, between the DOT and 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 would 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 shall 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 DOT. The 

Memorandum also provides for referral of 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 whether 

proposed safety regulations are reasonable, feasible, and practicable. 
4.0 – Environmental Analysis 4-102 

The pipeline and M&R station associated with the Project must 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 prevent natural gas facility accidents and failures. Part 192 specifies 

material selection and qualification, minimum design requirements, and protection from 

internal, external, and atmospheric corrosion. 

49 CFR 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 one-mile length of pipeline. The four area classifications are defined as 

follows: 

Class 1 Location with 10 or fewer buildings intended for human occupancy. 

Class 2 Location with more than 10 but less than 46 buildings intended for 

human occupancy. 

Class 3 Location with 46 or more buildings intended for human occupancy or 

where the pipeline lies within 100 yards of any building, or small welldefined outside area occupied by 20 or more people during normal use. 

Class 4 Location where buildings with four or more stories above ground are 

prevalent. 

The pipeline corridor is in a Class 1 location. Pipelines constructed on land in Class 1 

locations must be installed with a minimum depth of cover of 30 inches in normal soil 

and 18 inches in consolidated rock. Class locations also specify a maximum distance to a 

sectionalizing block valve of 10.0 miles in Class 1 areas. If a subsequent increase in 

population density adjacent to the right-of-way causes a change in class location above 

existing design for the pipeline, FGS would be required to reduce the maximum 

allowable operating pressure or replace the segment with pipe of sufficient grade and 

wall thickness to comply with the 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 Section 

192.911 and addresses the risks on each covered transmission pipeline segment. 

Specifically, the law establishes an integrity management program that applies to all 

high-consequence areas (HCAs). The DOT (68 FR 69778, 69 FR 18228, and 69 FR 

29903) defines HCAs as they relate to the different class zones, potential impact circles, 

or areas containing an identified site as defined in Section 192.903 of the DOT 

regulations. 

HCAs include: buildings or outside areas occupied by persons who are confined, of 

impaired mobility, or difficult to evacuate, such as hospitals, schools, prisons, or 

retirement facilities; and buildings or sites used by at least 20 or more persons on at least 

50 days in any 12-month period, such as beaches, playgrounds, campgrounds, stadiums, 
4-103 4.0 – Environmental Analysis

or religious facilities. For a pipeline not more than 12 inches in diameter and operating at 

a maximum achievable operating pressure, the area for consideration of HCAs is within 

300 feet of the center line of the pipeline; for a 12 to 30–inch-diameter pipeline, the area 

of concern for HCAs would extend 660 feet. There are no HCAs in the vicinity of the 

proposed FGS pipeline corridor. 

49 CFR 192 prescribes the minimum standards for operating and maintaining pipeline 

facilities, including the requirement to establish a written plan governing these activities. 

Under Section 192.615, each pipeline operator must also establish an emergency plan that 

includes procedures to minimize the hazards in a natural gas pipeline emergency. Key 

elements of the plan include procedures for: 

• receiving, identifying, and classifying emergency events, gas leakage, 

fires, explosions, and natural disasters; 

• establishing and maintaining communications with local fire, police, 

and public officials, and coordinating emergency response; 

• emergency 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. 

Part 192 requires that each operator establish and maintain liaison with appropriate fire, 

police, and public officials to learn the resources and responsibilities of each organization 

that may respond to a natural gas pipeline emergency, and to coordinate mutual 

assistance. The operator must also establish a continuing education program to enable 

customers, the public, government officials, and those engaged in excavation activities to 

recognize a gas pipeline emergency and report it to appropriate public officials. FGS has 

met with the Martin County Emergency Services Organization to inform it of the Project 

and proposed safety systems. FGS and the County have agreed to coordinate activities. 

In addition, FGS would have direct communications systems in place when the Project is 

constructed, make a contribution to install safety systems and specific gas detection 

equipment on its trucks, and provide training. 

Based on approximately 302,000 miles in service, the rate of public fatalities for the 

nationwide mix of transmission and gathering lines in service is 0.01 per year per 1,000 

miles of pipeline. Using this rate, the pipeline associated with the Project is not likely to 

result in more than one public fatality every 23,923 plus years. This would represent a 

negligible risk to the nearby public. 

4.13 CUMULATIVE IMPACTS 

The CEQ defines cumulative impacts as the “impacts on the environment which result 

from the incremental impact of the action when added to other past, present, and 

reasonably foreseeable future actions regardless of what agency (federal or non-federal) 

or person undertakes such other actions.” Although the individual impact of each 

separate project may be minor, the additive or synergistic effects of multiple projects 
4.0 – Environmental Analysis 4-104 

could be significant. The cumulative impact assessment includes determining the 

resources to be evaluated, establishing the geographic scope and temporal scale for the 

analysis, and identifying the other past, present, and reasonable foreseeable future actions 

that have affected, or could affect, the resources of concern. 

4.13.1 Potentially Cumulatively-Affected Resources 

Resources subject to cumulative impact assessment include those resources upon which 

the Project would have long-term impacts. Resources that are not impacted by the 

Project or are only subject to temporary effects were excluded from this analysis. Table 

4.13-1 summarizes the screening process to determine the resources included in the 

cumulative effects analysis. 

Based on this analysis, we have identified eight resources that have the potential for 

cumulative effects: water resources, vegetation and wildlife, visual resources, 

socioeconomics, transportation, air quality, noise, and reliability and safety. 

4.13.2 Geographic Scope and Temporal Scale 

The geographic scope of the cumulative impact assessment for most resource areas 

includes lands within a two-mile radius of the proposed storage site, pipeline, and M&R 

station (see Figure 4.13-1). Due to the dispersion potential of air emissions, the 

geographic scope for this resource includes all of Martin County to ensure compliance 

with federal, state, and local air quality standards. The socioeconomic analysis considers 

all of Martin County within the Project’s area of influence; therefore, the geographic 

scope for this resource includes all of Martin County. 

4.13.3 Other Actions Potentially Contributing to Cumulative Effects 

Existing environmental conditions in the study area reflect changes based on past 

activities. Historically, the site was a combination of marshland, forested wetlands, 

upland forests, and grasslands. Much of the study area has been in agricultural use (e.g., 

cattle ranching, citrus orchards) since the 1890s. Residential development in Indiantown 

began in the early 1900s, but increased since 1953 when the Indiantown Company 

purchased and subsequently developed much of the land in this unincorporated town. 

Industrialization of the study area included agri-businesses such as Tampa Farms and 

Louis Dreyfus. The Florida Steel manufacturing facility was constructed in 1970, 

operated until February 1982, and was placed on the Superfund list in December 1982. 

With the extension of gas pipelines, the study area became attractive for power 

generation and distribution, with the construction of the FPL Martin power plant and 

associated electric transmission lines, and subsequently the Cogentrix power plant. 
4-105 4.0 – Environmental Analysis

Table 4.13-1 

Summary of Potential Cumulative Effects of the Proposed Project 

Resource Would Project have long term 

adverse effect on resource? 

(Yes or No) 

Cumulative 

Effects analysis 

required 

Potential Cumulative Effect 

Geology No, Project would have no effect on 

geology. 

No None 

Soils No, Project would only have minor 

temporary effects on soils during 

construction. All disturbed soils 

would be stabilized and restored. 

No None 

Water Resources Yes Yes The Project would have a long-term 

affect on water resources through 

groundwater withdrawals for 

landscaping and increases in 

stormwater runoff. 

Wetlands No, Project would only have minor 

temporary effects on wetlands during 

construction. All wetlands would be 

restored with permanent impacts. 

No None 

Vegetation and 

Wildlife 

Yes. Yes Project would permanently affect 

78.40 acres of vegetation that 

provides habitat for a variety of 

wildlife species. 

Aquatic 

Resources 

No, Project would only have minor 

temporary adverse effects on 

drainage ditches and stormwater 

ponds during construction. 

No None 

Threatened and 

Endangered 

Species 

No, Project either would have no 

effect or would be not likely to 

adversely affect all federally- listed 

species. 

No None 

Land Use No, Project is consistent with current 

local zoning and future land use plan 

and compatible with neighboring land 

uses. 

No None 

Recreation and 

Special Interest 

Areas 

No, Project would have no effect any 

recreation or other special interest 

areas. 

No None 

Visual Resources Yes Yes Project would be visible from public 

roads and would result in minor 

permanent change in the visual 

landscape of Project area. 

Socioeconomics Yes Yes Project would have a long-term 

beneficial effect on local economy 

through job creation and payment of 

taxes and fees. 

Transportation Yes Yes Project would result in minor longterm increase in traffic. 

Cultural 

Resources 

No, the Project would have no effect 

on cultural resources. 

No None 

Air Quality Yes Yes Project would result in minor longterm increase in air emissions. 

Noise Yes Yes Project would result in minor longterm increase in noise levels in the 

immediate Project area. 

Reliability and 

Safety 

Yes Yes Project would affect reliability and 

public safety. 
4.0 – Environmental Analysis 4-106 

These projects cumulatively resulted in the loss of natural vegetation and wetlands, 

reduction in water quality, fragmentation of the remaining natural habitat, and 

introduction of exotic and invasive species. Future development would further contribute 

to these impacts. 

There are no known expansion plans for the FPL Martin, Cogentrix, or Louis Dreyfus 

plants; however, these facilities would be expected to continue industrial operations 

during the life of the Project. Three industrial projects - Venture Park, Indiantown 

Commerce & Technology Park, and Prism Business Park - are planned within 

approximately one mile of the LNG storage facility site; one mixed-use (i.e., residential 

and commercial) project is planned within about 1.25 miles. Table 4.13-2 lists present or 

reasonably foreseeable future projects or activities that may cumulatively or additively 

impact resources affected by construction and operation of the FGS LNG facility. Figure 

4.13-1 shows the location of the existing and planned development actions in relation to 

the Project. 

Table 4.13-2 

Potential Future Actions in the FGS Project Area 

Activity Description 

Venture Park Industrial lots (22) and agricultural ranchettes on 139 acres across SR 710 from the 

northern corner of SRS project site. 

Indiantown Commerce & 

Technology Park 

Industrial lots (31) on 97.4 acres of the west side of CSX Railroad, north of the 

Booker Park Community of Indiantown. 

Prism Business Park 21-acre industrial development at the Northwest corner of SR 710 and County Road 

609 in Indiantown. 

Quillen Development Mixed-use residential (2,250 units) and commercial (150,000 square feet) at the 

Northwest corner of SR 710 and County Road 609 in Indiantown approximately 1.25 

miles from FGS site. 

4.13.4 Resource-Specific Cumulative Effects Analysis 

Water Resources 

The Project would not affect any major waterbodies. It would disturb three drainage 

ditches and withdraw hydrotest water from the St. Lucie Canal; but these effects would 

be temporary, the ditches would be restored in accordance with our Procedures, and the 

hydrotest water returned to the canal. 
Indiantown

SR-710

Fox Brown Road

Allapattah Road

SR-76 Kanner Hwy

CSX Railroad

Indiantown Commerce 

and Technology Park

Proposed Secondary 

Access Road

St. Lucie Canal

Prism Business

Park

Quillen Development

Venture Park

FPL Martin Power Plan

and Cooling Pond

Cogentrix Power Plant

and Cooling Pond

Louis Dreyfus

Plant

0 0.25 0.5 1

Miles

Legend Roads

Railroad

Project Pipeline

M&R Station

Storage Facility Site

Potential Future Actions

4-107

Figure 4.13-1

FGS Project

Current and Potential Future Actions in the Project Area
4.0 – Environmental Analysis 4-108 

The only long-term Project effects on water resources involve increased groundwater 

withdrawals for landscaping, stormwater runoff from impervious surfaces, and 

wastewater generation. Groundwater withdrawals for landscaping would be a maximum 

of 30 gpm and most of the water (allowing for evaporative losses) would be returned to 

the surficial aquifer. The creation of impervious surface would reduce the available 

surface area for groundwater recharge; however, relative to the total recharge area for the 

aquifer, this reduction in pervious surface would not be significant. These impervious 

surfaces would also increase the volume of stormwater runoff, but the Project would 

provide on-site stormwater management in accordance with state and local requirements 

and implement site-specific SPCC and SWPP plans. The Project would generate 

domestic wastewater from the approximately 32 full-time employees, but this wastewater 

volume would be small and it would be treated at a publicly-owned wastewater treatment 

plant. Therefore, the Project would have little effect on groundwater or surface water 

quantity or quality. 

The current and potential future actions in the Project area would also contribute to 

additional withdrawals from the local aquifer and wastewater discharges to the local 

wastewater utilities. These activities would all likely be constructed in accordance with 

the applicable federal, state, and local permit requirements and would likely not cause the 

aquifer or utility systems to exceed their capacity. Therefore, the Project, other existing 

development, and potential future actions would not result in a significant cumulative 

impact on water resources in the study area. 

Vegetation and Wildlife 

Construction of the Project would result in the permanent loss of 56.07 acres of potential 

wildlife habitat and the permanent maintenance of 22.33 acres of pipeline right-of-way in 

low growth (i.e., shrub or herbaceous) cover. More mobile species would be displaced, 

while smaller, less mobile species would suffer localized mortality. Much of the affected 

land, however, was previously disturbed and contaminated and does not represent 

valuable habitat. The proposed pipeline route does not intersect any rare or significant 

habitats. Pipeline construction and right-of-way maintenance could fragment wildlife 

habitat reducing its value, but in this case the pipeline follows an existing transmission 

line right-of-way for much of its length. A major issue in Florida is the proliferation of 

invasive and exotic species. The Project would remove stands of Australian pine and 

Brazilian pepper. 

The Prism Business Park, Venture Park, and Quillen Development sites are dominated by 

open prairie, residential areas, and agricultural fields while the Indiantown Commerce 

and Technology Park is dominated by pine flatwoods. These habitat types are common 

throughout the region and likely would not provide significant wildlife habitat. The 

majority of wildlife species displaced by these projects would likely be able to relocate 

and would not suffer long-term, population-level impacts to biodiversity within the 

region. Therefore, there would be no significant cumulative impact to wildlife resources. 
4-109 4.0 – Environmental Analysis 

Visual Resources 

The primary Project effect on visual resources would be the two 174-foot-high LNG 

storage tanks. These storage tanks would be visible to the surrounding area; however, the 

visual character of the Project area is currently industrial. The adjoining Louis Dreyfus 

plant and Cogentrix power plant have structures that are 138- and 495-feet-high, 

respectively. Other nearby tall structures include the FPL’s Martin power plant stacks 

and electric transmission line, which are visible throughout the Project area. The Project 

would be visually compatible with other industrial facilities in the study area and 

consistent with the industrial zoning of the area. 

The current and potential future actions would further contribute to the trend of 

converting the landscape character of the Project area from rural/agricultural to 

industrial/commercial. This change in visual character is consistent with the current 

zoning and planning guidelines for Indiantown and would not introduce structural 

elements out of character with surrounding developments. 

Socioeconomics 

Project operations would provide long-term benefits to the economy of the study area and 

Martin County through the creation of 270 temporary construction jobs with a peak of 

450 temporary construction jobs during months 14 and 15 of the construction period, up 

to 33 full time employees, purchase of construction materials, and the annual payment of 

corporate income taxes to the State of Florida and property taxes to Martin County. 

The current and potential future actions in the Project area would similarly provide 

economic benefits through increased employment opportunities and payment of taxes. 

Overall, the Project, other existing development, and potential future actions would 

benefit the socioeconomic conditions of the study area. 

Transportation 

The Project would primarily affect traffic during construction when as many as 450 

workers would commute to the site, but these effects would be temporary. The Project 

would employ approximately 33 full time employees during operation, but these 

employees would have a negligible effect on traffic volumes in the study area considering 

that SR 710 currently carries 7,800 vehicles per day. 

Other existing development and potential future actions would likely generate much more 

traffic than the 32 employees at the LNG storage facility. Traffic volumes along SR 710 

are increasing and FDOT has plans for road resurfacing, intersection signalization and 

turn lane improvements to maintain the desired level of service. With proper 

coordination of land use and transportation planning, the Project and current and potential 

future actions should not reduce the level of service below acceptable standards. 

Air Quality 

Operation of the Project would result in the emission of a variety of criteria air pollutants. 

The net emissions from the Project for each of the criteria pollutants would be less than 
4.0 – Environmental Analysis 4-110 

applicable thresholds so the Project would be considered a minor source. The Project is 

implementing a variety of control technologies such as the use of low NOx burners to 

reduce air emissions. The Project would comply with all applicable federal and state 

permits. 

The current and potential future actions in the Project area also have the potential to emit 

air emissions. There are three existing major emissions sources in the vicinity of the 

proposed Project: the FPL Martin power plant, the Cogentrix power plant, and the Louis 

Dreyfus Citrus processing plant. These facilities are regulated under Title V of the CAA 

and the combined annual permitted emissions for these facilities and the proposed Project 

are identified in Table 4.13-3. The proposed Project would account for less than a 5 

percent increase in any single criteria pollutant. 

Table 4.13-3 

Cumulative Existing Criteria Air Pollutant Emissions in the Vicinity of the Proposed Project 

SO2 PM NOx CO VOC HAPs 

Existing Emissions (tons/year)1 33,435.2 4,260.9 17,118.5 3,784.8 1,037.7 92.9 

Proposed Project Emissions (tons/year) 7.6 11.0 89.0 96.0 48.0 0.2 

Project Emissions as a Percent of Total 0.02% 0.26% 0.52% 2.54% 4.63% 0.24% 1 FDEP, 2008c 

There are currently three industrial facilities and one mixed-use development proposed in 

the Project area. When emissions from the proposed Project are combined with 

emissions from current industrial operations in Martin County, the Project would not 

contribute to an exceedence of the NAAQS or violate the PSD requirements of the CAA. 

The degree to which the Project and current and potential future actions would contribute 

to regional air quality is dependent upon the specific activities conducted at each location. 

Should these activities receive the required permits and comply with all federal and state 

air quality regulations, these activities would have no significant cumulative impact on 

regional air quality. 

Project operations would emit approximately 2 million tons of CO2-e annually; however, 

the Project would likely cause an overall net reduction in greenhouse gas emissions by 

increasing the availability of natural gas as a substitute for alternative fuels that emit 

more CO2-e per unit of energy. 

Noise 

The operation of the LNG storage facility would increase noise levels by about 2 dBA at 

the nearest NSA thereby resulting in an insignificant impact on the noise environment.. 

This noise analysis already takes into consideration existing background noise levels. 

The potential future actions in the Project area would also increase noise levels either 

directly through their operation, or indirectly by increases in traffic and other noisegenerating activities. These activities, however, would be located in areas zoned for their 

respective use (e.g., industrial, commercial, residential) and Martin County implements a 

strict noise control ordinance. Based on the lack of NSAs, compatible land use zoning, 

and likely implementation of noise minimization measures, the Project and current and 
4-111 4.0 – Environmental Analysis 

potential future actions would increase noise levels in the Project area; but the increase 

would be minor and would result in no significant cumulative impacts. 

Reliability and Safety 

Impacts on reliability and public safety would be mitigated through the implementation 

of applicable federal, state, and local rules and regulations for each individual project. 

The implementation of federal, state, and local rules and regulations concerning safety; 

implementation of the Emergency Response Plan; and close coordination and 

communication with emergency responders would minimize the risk to the LNG storage 

facility and the public. 

4.13.5 Conclusions about Cumulative Impacts 

A determination of significance for the cumulative impacts for specific resources is 

problematic because well-defined thresholds are typically undetermined; however, most 

of the cumulative impacts we have identified for the proposed Project would be 

temporary and minor. Consequently, their addition to other past, present, and reasonably 

foreseeable actions in the area does not result in an overall significant increase in impacts. 

Although the Project would result in some minor adverse environmental impacts, the 

Project would also cumulatively benefit the local economy through job creation and 

wages, purchases of goods and materials, tax revenues, and provision of a new source of 

competitively priced natural gas. 
5-1 5.0 – Conclusions and Recommendations

5.0 CONCLUSIONS AND RECOMMENDATIONS 

5.1 SUMMARY OF THE STAFF’S ENVIRONMENTAL ANALYSIS 

The conclusions presented in this section are those of the environmental staff of the 

FERC, working in cooperation with the FWS, EPA, and COE. Review of the 

information provided by FGS and further developed from data requests; field visits; 

scoping; literature research; alternatives analysis; comments from federal, state, and local 

agencies; and input from individual members of the public indicates that development 

and operation of the proposed Floridian Natural Gas Storage Project would result in 

limited adverse environmental impacts. In addition, we conclude that if the proposed 

Project is constructed and operated in accordance with FGS’ proposed mitigation and our 

additional mitigation recommendations presented in Section 5.2, it would be an 

environmentally acceptable action. 

The discussion below summarizes the environmental impacts and mitigation we are 

recommending for each resource analyzed in this EIS. 

5.1.1 Geology 

Construction and operation of the Project would have minimal impact on geological 

resources. The Project is located in an area with no known extractive or surficial 

paleontological resources; low risk of soil liquefaction, slope failures, or landslides; and 

one of the lowest seismic hazards within the continental United States. Probabilistic and 

deterministic seismic hazard analyses determined the required input ground motions for 

design of the LNG storage facility. These were found to be consistent with the 

requirements of NFPA 59A and FERC’s Draft Seismic Design Guidelines and Data 

Submittal Requirements for LNG Facilities. We are recommending that prior to 

construction, FGS provide additional geotechnical and structural design details for the 

LNG storage facility to support our review and approval of the final engineering design 

of the facility. No blasting is anticipated. 

5.1.2 Soils 

The Project would temporarily disturb 127.03 acres of land. None of this land or its soils 

are classified as prime farmland or considered to have high erosion potential by the U.S. 

Department of Agriculture; and none are currently in agricultural use. These soils, 

however, are generally very poorly to poorly drained, which contribute to their fair to 

very poor revegetation potential. 

FGS would implement the mitigation measures contained in our Plan to control erosion, 

ensure successful revegetation, and minimize any potential adverse impacts to soil 

resources. FGS would further limit potential impacts to soil resources by implementing 

site-specific SPCC, SWPP, and Unanticipated Hazardous Waste Discovery plans. With 

the implementation of our Plan and FGS’s site-specific plans, the Project would not result 

in any significant impacts to soils. 
5.0 – Conclusions and Recommendations 5-2 

5.1.3 Water Resources 

Project activities would not occur within 500 feet of any public water supply well and 

would not affect any sole-source aquifers or wellhead protection areas. The Project 

would withdraw a maximum of 30 gpm of groundwater for landscaping purposes, but this 

withdrawal rate would have a negligible impact on the surficial aquifer at the storage 

facility site. The SFWMD approved the Water Use Permit (No. 43-02115-W) for 

landscaping irrigation at the proposed facility on March 7, 2008. The greatest potential 

for impact to groundwater would be from spills, leaks, or other releases of hazardous 

materials during construction or operation. FGS has agreed to implement our Procedures 

as well as its own SPCC and SWPP plans to address this issue. 

There are no major waterbodies in the Project area; the nearest major waterbody is the St. 

Lucie Canal, which is about two miles away. The pipeline would cross five waterbodies, 

which are all intermittent drainage ditches. FGS proposes to use open-cut methods to 

cross four ditches and would restore the ditches in accordance with our Procedures. FGS 

would also bore under one ditch from MP 0.99 to 1.02, avoiding impacts to 0.03 acre of 

wetlands. 

FGS proposes to withdraw water from the St. Lucie Canal for hydrotesting of the LNG 

storage tanks and the pipeline (i.e., approximately 33.5 million gallons for tank testing 

and one million gallons for pipeline testing). FGS would use an existing irrigation intake 

structure, withdraw water at a rate that is less than 0.1 percent of the annual flow of the 

canal, not use any biocides or other water additives, and return the water to the canal after 

the testing is completed. The SFWMD approved the Water Use Permit (No. 43-02186-

W) for hydrostatic testing of the LNG storage tanks on April 10, 2008. Therefore, we do 

not anticipate that the Project would have any significant adverse effects on water 

resources. 

5.1.4 Wetlands 

Construction of the Project would temporarily impact 3.91 acres of wetlands; there would 

be no permanent impacts. All of the wetland impacts would be associated with pipeline 

construction; no wetlands would be impacted by construction or operation of the LNG 

storage facility. None of the affected wetlands are forested, or considered high-quality, 

sensitive, or special status. 

FGS minimized impacts to wetlands by evaluating route alternatives to avoid wetlands, 

reducing the nominal construction right-of-way width in wetlands to 65 feet, using a bore 

rather than open trenching to avoid impacting 0.03 acres of wetlands, and adopting our 

Procedures without modifications. Following construction, FGS would revegetate 

wetlands in accordance with our Procedures and COE permit conditions. The FDEP 

issued the ERP on March 19, 2008, which states the proposed wetland mitigation would 

improve on-site wetlands. By implementing these measures, effects on wetlands would 

be minimized. 
5-3 5.0 – Conclusions and Recommendations

5.1.5 Vegetation 

In addition to the wetland vegetation resources described above, Project construction 

would clear 123.12 acres of upland cover types. Project operations would permanently 

affect 53.10 acres for the LNG storage facility; and 25.30 acres for the permanent 

pipeline right-of-way, M&R station, and pipeline interconnections. Much of this land is 

previously disturbed and is dominated by invasive species such as Australian pine and 

Brazilian pepper. Further, the LNG storage facility site was previously contaminated and 

is currently undergoing EPA-supervised remediation. 

FGS would implement our Plan to facilitate the revegetation of disturbed areas not used 

for aboveground facilities. In addition, FGS prepared a PAMP for the LNG storage 

facility site that identifies the location of Preserve Areas, invasive species controls, 

construction procedures, and monitoring requirements. To ensure appropriate application 

of herbicides, we are recommending that FGS develop a Standard Operating Procedure 

for Herbicide Use that meets EPA requirement. Given these measures, impacts to upland 

vegetation would be effectively minimized. 

5.1.6 Wildlife and Aquatic Resources 

The upland and wetland vegetative communities in the Project area support habitats for a 

variety of wildlife species. As indicated above, the Project would result in the clearing of 

127.03 acres of land and the permanent loss of 56.07 acres of wildlife habitat (53.10 acres 

for the LNG storage facility and 2.97 acres for the M&R station and interconnections). 

In addition, 2.48 acres of upland habitat would become part of the stormwater pond. 

Much of this affected land, however, was previously disturbed and contaminated and 

does not represent valuable habitat. During construction, more mobile species would be 

temporarily displaced to similar habitats nearby, while less mobile species may suffer 

direct mortality or permanent displacement. Regardless of mobility, some wildlife 

species would be affected by the loss of cover, nesting, and foraging habitat. Once 

construction is complete and work areas restored, wildlife could re-occupy available 

habitat. Pipeline construction and right-of-way maintenance can also fragment wildlife 

habitat reducing its value, but in this case the pipeline follows an existing electric 

transmission line right-of-way for much of its length. Therefore, wildlife would not to be 

significantly impacted by the Project. 

The Project would not affect any naturally occurring waterbodies, including any major, 

navigable, or sensitive waterbodies. Drainage ditches crossed by the pipeline contain 

only common forage fishes such as mosquito fish, least killifish, and small sunfish. The 

ditches are not considered critical habitat by FWS for any native or game fish species and 

do not provide habitat for recreationally important fish species. The on-site stormwater 

pond does not provide significant aquatic habitat, therefore, expansion of the stormwater 

pond would not adversely affect aquatic resources at the LNG storage facility site. FGS 

proposes to construct the Project in accordance with our Procedures, ensuring that the 

physical characteristics of the drainage ditches that may provide aquatic habitat are 

restored to pre-Project conditions. Therefore, we conclude that the Project would not 

have any significant adverse effects on aquatic resources. 
5.0 – Conclusions and Recommendations 5-4 

5.1.7 Threatened, Endangered, and Special Status Species 

Four federally-listed endangered or threatened species may occur in the Project area. 

Based on our review of FWS species accounts and field survey information provided by 

FGS, we have determined that the Project would have no effect on the Audubon crested 

caracara. We have also determined that the Project is not likely to adversely affect the 

wood stork, the American alligator, or the Eastern indigo snake. 

The wood stork is highly mobile and not dependent upon the industrial land use at the 

LNG storage facility site. It does not use the storage facility site or proposed pipeline 

corridor for nesting, and large areas of suitable foraging habitat are available in the 

vicinity. The Project is designed to avoid forested wetland areas and any impacts to 

emergent and scrub-shrub wetlands and vegetated ditches along the pipeline corridor that 

the wood stork uses for foraging would be temporary. All areas would be restored. No 

loss of potential foraging habitat for the wood stork would occur. 

At the LNG storage facility site, a single alligator was observed in one of the ponds and 

other individuals may inhabit other open water habitats and wetlands in the vicinity of the 

site. FGS proposes to expand one of the ponds on-site to provide increased stormwater 

management capacity. Temporary construction impacts to the American alligator are 

likely to be minor and of short duration. During the expansion of the stormwater pond, it 

is likely that individual alligators that may be in the pond would temporarily relocate to 

adjacent ponds on-site. Expansion of the stormwater pond would ultimately provide 

additional suitable habitat. 

Although no Eastern indigo snakes were observed on the LNG storage facility site or 

along the pipeline corridor, FGS surveys identified several gopher tortoise burrows on the 

proposed storage facility site. Gopher tortoise burrows are commonly used by the 

Eastern indigo snake. FGS would obtain a pre-clearing gopher tortoise relocation permit 

from the FFWCC to excavate any burrows within 25 feet of construction areas prior to 

initiation of construction. Any Eastern indigo snakes captured during gopher tortoise 

relocation efforts would also be relocated to an approved on-site or off-site location in 

consultation with FFWCC and FWS representatives. In addition to these measures, FGS 

has agreed to implement the FWS Standard Protection Measures for the Eastern Indigo 

Snake. 

We have been informally consulting with the FWS, which is a cooperating agency in the 

preparation of this EIS, regarding Project effects on these listed species. In a letter dated 

June 2, 2008, the FWS concurred with the findings of the EIS that the Project would not 

affect or would not likely adversely affect any federally-listed species. In a letter dated 

June 27, 2008, the FWS also concurred that the Project would have no affect on listed 

species at the Tampa Farms construction staging area. Consequently, the Commissions 

required consultation under Section 7 of the Endangered Species Act is complete. 

Six state-listed species may also be found at the Project. Nine active gopher tortoise 

burrows were observed at the LNG storage facility site. FGS has proposed measures to 

capture the tortoises during construction and relocate them to an on-site preserve. Five 

state-listed birds are also found in the Project area, but suitable habitat does not exist at 

the Project for nesting. Foraging habitats would only be temporarily affected by 
5-5 5.0 – Conclusions and Recommendations

construction and would be immediately restored. Therefore, we conclude that the Project 

would not have any significant adverse effect on state-listed species. In an e-mail dated 

June 14, 2007, the FFWCC stated they had no official comment on the Project but did not 

find any substantive issues with the Project and believe the impacts to state-listed species 

should be negligible. 

5.1.8 Land Use, Recreation, and Visual Resources 

Project construction would require 55.58 acres for the LNG storage facility and 71.45 

acres for the construction right-of-way, construction staging area, the M&R station, and 

pipeline interconnections. Project operations would require 53.10 acres for the LNG 

storage facility and 25.30 acres for the permanent 50-foot-wide pipeline right-of-way, the 

M&R station, and pipeline interconnections. The Project would be consistent with 

current zoning and future land use plans by Martin County and compatible with 

surrounding land uses, which are principally industrial or agri-business in nature (e.g., 

Cogentrix power plant, Louis Dreyfus citrus processing plant, Tampa Farms wholesale 

egg facility). 

The Project would have no effect on recreation resources or special interest areas. No 

residences are located within 0.6 mile of the pipeline right-of-way. There are three 

residences within 0.50 mile of the LNG storage facility, with the nearest residence 

located approximately 0.46 mile away. Although the storage tanks would be visible to 

the surrounding area, the storage facility site has an established industrial character and is 

adjacent to other industrial uses. As a result, the visual changes resulting from tank 

construction and operation would be visually consistent with the character of the area. 

The FDEP approved the ERP permit for the Project on March 19, 2008, which included 

the federal coastal zone consistency determination; therefore, the Project is consistent 

with the federal CZMA. 

5.1.9 Socioeconomics 

Construction of the Project would not have a significant adverse impact on local 

population, housing, employment, community services, or local commerce. Any adverse 

impacts would be highly localized and temporary. Project construction would 

temporarily increase demand for housing and public services such as medical and law 

enforcement, but these effects would be temporary and limited to the construction period. 

During Project operation, the LNG storage facility would have self-contained safety, fire, 

and security resources and would not require these services from the community. 

Pursuant to DOT regulations, FGS would coordinate with local emergency responders 

regarding pipeline facilities and public safety. In addition, facility operation would only 

require 32 permanent staff, which would present a negligible increase in the demand for 

housing and public services. 

The Project would have a beneficial effect on government tax revenues. In addition to 

fees paid to the Martin County Building Department by FGS during construction, local 

spending by construction employees and the Project would increase sales tax revenues 

locally. During operation, FGS would pay a minimum of $1.6 million annually in 
5.0 – Conclusions and Recommendations 5-6 

property taxes to the county as well as corporate income tax (5.5 percent annually) to the 

State. Annual payroll during operations is estimated at $2.2 million per year. 

No residences are located within 0.6 mile of the proposed pipeline construction work 

areas. There are three residences within 0.50 mile of the LNG storage facility, with the 

nearest residence located approximately 0.46 mile away. The proposed storage facility 

and pipeline corridor avoid populated areas, minimizing the number of persons at risk of 

injury due to an accident at the storage facility or a pipeline failure. Although the 

proposed storage facility would emit some air emissions during normal Project operation, 

these emissions would be minor, below PSD applicability thresholds, and not a public 

health hazard. The potential health risk from Project operations would be extremely 

small, while potential economic benefits would be substantial. Although the racial and 

economic composition of the Indiantown Census County Division does not appear to 

meet the EPA definition of a minority or low-income community, the Project is 

proximate to the Indiantown CDP, which does have a minority population that is 

meaningfully higher than the general area. There is no evidence, however, that the 

proposed Project would have any significantly higher or adverse environmental or human 

health effects and would not result in any environmental justice issues. 

5.1.10 Transportation 

Project construction would occur over 36 months and involve a peak of approximately 

450 workers. FGS proposes to mitigate any temporary traffic problems by scheduling 

shifts and truck deliveries for off-peak hours, providing temporary traffic lights, and 

using off-duty representatives of the Martin County Sheriff’s Department to avoid any 

congestion. No construction would occur on public roads and no road closures or detours 

are planned. 

The Project expects to have up to 33 full-time employees. The traffic generated by this 

number of employees would be minor compared to average daily traffic on SR 710 (i.e., 

7,800 vehicles per day). Therefore, we conclude that the Project would not have any 

significant adverse effect on transportation or traffic conditions in the Project area. 

5.1.11 Cultural Resources 

FGS conducted cultural resource surveys on the LNG storage facility site and pipeline 

corridor, as well as at the proposed M&R station site, access roads, and temporary 

workspaces. No archaeological sites were identified within the Project area. In addition, 

a survey was completed of historic properties in the surrounding area, which did not 

identify any sites as eligible for listing in the National Register of Historic Places. The 

Cultural Resource Assessment Survey Reports for the Project and Tampa Farms 

construction staging area were reviewed by the Florida Division of Historical Resources, 

which concurred with the findings of the reports and agreed that no further investigation 

is necessary. FGS contacted five Native American groups regarding the Project. FGS 

also held informal conversations with both the Seminole THPO and Miccosukee Section 

106 representative, both of whom concurred with the findings of the cultural resource 

studies. 
5-7 5.0 – Conclusions and Recommendations

5.1.12 Air Quality and Noise 

Air quality impacts associated with construction of the Project would include emissions 

from construction equipment and fugitive dust. Such air quality impacts, however, would 

be temporary and localized and would not cause or contribute to a violation of applicable 

air quality standards. The proposed LNG storage facility would emit air pollutants as a 

result of operation. Project emissions would be minimized through the use of low NOx

burners for the WEG heaters; use of clean-burning natural gas fuels; and appropriate 

operation and maintenance procedures. In addition, the facility would be operated in 

compliance with federal and state air quality regulations driven by the CAA. The Project 

would not be subject to Prevention of Significant Deterioration permitting and would not 

exceed NAAQS thresholds. Since Martin County is classified as an attainment area for 

all criteria pollutants, a General Conformity review of the Project is not required. 

Therefore, we conclude that the Project would not have a significant adverse effect on air 

quality. 

Noise would be generated during construction of the pipelines and during construction 

and operation of the LNG storage facility. Impacts to noise quality associated with 

construction would generally be temporary, minor, and limited mostly to daylight hours. 

The proposed storage facility would generate noise on a continuous basis during 

operation, but potential noise-related impacts would be limited to the vicinity of the 

facility and modeling indicates that facility noise would be below 55 dBA at NSAs. In 

addition, we are recommending that FGS complete post-construction noise surveys and 

implement additional mitigation measures, if required, to ensure that actual noise levels 

resulting from Project operations would not exceed 55 dBA. Therefore, we conclude that 

the Project would not have a significant adverse effect on noise in the Project area. 

5.1.13 Reliability and Safety 

Our evaluation of the front-end-engineering design of the proposed LNG storage facility 

included a review of the cryogenic safety; thermodynamics; heat transfer, 

instrumentation; cryogenic processes; and other relevant safety systems. As a result of 

the technical review of the proposed design of the LNG storage facility, we have 

identified a number of concerns relating to the reliability, operability, and safety of the 

proposed design and are making recommendations to address these issues. Compliance 

with these recommendations would need to be demonstrated by FGS prior to initial site 

preparation, prior to construction, after final design, prior to commissioning, or prior to 

commencement of service. Therefore, we believe that appropriate features and 

modifications would be incorporated into the facility design to enhance the safety and 

operability of the proposed LNG storage facility. In addition, we believe that the 

proposed facility complies with the siting requirements of Title 49, CFR, Part 193. 

FGS would comply with DOT’s pipeline material and construction standards for natural 

gas pipelines. After construction, FGS must implement a pipeline integrity management 

plan to ensure public safety during operation of the pipeline. 
5.0 – Conclusions and Recommendations 5-8 

5.1.14 Alternatives 

This EIS addresses alternatives to the proposed action. The FERC can deny the Project, 

postpone the issuance of a Certificate pending further study, or issue a Certificate for the 

Project as proposed or modified by location or condition. 

No Action or Postponed Action Alternatives 

The No Action or Postponed Action Alternatives would deny or defer the Project. While 

these alternatives would avoid the environmental impacts identified in this EIS, the 

objectives of the Project would not be met and customers and other markets in Florida 

would be denied the flexible and reliable gas supply that could be provided by the 

Project. This in turn could lead to higher natural gas prices, the use of alternative sources 

of energy, or proposals to develop natural gas import and transmission infrastructure. 

While conservation and the development of other sources of energy are anticipated to 

play a part in meeting the future energy needs of the country, they are not expected to 

significantly reduce the need for additional gas supplies. Therefore, we conclude that the 

No Action and Postponed Action Alternatives are not preferable to the proposed action. 

System Alternatives 

Our analysis of system alternatives included an evaluation of alternative LNG storage 

facilities (e.g., underground storage), other planned or proposed LNG terminal projects, 

and pipeline expansions. Due to the geology in the state, very few suitable underground 

storage caverns exist within Florida and none are located in the southern part of the state. 

As a result, the typical underground storage options are not viable system alternatives to 

the proposed action. 

Four LNG import terminals have been proposed near to, but outside of, Florida and are in 

varying stages of development. Two terminals have been proposed as onshore import 

terminals in the Bahamas, but neither of these have yet been approved by the Bahamian 

government. The other two terminals are deepwater port proposals subject to review by 

the USCG and approval by the Maritime Administration. Our analysis determined that 

these projects are not viable alternatives to the proposed Project because the four LNG 

import terminals cannot be in service within the needed timeframe; or cannot perform 

storage and peaking service. 

The proposed Project is not an energy source itself, but is needed to improve current 

electrical generating system reliability. To the extent that this Project could make gas 

fired generating facilities more attractive because of improved reliability, we discussed 

the status of alternative energy sources and energy conservation in Florida. The Florida 

Public Services Commission concluded that energy demand forecasts continue to surpass 

current energy conservation and renewable energy programs offered by Florida’s utilities 

and that local utilities should continue investigating natural gas supply and delivery 

options such as natural gas storage to maintain diversity in the face of unplanned supply 

or distribution disruptions. 

Expansion, looping, and added compression to existing pipelines were also considered. 

Pipeline system expansions, consisting of the construction of large-diameter pipelines, 
5-9 5.0 – Conclusions and Recommendations

looping of constrained portions of the pipelines, or additional compression would not 

provide needed storage capacity nor satisfy the Project objective of having supply 

available in Florida to serve the region during peak demand periods and weather related 

shut-ins when pipeline deliveries are curtailed or disrupted, and are not considered a 

viable alternative to the proposed Project. 

Site and Route Alternatives 

In addition to system alternatives, we evaluated six alternative LNG storage facility sites 

in south Florida and three alternative pipeline corridors. Our evaluation of sites 

considered zoning and land use compatibility, wetlands avoidance, proximity to interstate 

natural gas pipelines, suitability for proposed use, and proximity to the market area. 

None of the alternative storage facility sites we evaluated are considered to be 

environmentally preferable to the proposed storage facility site. None of the alternative 

pipeline routes offered any environmental advantages to the proposed route. 

In summary, we have determined that the proposed Project, as modified by our 

recommended mitigation measures, is the preferred alternative that can meet the Project 

purpose. 

5.2 FERC STAFF’S RECOMMENDED MITIGATION 

If the Commission issues a Certificate for the proposed Project, we are recommending 

that the Commission’s Order include the following specific conditions. We believe that 

these measures would further mitigate the environmental impacts associated with the 

construction and operation of the proposed Project. 

1. FGS shall follow the construction procedures and mitigation measures described 

in its application, supplemental filings (including responses to staff data requests), 

and as identified in this EIS, unless modified by the Order. FGS must: 

a. request any modification to these procedures, measures, or conditions in a 

filing with the Secretary; 

b. justify each modification relative to site-specific conditions; 

c. explain how that modification provides an equal or greater level of 

environmental protection than the original measure; and 

d. receive approval in writing from the Director of the OEP before using 

that modification. 

2. For pipeline facilities, the Director of OEP has delegated authority to take 

whatever steps are necessary to ensure the protection of all environmental 

resources during construction and operation of the Project. This authority shall 

allow: 

a. the modification of conditions of the Commission’s Order; and 

b. the design and implementation of any additional measures deemed 

necessary (including stop work authority) to assure continued compliance 
5.0 – Conclusions and Recommendations 5-10 

with the intent of the environmental conditions as well as the avoidance or 

mitigation of adverse environmental impact resulting from Project 

construction and operation. 

3. For the LNG facility, 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. 

4. Prior to any construction, FGS shall file an affirmative statement with the 

Secretary, certified by a senior company official, that all company personnel, 

environmental inspectors, and contractor personnel will be informed of the 

environmental inspector's authority and have been or will be trained on the 

implementation of the environmental mitigation measures appropriate to their 

jobs before becoming involved with construction and restoration activities. 

5. The authorized facility locations shall be as shown in the EIS, as supplemented by 

filed alignment sheets. As soon as they are available, and before the start of 

construction, FGS 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. 

 FGS’ exercise of eminent domain authority granted under Natural Gas Act section 

7(h) in any condemnation proceedings related to the Order must be consistent 

with these authorized facilities and locations. FGS’ right of eminent domain 

granted under Natural Gas Act section 7(h) does not authorize it to increase the 

size of its natural gas pipeline to accommodate future needs or to acquire a rightof-way for a pipeline to transport a commodity other than natural gas. 

6. FGS 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 will 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, and documentation of landowner 

approval, whether any cultural resources or federally listed threatened or 

endangered species will be affected, and whether any other environmentally 

sensitive areas are within or abutting the area. All areas shall be clearly identified 

on the maps/sheets/aerial photographs. Each area must be approved in writing by 

the Director of OEP before construction in or near that area. 
5-11 5.0 – Conclusions and Recommendations

This requirement does not apply to extra workspace allowed by our Plan, minor 

field realignments per landowner needs and requirements which 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. At least 60 days before the start of construction, FGS shall file an initial 

Implementation Plan with the Secretary for review and written approval by the 

Director of OEP describing how FGS will implement the mitigation measures 

required by the Order. FGS must file revisions to the plan as schedules change. 

The plan shall identify: 

a. how FGS 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; 

b. the number of environmental inspectors assigned, and how the company 

will ensure that sufficient personnel are available to implement the 

environmental mitigation; 

c. company personnel, including environmental inspectors and contractors, 

who will receive copies of the appropriate material; 

d. the training and instructions FGS will give to all personnel involved with 

construction and restoration (initial and refresher training as the Project 

progresses and personnel change) with the opportunity for OEP staff to 

participate in the training session(s); 

e. the company personnel (if known) and specific portion of FGS’ 

organization having responsibility for compliance; 

f. the procedures (including use of contract penalties) FGS will follow if 

noncompliance occurs; and 

g. 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 mitigation training of on-site personnel; 

iii. the start of construction; and 
5.0 – Conclusions and Recommendations 5-12 

iv. the start and completion of restoration. 

8. FGS shall employ at least one environmental inspector. The environmental 

inspector 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. FGS shall file updated status reports prepared by the environmental inspector with 

the Secretary on a bi-weekly basis 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. the current construction status of the Project, work planned for the 

following reporting period, and any schedule changes for stream crossings 

or work in other environmentally sensitive areas; 

b. a listing of all problems encountered and each instance of noncompliance 

observed by the environmental inspector 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); 

c. corrective actions implemented in response to all instances of 

noncompliance, and their cost; 

d. the effectiveness of all corrective actions implemented; 

e. a description of any landowner/resident complaints which may relate to 

compliance with the requirements of the Order, and the measures taken to 

satisfy their concerns; and 

f. copies of any correspondence received by FGS from other federal, state or 

local permitting agencies concerning instances of noncompliance, and 

FGS’ response. 
5-13 5.0 – Conclusions and Recommendations

10. FGS must receive written authorization from the Director of OEP before 

commencing service from the Project. Such authorization will only be granted 

following a determination that the LNG facility has been constructed in 

accordance with Commission approval and applicable standards, can be expected 

to operate safely as designed, and the rehabilitation and restoration of the right-ofway is proceeding satisfactorily. 

11. Within 30 days of placing the certificated facilities in service, FGS 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 certificate conditions FGS has complied with or 

will comply with. This statement shall also identify any areas affected by 

the Project where compliance measures were not properly implemented, if 

not previously identified in filed status reports, and the reason for 

noncompliance. 

12. FGS shall develop a Standard Operating Procedure for Herbicide Use that meets 

EPA requirements. (Section 4.4.2)

13. FGS shall make all reasonable efforts to assure its predicted noise levels from the 

LNG storage facility are not exceeded at nearby NSAs and file noise surveys 

showing this with the Secretary no later than 60 days after placing the LNG 

storage facility in service. However, if the noise attributable to the operation of 

the LNG storage facility at full load exceeds an Ldn of 55 dBA at any nearby 

NSAs, FGS shall file a report on what changes are needed and shall install 

additional noise control to meet the level within one year of the in-service date. 

FGS shall confirm compliance with this requirement by filing a second noise 

survey with the Secretary no later than 60 days after it installs the additional 

noise controls. (Section 4.11.2)

Recommendations 14 through 23 shall apply to the Project design and construction 

details. All detailed design documents (drawings, calculations, specifications, etc.) 

and design submittals shall satisfy the requirements of Section 4, Part II of the 

FERC’s Draft Seismic Design Guidelines and Data Submittal Requirements for LNG 

Facilities, January 2007 (draft Seismic Design Guidelines). The following 

information shall be filed with the Secretary for review and approval by the 

Director of OEP either prior to the issuing of requests for quotations; prior to 

construction; or prior to commissioning as indicated by each specific condition. 

14. File a detailed plan, including calculations, for the LNG tank foundation 

surcharge, prior to construction. (Section 4.1.4)

15. File a list of all structures, systems, and components that are assigned Seismic 

Category I prior to construction for review as described in section 3.6 of Part II 

of the FERC Seismic Guidelines. (Section 4.1.4)
5.0 – Conclusions and Recommendations 5-14 

16. Seismic Design Criteria shall be provided for all Seismic Design Category I 

structures, systems, and components as described in section 3.7 of Part II of the 

FERC Seismic Guidelines prior to construction. The Seismic Design Criteria 

shall satisfy Part I of the FERC Seismic Guidelines. (Section 4.1.4)

17. LNG Tank and Foundation Design shall comply with Part I of the FERC Seismic 

Guidelines. Submittals that demonstrate compliance shall be provided prior to 

construction. (Section 4.1.4)

18. Final foundation design recommendations for all other Seismic Category I 

structures shall be submitted for review and approval prior to construction. 

(Section 4.1.4)

19. All items identified in the submitted geotechnical/seismic reports which were 

proposed to be addressed during the detailed design shall be submitted for review 

and approval prior to construction. (Section 4.1.4)

20. Seismic specifications to be used in conjunction with the procuring equipment as 

described in section 3.10 of Part II of the FERC Seismic Guidelines shall be 

submitted for review prior to the issuing of requests for quotations. (Section 

4.1.4)

21. Quality Control and Assurance procedures as described in section 3.11 of Part II 

of the FERC Seismic Guidelines that will be used for design and construction 

shall be submitted for review prior to construction of the project. (Section 

4.1.4)

22. A seismic instrumentation plan as described in section 3.12 of Part II of the FERC 

Seismic Guidelines shall be provided prior to commissioning. (Section 4.1.4)

23. The results of the hydrostatic load tests on the LNG storage tanks, including 

settlement data as described in section 7.4.1 of the FERC Seismic Guidelines shall 

be provided prior to commissioning. (Section 4.1.4)

Recommendations 24 through 91 shall apply to the FGS design and construction 

details. Information pertaining to these specific recommendations shall be filed with 

the Secretary for review and approval by the Director of OEP either: prior to initial 

site preparation; prior to construction of final design; prior to commissioning; or 

prior to commencement of service as indicated by each specific condition. Specific 

engineering, vulnerability, or detailed design information meeting the criteria 

specified in Order No. 683 (Docket No. RM06-24-000), including security 

information, shall be submitted as critical energy infrastructure information (CEII) 

pursuant to 18 CFR 388.112. See Critical Energy Infrastructure Information, 

Order No. 683, 71 Fed. Reg. 58,273 (October 3, 2006). FERC Stats. & Regs. ¶ 

31,228 (2006). Information pertaining to items such as: offsite emergency response; 

procedures for public notification and evacuation; and construction and operating 

reporting requirements would be subject to public disclosure. This information shall 

be submitted a minimum of 30 days before approval to proceed is required. 

24. Complete plan drawings and a list of the hazard detection equipment shall be filed 

prior to initial site preparation. The list shall include the instrument tag 
5-15 5.0 – Conclusions and Recommendations

number, type and location, alarm locations, and shutdown functions of the 

proposed hazard detection equipment. Plan drawings shall clearly show the 

location of all detection equipment. (Section 4.12.2)

25. FGS shall provide a technical review of its proposed facility design that: 

a. identifies all combustion/ventilation air intake equipment and the distances 

to any possible hydrocarbon release (LNG, flammable refrigerants, 

flammable liquids and flammable gases); 

b. demonstrates that these areas are adequately covered by hazard detection 

devices and indicate how these devices would isolate or shutdown any 

combustion equipment whose continued operation could add to or sustain 

an emergency. 

FGS shall file this review prior to initial site preparation. (Section 4.12.2) 

26. Complete plan drawings and a list of the fixed and wheeled dry-chemical, fire 

extinguishing, and other hazard control equipment shall be filed prior to initial 

site preparation. The list shall include the equipment tag number, type, size, 

equipment covered, and automatic and manual remote signals initiating discharge 

of the units. Plan drawings shall clearly show the planned location of all fixed 

and wheeled extinguishers. (Section 4.12.2)

27. Facility plan drawings showing the proposed location of, and area covered by, 

each monitor, hydrant, deluge system, hose, and sprinkler, as well as piping and 

instrumentation diagrams of the fire water system, shall be filed prior to initial 

site preparation. (Section 4.12.2)

28. FGS shall perform a hazard design review, which addresses operability, 

reliability, and safety, of the updated intermediate process and instrumentation 

diagrams (P&IDs). A copy of the hazard design review, the list of 

recommendations that are to be incorporated in the final facility design, and the 

updated intermediate P&IDs shall be filed prior to initial site preparation. 

(Section 4.12.2)

29. Drawings of the storage tank piping support structure and support of horizontal 

piping at grade shall be filed prior to initial site preparation. (Section 4.12.2)

30. Procedures shall be developed for offsite contractors’ responsibilities, restrictions, 

limitations and supervision of these contractors by FGS staff, prior to initial site 

preparation. (Section 4.12.2) 

31. FGS shall file step-by-step calculations showing how the vapor production rate 

from a single trench element over a 10 minute period was determined, prior to 

initial site preparation. (Section 4.12.3)

32. FGS shall file revised vapor dispersion simulations with the following 

information, prior to initial site preparation: 
5.0 – Conclusions and Recommendations 5-16 

a. a quantitative grid sensitivity analysis that supports the selection of grid 

size and demonstrates the convergence of the downwind dispersion 

distances; 

b. simulations with mirror boundary conditions for the side and top 

boundaries; 

c. simulations that allow the wind profile to reach a steady or quasi-steady 

state before injecting LNG vapor into the domain; 

d. a sensitivity analysis and technical justification that supports the slip factor 

value used to determine the downwind dispersion distances; 

e. an evaluation of the effect that the “reaction flag” in the source code to 

FDS has on the downwind dispersion distances; 

f. technical justification and/or sensitivity analyses that support the selection 

of the lapse rate, ground surface material properties, temperature, 

humidity, and wind profile used to determine the downwind dispersion 

distances; and 

g. all pertinent input files (*.fds) and output files (*.out) used to determine 

the downwind dispersion distances. (Section 4.12.3)

33. FGS shall provide information/revisions related to the 39 responses to the January 

17, 2008 Engineering Information Request which stated that corrections, or 

modifications would be made to the design. The final design shall specifically 

address response numbers 4, 6, 7, 11, 17, 18, 21, 22, 24, 27, 28, 29, 30, 33, 35, 36, 

37, 38, 41, 42, 43, 49, 55, 58, 60, 61, 62, 63, 65, 67, 73, 76, 77, 78, 80, 83, 91, 94, 

and 99 using management of change procedures. (Section 4.12.2)

34. The final design shall clearly and consistently show the design of the process 

systems on both the process flow diagrams (PFDs) and P&IDs. (Section 4.12.2)

35. The P&IDs in the final design shall show and number all valves including drain, 

vent, main, and car sealed. (Section 4.12.2)

36. The final design shall specify that the set pressure of PAH-11055 shall not be 

greater than 50 psig below the design pressure of the system. (Section 4.12.2)

37. The final design shall include layout provisions for the installation of an adsorber 

feed gas cooler and chiller system. (Section 4.12.2)

38. In the event that ceramic support material is used to retain the molecular sieve, the 

final design shall include a witch hat type strainer at the bottom outlet of each 

adsorber, designed to retain support material. (Section 4.12.2)

39. The final design shall include a shutoff valve at the inlet to the NGL extraction 

exchanger. This valve may be the proposed manual isolation valve equipped with 

an actuator operated by the Safety Instrumentation System (SIS). (Section 4.12.2)

40. The final design shall include an isolation valve downstream of the ethylene 

pressure regulator. (Section 4.12.2)
5-17 5.0 – Conclusions and Recommendations

41. The final design shall include a hazard and operability review of the completed 

design. A copy of the review and a list of the recommendations shall be filed 

with the Secretary. (Section 4.12.2)

42. The final design shall specify that the LNG tank carbon steel piping support 

plates and connections to piping supports shall be designed to ensure that 

corrosion protection is adequately provided and provisions for corrosion 

monitoring and maintenance of carbon steel attachments are to be included in the 

design and maintenance procedures. (Section 4.12.2)

43. The final design of the tank foundation shall include an inclinometer, 

instrumented to record and display tank settlement, with a minimum of eight 

permanent reference points equally spaced round the base for elevation survey 

measurement. (Section 4.12.2)

44. The final design shall include details of the LNG tank tilt settlement and 

differential settlement limits between each LNG tank and piping and procedures 

to be implemented in the event that limits would be exceeded. (Section 4.12.2)

45. The final design shall include detailed drawings of the spill control system to be 

applied to the LNG tank roof. (Section 4.12.2)

46. The final design shall provide a discretionary vent for each LNG tank that can 

relieve the tank pressure when the tank is isolated from the boiloff vapor system. 

(Section 4.12.2)

47. The final design shall include a recycle line from the top of the sendout pump 

suction header to storage. (Section 4.12.2)

48. The final design shall specify that the first isolation valve at the inlet to the 

sendout pumps would be a weld end shutoff valve. In the case that flanged valves 

would be specified, the sendout system should be shutdown in the event of a leak. 

(Section 4.12.2)

49. The final design shall provide a minimum flow recycle line from the sendout 

pumps to the LNG storage tanks. The piping including the isolation valve 

upstream of the discharge to the storage tanks shall be the same pressure and 

temperature rating as the piping at the discharge of the sendout pumps. (Section 

4.12.2)

50. The final design shall include provisions to drain and purge the LNG inlet piping 

to the vaporizer to a safe location. (Section 4.12.2)

51. The final design shall specify that the LNG isolation valve from the inlet header 

to the vaporizer is to be a weld end shutoff valve operated by the SIS. In the case 

that flanged valves would be specified, the sendout system should be shutdown in 

the event of a leak. (Section 4.12.2)

52. The final design shall specify the vaporizer discharge valve to the outlet header to 

be a weld end shutoff valve operated by the SIS. In the case that flanged valves 

would be specified, the sendout system should be shutdown in the event of a leak. 

(Section 4.12.2)
5.0 – Conclusions and Recommendations 5-18 

53. The final design shall specify that the shell side of the LNG vaporizer is to be 

equipped with a full flow bursting disc sized for tube failure. (Section 4.12.2)

54. The final design shall include provisions to transmit the flow measurement of the 

WEG solution to each LNG vaporizer to the distributed control system (DCS). 

(Section 4.12.2)

55. The final design shall include provisions to limit the LNG flow to the effective 

vaporization capacity of the circulating WEG at any time. (Section 4.12.2)

56. The final design shall include a pilot relief valve, or operated vent valve, sized for 

thermal relief and located at the discharge of each vaporizer upstream of the 

isolation valves. (Section 4.12.2)

57. The final design shall include shutoff valves operated by the SIS at the suction 

and discharge of the boiloff, tail gas, and NGL compressors. (Section 4.12.2)

58. The final design shall specify that manual bypass valves shall be car sealed 

closed. (Section 4.12.2)

59. The final design shall specify that all drains from LNG and refrigerant systems 

are to be equipped with double isolation and bleed valves. (Section 4.12.2)

60. The final design shall specify that, for LNG and natural gas service, branch 

piping and piping nipples less than 50mm (2 inches), are to be no less than 

schedule 160. (Section 4.12.2)

61. The final design shall include provisions to flare cryogenic and heavy 

hydrocarbon vapors currently shown as being discharged to atmosphere through 

the vent stack. (Section 4.12.2)

62. The final design shall specify that the vent/flare stack separator vessel shall be 

equipped with low level alarm, high level alarm and high-high level alarm. 

(Section 4.12.2)

63. The final design shall specify that in the event that high-high level occurs in 

vent/flare stack separator vessel, the facility shall be shut down until the liquid has 

been removed to below the low level alarm limit. (Section 4.12.2)

64. The final design shall provide P&IDs, specifications and procedures that clearly 

show and specify the tie-in details required to safely connect the Phase 2 

expansion. (Section 4.12.2)

65. Layout and elevation drawings of the process equipment that are appropriate for 

the proposed operation and maintenance of the facility shall be included in the 

final design and submitted to the FERC at the time that the EPC contractor issues 

the drawing for review. This milestone shall be included in the project schedule. 

(Section 4.12.2)

66. The final design shall specify that the hazardous area classification of the areas 

containing liquefaction exchangers, LNG pumps, LNG vessels, and inlet and 

outlet of LNG vaporizers would be as Class 1, Group D, Division 1. (Section 

4.12.2)
5-19 5.0 – Conclusions and Recommendations

67. The final design shall include details of the air gaps to be installed downstream of 

all seals or isolations that are located 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 4.12.2)

68. The final design shall include audible and visual warning at buildings with 

instrument air service when nitrogen is supplied to the instrument air system. 

(Section 4.12.2)

69. The final design shall provide automatic shutoff of the fuel gas to the fuel gas 

heaters, upstream of the pressure regulators. (Section 4.12.2)

70. The final design shall include detection of flammable gas from the shell side vent 

of the LNG vaporizer and in the WEG system. Alarm and shutdown of equipment 

shall be provided as appropriate. (Section 4.12.2)

71. The final design of the hazard detection equipment shall identify manufacturer 

and model. (Section 4.12.2)

72. The final design shall specify that all hazard detection equipment shall include 

redundancy fault detection and fault alarm monitoring in all potentially hazardous 

areas and enclosures. (Section 4.12.2)

73. The final design of the fixed and wheeled dry-chemical, fire extinguishing and 

high expansion foam hazard control equipment shall identify the manufacturer 

and model. (Section 4.12.2)

74. The final design shall include an updated fire protection evaluation in accordance 

with the requirements of NFPA 59A 2001, chapter 9.1.2. (Section 4.12.2)

75. The final design shall specify that multiple cameras shall be installed to monitor 

the entry/exit gate and approach to the facility entrance. (Section 4.12.2)

76. The final design of the firewater system shall include provisions to measure and 

record the discharge flow and pressure from each of the firewater pumps. 

(Section 4.12.2)

77. The final design shall include an uninstalled spare firewater jockey pump. 

(Section 4.12.2)

78. The final design shall include details of the shut down logic, including cause and 

effect matrices for alarms and shutdowns. (Section 4.12.2)

79 The final design shall specify that all ESD valves are to be equipped with open 

and closed position switches connected to the DCS/SIS. (Section 4.12.2)

80. The final design shall include emergency shutdown of equipment and systems 

activated by hazard detection devices for flammable gas, fire, and cryogenic 

spills, when applicable. (Section 4.12.2) 
5.0 – Conclusions and Recommendations 5-20 

81. The final design shall include drawings, P&IDs, and specifications for the 

mounding system and the coatings and cathodic protection system for the vessels. 

(Section 4.12.3)

82. The maintenance procedures to be filed prior to commissioning shall state that a 

foundation elevation survey of all LNG tanks shall be made on an annual basis. 

(Section 4.12.2)

83. All valves including drain, vent, main, and car sealed, or locked valves shall be 

tagged in the field during construction and prior to commissioning. (Section 

4.12.2)

84. The car seal procedure and car seal control logs for all valves shall be provided 

prior to commissioning. (Section 4.12.2)

85. A tabulated list of the proposed hand-held fire extinguishers shall be filed prior 

to commissioning. The information shall include a list with the equipment 

number, type, size, number, and location. Plan drawings shall include the type, 

size, and number of all hand-held fire extinguishers. (Section 4.12.2)

86. Operation and Maintenance procedures and manuals, as well as emergency 

response plans and safety procedures, shall be filed prior to commissioning. 

(Section 4.12.2)

87. The Operations and Maintenance procedures to be provided prior to 

commissioning, shall state that filters are not to be opened unless the unit can be 

completely depressurized when isolated. (Section 4.12.2)

88. The contingency plan for failure of the LNG tank outer containment shall be filed 

prior to commissioning. (Section 4.12.2)

89. A copy of the criteria for horizontal and rotational movement of the inner tank for 

use during and after cool down shall be filed prior to commissioning. (Section 

4.12.2)

90. The FERC staff shall be notified of any proposed revisions to the security plan 

and physical security of the facility prior to commencement of service. (Section 

4.12.2)

91. Progress on construction of the project shall be reported in monthly reports filed 

with the Secretary. Details shall include a summary of activities, projected 

schedule for completion, problems encountered and remedial actions taken. 

Problems of significant magnitude shall be reported to the FERC within 24 

hours. (Section 4.12.2)

In addition, recommendations 92 through 97 shall apply throughout the life of the 

facility: 

92. The facility shall be subject to regular FERC staff technical reviews and site 

inspections on at least a biennial basis or more frequently as circumstances 

indicate. Prior to each FERC staff technical review and site inspection, FGS shall 

respond to a specific data request including information relating to possible 
5-21 5.0 – Conclusions and Recommendations

design and operating conditions that may have been imposed by other agencies or 

organizations. Up-to-date detailed piping and instrumentation diagrams reflecting 

facility modifications and provision of other pertinent information not included in 

the semi-annual reports described below, including facility events that have taken 

place since the previously submitted annual report, shall be submitted. (Section 

4.12.2)

93. Semi-annual operational reports shall be filed with the Secretary to identify 

changes in facility design and operating conditions, abnormal operating 

experiences, activities (including trucking, quantity and composition of feed gas 

and trucked LNG, vaporization quantities, boil-off/flash gas, etc.), plant 

modifications including future plans and progress thereof. Abnormalities shall 

include, but not be limited to: trucking problems, 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, vapor or liquid releases, fires involving 

natural gas and/or from other sources, negative pressure (vacuum) within a 

storage tank and higher than predicted boiloff 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 the FERC staff with early notice of 

anticipated future construction/maintenance projects at the LNG facility. (Section 

4.12.2)

94. FGS shall include completed car seal control logs with the first two Semi-annual

operational reports filed with the Commission. (Section 4.12.2)

95. In the event the temperature of any region of any secondary containment 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 4.12.2)

96. FGS shall develop a traffic control plan coordinated with local authorities to 

address LNG and NGL truck transportation from the facility. This plan shall be 

incorporated into the facility’s operation and maintenance procedures and 

manuals prior to any trucking activities at the LNG facility. (Section 4.12.4)

97. Significant non-scheduled events, including safety-related incidents (i.e., LNG or 

natural gas releases, fires, explosions, mechanical failures, unusual over 

pressurization, and major injuries) and security related incidents (i.e., attempts to 

enter site, suspicious activities) shall be reported to FERC staff. In the event an 

abnormality is of significant magnitude to threaten public or employee safety, 

cause significant property damage, or interrupt service, notification shall be made 

immediately, without unduly interfering with any necessary or appropriate 

emergency repair, alarm, or other emergency procedure. In all instances, 
5.0 – Conclusions and Recommendations 5-22 

notification shall be made to the Commission within 24 hours. This notification 

practice shall be incorporated into the LNG facility's emergency plan. Examples 

of reportable LNG-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. free flow of LNG that results in pooling; 

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 gas or LNG; 

g. any crack or other material defect that impairs the structural integrity or 

reliability of an LNG facility that contains, controls, or processes gas or 

LNG; 

h. any malfunction or operating error that causes the pressure of a pipeline or 

LNG facility that contains or processes gas or LNG 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 an LNG facility that contains or processes gas or LNG 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 condition that could lead to a hazard and cause a 20 percent reduction 

in operating pressure or shutdown of operation of a pipeline or an LNG 

facility; 

l. safety-related incidents with LNG and NGL trucks 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, the 

Commission staff would determine the need for an on-site inspection by 

Commission staff, and the timing of an initial incident report (normally within 

10 days) and follow-up reports. (Section 4.12.2)
i Table of Contents

TABLE OF CONTENTS 

Floridian Natural Gas Storage Project 

Final Environmental Impact Statement 

EXECUTIVE SUMMARY ES-1 

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

PUBLIC OUTREACH AND COMMENTS ...............................................ES-2 

ALTERNATIVES CONSIDERED .............................................................ES-3 

PROJECT IMPACTS AND MITIGATION................................................ES-4 

MAJOR CONCLUSION .............................................................................ES-6 

1.0 INTRODUCTION 1-1 

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

1.2 PURPOSE AND SCOPE OF THIS EIS............................................ 1-3 

1.3 PERMITS, APPROVALS, AND REGULATORY 

REQUIREMENTS............................................................................. 1-4 

1.4 PUBLIC OUTREACH AND COMMENTS ..................................... 1-6 

2.0 DESCRIPTION OF THE PROPOSED ACTION 2-1 

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

2.1.1 LNG Storage Facility Description .........................................2-1 

2.1.2 Pipelines and Aboveground Facilities ................................... 2-9 

2.2 NONJURISDICTIONAL FACILITIES .......................................... 2-10 

2.3 LAND REQUIREMENTS............................................................... 2-10 

2.3.1 LNG Storage Facility...........................................................2-10 

2.3.2 Pipelines and Aboveground Facilities ................................. 2-11 

2.4 CONSTRUCTION PROCEDURES................................................ 2-16 

2.4.1 LNG Storage Facility Construction Procedures ..................2-16 

2.4.2 Pipeline and Aboveground Facilities................................... 2-21 

2.5 CONSTRUCTION SCHEDULE..................................................... 2-25 

2.6 ENVIRONMENTAL COMPLIANCE AND MONITORING ....... 2-26 

2.7 OPERATION AND MAINTENANCE........................................... 2-26 

2.7.1 LNG Storage Facility...........................................................2-26 

2.7.2 Pipelines and Associated Aboveground Facilities............... 2-27 

2.8 SAFETY CONTROLS .................................................................... 2-27 

2.8.1 LNG Storage Facility...........................................................2-27 

2.8.2 Pipelines and Associated Aboveground Facilities............... 2-31 

2.9 FUTURE PLANS AND ABANDONMENT .................................. 2-32 
Table of Contents ii 

TABLE OF CONTENTS (cont.) 

3.0 ALTERNATIVES 3-1 

3.1 NO ACTION OR POSTPONED ACTION ALTERNATIVES........ 3-1 

3.2 ALTERNATIVE ENERGY SOURCES............................................ 3-1 

3.2.1 Other Non-Renewable Fuels..................................................3-2 

3.2.2 Renewable Energy Sources....................................................3-3 

3.2.1 Energy Conservation..............................................................3-4 

3.2.2 Renewable Energy Combined with Energy Conservation.....3-4 

3.2.1 Conclusions Regarding Alternative Energy Sources.............3-5 

3.3 STORAGE FACILITY ALTERNATIVES....................................... 3-5 

3.3.1 System Alternatives ...............................................................3-5 

3.3.2 LNG Storage Facility Site Alternatives ................................. 3-8 

3.4 PIPELINE AND ABOVEGROUND FACILITY 

ALTERNATIVES............................................................................ 3-12 

3.4.1 Pipeline Route Alternatives .................................................3-12 

3.4.2 Aboveground Facility Alternatives...................................... 3-15 

3.4.3 Hydrotest Water Pipeline Alternatives ................................3-15 

4.0 ENVIRONMENTAL ANALYSIS 4-1 

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

4.1.1 Geological Setting..................................................................4-1 

4.1.2 Seismic Design Requirements ...............................................4-1 

4.1.3 FERC Seismic Design Guidelines for LNG Facilities...........4-2 

4.1.4 Geological Hazards, Site-Specific Geotechnical Investigation 

and Seismic Hazard Analysis.................................................4-3 

4.1.5 Extractive Resources..............................................................4-7 

4.1.6 Paleontological Resources ..................................................... 4-7 

4.2 SOILS ................................................................................................ 4-8 

4.2.1 Soil Composition and Limitations .........................................4-8 

4.2.2 Contaminated Soils ..............................................................4-11 

4.2.3 Mitigation.............................................................................4-11 

4.3 WATER RESOURCES ................................................................... 4-12 

4.3.1 Groundwater ........................................................................4-12 

4.3.2 Surface Water Resources ..................................................... 4-14 

4.4 VEGETATION................................................................................ 4-17 

4.4.1 Wetlands ..............................................................................4-17 

4.4.2 Upland Vegetation ...............................................................4-22 

4.5 WILDLIFE AND AQUATIC SPECIES ......................................... 4-26 

4.5.1 Wildlife ................................................................................4-26 

4.5.2 Aquatic Resources ...............................................................4-30 
iii Table of Contents

TABLE OF CONTENTS (cont.) 

4.6 THREATENED, ENDANGERED, AND SPECIAL STATUS 

SPECIES.......................................................................................... 4-31 

4.6.1 Federally Listed Threatened and Endangered Species ........4-31 

4.6.2 State-listed Species ..............................................................4-36 

4.7 LAND USE, RECREATION, AND VISUAL RESOURCES ........ 4-38 

4.7.1 Land Use .............................................................................. 4-38 

4.7.2 Residences and Structures....................................................4-43 

4.7.3 Recreation and Special Interest Areas ................................. 4-43 

4.7.4 Coastal Zone Management ..................................................4-43 

4.7.5 Hazardous Waste Sites.........................................................4-43 

4.7.6 Visual Resources..................................................................4-44 

4.8 SOCIOECONOMICS...................................................................... 4-47 

4.8.1 Population ............................................................................4-47 

4.8.2 Economy and Employment..................................................4-49 

4.8.3 Housing and Property Values ..............................................4-50 

4.8.4 Government Revenues from the Project..............................4-50 

4.8.5 Public Services..................................................................... 4-51 

4.8.6 Environmental Justice..........................................................4-51 

4.9 TRANSPORTATION...................................................................... 4-54 

4.10 CULTURAL RESOURCES ............................................................ 4-56 

4.10.1 Results of Cultural Resources Surveys................................4-57 

4.10.2 Native American Consultation............................................. 4-57 

4.10.3 Compliance with NHPA ......................................................4-57 

4.11 AIR QUALITY AND NOISE ......................................................... 4-58 

4.11.1 Air Quality ...........................................................................4-58 

4.11.2 Noise Quality ....................................................................... 4-66 

4.12 RELIABILITY AND SAFETY....................................................... 4-71 

4.12.1 LNG Hazards ....................................................................... 4-72 

4.12.2 Front-End Engineering Design Review...............................4-74 

4.12.3 Siting Requirements – Thermal and Dispersion Exclusion 

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

4.12.4 LNG and NGL Truck Operations ........................................ 4-97 

4.12.5 Emergency Response and Evacuation Planning..................4-98 

4.12.6 Terrorism and Security Issues..............................................4-99 

4.12.7 Natural Gas Pipelines.........................................................4-101 

4.13 CUMULATIVE IMPACTS........................................................... 4-103 

4.13.1 Potentially Cumulatively-Affected Resources...................4-104 

4.13.2 Geographic Scope and Temporal Scale .............................4-104 

4.13.3 Other Actions Potentially Contributing to Cumulative 

Impacts...............................................................................4-104 

4.13.4 Resource-Specific Cumulative Impacts Analysis..............4-106 

4.13.5 Conclusions about Cumulative Impacts.............................4-111 
Table of Contents iv 

TABLE OF CONTENTS (cont.) 

5.0 CONCLUSIONS AND RECOMMENDATIONS 5-1 

5.1 SUMMARY OF THE STAFF’S ENVIRONMENTAL 

ANALYSIS........................................................................................ 5-1 

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

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

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

5.1.4 Wetlands ................................................................................5-2 

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

5.1.6 Wildlife and Aquatic Resources ............................................5-3 

5.1.7 Threatened, Endangered, and Special Status Species............5-4 

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

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

5.1.10 Transportation........................................................................ 5-6 

5.1.11 Cultural Resources.................................................................5-6 

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

5.1.13 Reliability and Safety............................................................. 5-7 

5.1.14 Alternatives............................................................................ 5-8 

5.2 FERC STAFF’S RECOMMENDED MITIGATION........................ 5-9 
v List of Appendices

LIST OF APPENDICES 

APPENDIX A Final Environmental Impact Statement Environmental Mailing List 

APPENDIX B References 

APPENDIX C List of Preparers 

APPENDIX D Comments on the Draft Environmental Impact Statement and 

Responses 
List of Tables vi 

LIST OF TABLES 

Table Title Page No. 

1.3-1 Permits and Approvals......................................................................................... 1-4 

2.3-1 Locations and Land Requirements for the Proposed Pipeline Facilities ........... 2-12 

2.8-1 Federal Siting and Design Requirements for LNG Facilities ............................ 2-28 

3.3-1 Comparison of Alternative LNG Storage Facility Sites ...................................... 3-9 

3.4-1 Comparison of Pipeline Route Alternatives ...................................................... 3-13 

4.2-1 Soils at the FGS Project ....................................................................................... 4-9 

4.4-1 Existing Project Vegetative Cover..................................................................... 4-17 

4.4-2 Temporary Wetland Impacts from Pipeline Construction ................................ 4-21 

4.4-3 Upland Vegetative Cover Types Occurring in the Project Area........................ 4-23 

4.4-4 Vegetation Communities Potentially Affected by the Project........................... 4-24 

4.6-1 Federally-Listed Species Potentially Occurring in the Project Area ................. 4-32 

4.6-2 State-Listed Species Potentially Occurring in the Project Area ........................ 4-36 

4.7-1 Planned Development in the Project Area......................................................... 4-39 

4.7-2 Land Cover Potentially Affected by LNG Storage Facility Development........ 4-41 

4.7-3 Land Cover Potentially Affected by Pipeline and Aboveground Facilities....... 4-42 

4.8-1 Existing Population in the Project Area of Influence ........................................ 4-47 

4.8-2 Income and Unemployment Data for Area of Influence ................................... 4-49 

4.8-3 Rental Units in Martin County........................................................................... 4-50 

4.8-4 Existing Medical, Police, Education, and Fire Full-Time Equivalents in the 

Area of Influence ............................................................................................... 4-51 

4.8-5 Racial/Ethnic Characteristics of the Area Surrounding the FGS Storage 

Project ................................................................................................................ 4-52 

4.11-1 National and State Ambient Air Quality Standards........................................... 4-59 

4.11-2 Summary of Air Emissions from Project Construction ..................................... 4-61 

4.11-3 Summary of Air Emissions from Project Operations ....................................... 4-62 

4.11-4 Summary of Greenhouse Gas Emissions from Project Construction ................ 4-65 

4.11-5 Summary of Greenhouse Gas Emissions from Project Operations ................... 4-66 

4.11-6 Existing Sound Levels and Noise Limits........................................................... 4-68 

4.11-7 Predicted Construction Noise Impacts for the FGS Project............................... 4-69 

4.11-8 Project Operating Noise Impacts for the FGS Project....................................... 4-70 

4.12-1 Impoundment Areas........................................................................................... 4-87 

4.12-2 Thermal Radiation Exclusion Zones.................................................................. 4-91 

4.13-1 Summary of Potential Cumulative Effects of the Proposed Project................ 4-105 

4.13-2 Potential Future Actions in the FGS Project Area........................................... 4-106 

4.13-3 Cumulative Existing Criteria Air Pollutant Emissions in the Vicinity of the 

Proposed Project .............................................................................................. 4-110 
vii List of Figures

LIST OF FIGURES 

Figure Title Page No. 

1.0-1 General Location Map ......................................................................................... 1-2 

2.1-1 Project Facility Location Map ............................................................................. 2-2 

2.1-2 Project Location Map........................................................................................... 2-3 

2.1-3 LNG Storage Facility Plot Plan ........................................................................... 2-5 

2.1-4 Typical Full Containment Storage Tank.............................................................. 2-6 

2.3-1 Proposed Pipeline Right-of-Way Section .......................................................... 2-14 

2.3-2 Proposed Wetland Crossing Pipeline Right-of-Way Section ............................ 2-15 

2.4-1 Hydrotest Pipeline Route Location Map............................................................ 2-19 

3.3-1 Alternative LNG Storage Facility Sites Location Map...................................... 3-10 

3.4-1 Alternative Pipeline Routes ............................................................................... 3-14 

4.4-1 Location of Project Wetlands............................................................................. 4-19 

4.7-1 Planned Future Project Area Land Use Map ..................................................... 4-40 

4.7-2 LNG Storage Facility Visual Simulation........................................................... 4-46 

4.8-1 US Census Track Boundaries ............................................................................ 4-48 

4.12-1 Thermal Radiation Exclusion Zones.................................................................. 4-90 

4.12-2 Vapor Dispersion Exclusion Zones ................................................................... 4-93 

4.13-1 Current and Potential Future Actions in the Project Area ............................... 4-107 
Acronyms and Abbreviations viii 

ACRONYMS AND ABBREVIATIONS 

°F Degrees Fahrenheit 

μg/m3 Micrograms per cubic meters 

ACHP Advisory Council on Historic Preservation 

APE Area of Potential Effect 

AQCR Air Quality Control Region 

ASME American Society of Mechanical Engineers 

BACT Best Available Control Technology 

Bcf Billion cubic feet 

BOG Boil-off gas 

Btu British thermal units 

Btu/ft2

-hr British thermal units per square foot per hour 

CAA Clean Air Act 

CCD Census County Division 

CDP Census Designated Place 

CEQ Council on Environmental Quality 

Certificate Certificate of Public Convenience and Necessity 

CFA Core foraging area 

CFR Code of Federal Regulations 

CO Carbon monoxide 

CO2 carbon dioxide 

CO2-e carbon dioxide equivalents 

COE U.S. Army Corps of Engineers 

Commission Federal Energy Regulatory Commission 

CZMA Coastal Zone Management Act 

dBA Decibels on the A-weighted scale 

DCS Distributed Control System 

DE Design Earthquake 

DEGADIS Dense gas dispersion model

DSM Demand-Side Management 

DOT U.S. Department of Transportation 

DOT-OPS U.S. Department of Transportation Office of Pipeline Safety 

E Endangered species 

EI Environmental Inspector 

EIS Environmental Impact Statement 

EPA U.S. Environmental Protection Agency 

ERP Environmental Review Permit 

ESA Endangered Species Act of 1973 

ESD Emergency Shutdown 

FCMP Florida Coastal Management Program 

FDEP Florida Department of Environmental Protection 

FDOT Florida Department of Transportation 

FDS Fire Dynamics Simulation 

FEED Front-end Engineering Design 

FERC Federal Energy Regulatory Commission 

FFWCC Florida Fish and Wildlife Conservation Commission 
ix Acronyms and Abbreviations

FGS Floridian Natural Gas Storage Company, LLC 

FGT Florida Gas Transmission 

FLUCFCS Florida Land Use, Cover, and Farms Classification System 

FPL Florida Power & Light Company 

fps feet per second 

FWS U.S. Fish and Wildlife Service 

GHG Greenhouse gas 

gpm gallons per minute 

HAPs Hazardous air pollutants 

HCA High Consequence Area 

hp horsepower 

LAeq Average equivalent sound level (hourly) 

Ld Day sound level 

Ldn Day-night sound level 

Leq(24) 24-hour equivalent sound level 

Ln Night sound level 

LNG Liquefied natural gas 

M&R Metering and regulation 

m3 Cubic meters 

MCE Maximum Considered Earthquake 

MMBtu/hr Million British thermal units per hour 

MMscfd Million standard cubic feet per day 

MP Milepost 

mph miles per hour 

MR mixed refrigerant 

MW Megawatt 

n/a Not applicable 

NAAQS National Ambient Air Quality Standards 

NEPA National Environmental Policy Act of 1969 

NESHAPs National Emission Standards for Hazardous Air Pollutants 

NFPA National Fire Protection Association 

NGL Natural gas liquids 

NGVD National Geodetic Vertical Datum 

NHPA National Historic Places Act of 1966 

NO2 Nitrogen dioxide 

NOI Notice of Intent 

NOx Nitrogen oxide 

NPDES National Pollutant Discharge Elimination System 

NRCS Natural Resources Conservation Service 

NSA Noise Sensitive Area 

NSPS New Source Performance Standards 

O3 Ozone 

OBE Operating Basis Earthquake 

OEP Office of Energy Projects 

PAMP Preserve Area Management Plan 

PCBs Polychlorinated biphenyls 
Acronyms and Abbreviations x 

PHMSA Pipeline and Hazardous Materials Safety Administration 

Plan Upland Erosion Control, Revegetation, and Maintenance Plan 

PM Particulate matter 

PM10 Particulate matter less than 10 microns in diameter 

PM2.5 Particulate matter less than 2.5 microns in diameter 

ppm Parts per million 

Procedures Wetland and Waterbody Construction and Mitigation Procedures 

PSC Public Service Commission 

PSD Prevention of Significant Deterioration 

psig Pounds per square inch gauge 

PVC Polyvinyl Chloride 

ROW Right-of-way 

RPT Rapid phase transition 

S/A Similarity of Appearance 

SC Species of Concern 

SFWMD South Florida Water Management District 

SHPO State Historic Preservation Office or Officer 

SIS Safe Instrument System 

SO2 Sulfur dioxide 

SPCC Spill Prevention, Control and Countermeasure 

SR State Route 

SSE Safe Shutdown Earthquake 

SVA Security Vulnerability Assessment 

SWPP Stormwater Pollution Prevention 

THPO Tribal Historic Preservation Officer 

TNT trinitrotoluene 

tpy Tons per year 

USC United States Code 

USCG U.S. Coast Guard 

USGS U.S. Geological Survey 

VOCs Volatile organic compounds 

WEG Water ethylene glycol 
Appendix A 

Final Environmental Impact Statement 

Environmental Mailing List 
APPENDIX A 

Environmental Mailing List 

A-1 

Federal Government Agencies

Advisory Council on Historic Preservation 

Assistant Director for Federal Program Development 

 Charlene Vaughn 

Office of Federal Agency Programs Director 

 Don Klima 

American Gas Association 

Dave Parker, President 

Chief Energy and Environment Library of Congress 

Exchange & Gift Division 

Federal Documents Section 

Council on Environmental Quality 

General Counsel 

 Dina Bear 

Deputy General Counsel 

 Edward Boling 

Associate Director for NEPA Oversight 

 Horst Greczmiel 

Department of Agriculture 

Office of Finance & Management 

 Natural Resources Conservation Service 

National Environmental Coordinator 

Andrea DuVarney 

 State Conservationist 

 Niles T. Glasgow 

U.S. Forest Service 

 Deputy Chief, National Forest System 

 Ecosystem Management Coordination 

Joe Carbone 

Director of Lands 

Department of Commerce 

 Office of the Secretary 

Senior Policy Advisor 

 Sloan Rappoport 

 National Oceanic and Atmospheric Administration 

Director of Ecology & Conservation 

 NEPA Policy & Compliance 

Steve Kokkinakis 

 National Marine Fisheries Service 

 NEPA Coordinator 

John Hansel 

 Office of Habitat Protection 

Karen Abrams 

 Northeast Field Office 

 Anne Richards 

Department of Defense 

Office of the Under Secretary of Defense 

Office of the Deputy Undersecretary, Installations and Environment 

 Patricia Ferrebee – Director, Environmental Security 

Assistant Chief of Staff for Installation Management 

 U.S. Army 

 Deputy Assistant Secretary for Environment, Safety, and Occupation Health 

 George Carellas - Assistant for Stewardship & Sustainability 

 Office of the Assistant Sectretary of the Army (Civil Works) 

 Assistant for Enviornment Tribal and Regulatory Affairs 

U.S. Army Corps of Engineers 

Office of Environmental Policy 

John Furry 

 Office of the Chief of Army Engineers 

 Headquarters 

Chief, Regulatory Branch 
APPENDIX A 

Environmental Mailing List 

A-2 

 Southeast Region 

 Penny Cutt 

 Jacksonville District 

 Richard Bonner 

Stephen C. Duba 

 Eric Reusch 

 U.S. Air Force 

Real Property Agency 

Vincent Leduc 

Office of Environment & Safety 

 Basing and Units 

 Jack Bush, NEPA Program Manager 

 U.S. Navy 

Office of the Assistant Secretary of the Navy (Installations and Environment) 

Robert Uhrich 

Office of the Assistant of the Secretary for Environment and Safety 

Thomas England, NEPA Liaison 

Office of Chief of Naval Operations 

Karen Foskey, Environmental Planning/NEPA Lead 

Department of Energy 

Office of NEPA Policy & Compliance 

Carol Borgstrom, Director 

 Office of Fossil Energy 

 Harvey Harmon 

Office of Environmental Compliance 

Natural Gas Regulatory Activities 

Robert Corbin, Manager 

Department of Health & Human Services 

 Office of Facilities Management & Policy 

Camille Beben, Director 

 Centers for Disease Control & Prevention 

George Chandler 

Department of Homeland Security 

David Reese, Environmental Protection Specialist 

 U.S. Coast Guard 

 Admiral Thomas Collins, Commandant 

Environmental Management Division 

 Ed Wandelt, Chief 

Office Operation & Environmental Standards 

Captain David Scott 

 Office of the Judge Advocate General 

Frank Esposito 

Department of Housing & Urban Development 

 Office of Environment and Energy 

Richard Broun, Director 

Department of the Interior 

Office of Environmental Policy & Compliance 

 Director 

 Andrew Raddant 

U.S. Fish and Wildlife Service 

NEPA Coordinator 

 Pat Carter 

Southeast Regional Office 

 Sam D. Hamilton, Director 

South Florida Ecological Services Office 

Paul Souza 

John Wrublik 

Land & Minerals Management 

Deputy Assitant 

 Patricia Morrison 

Bureau of Indian Affairs 

Donald Sutherland, NEPA Coordinator 
APPENDIX A 

Environmental Mailing List 

A-3 

Bureau of Land Management 

Planning and Assessment 

Deborah Rawhouser, Group Manager 

National Park Service 

Environmental Quality Division 

Jacob Hoogland, Chief 

Minerals Management Service 

Walter Cruickshank, Deputy Director 

Environmental Assessment Branch 

James Bennett, Chief 

U.S. Geological Survey 

Environmental Affairs 

Lloyd Woosley, Chief 

 Florida Integrated Science Center 

 Barry Rosen, Director 

Deptartment of Justice 

Environment & Natural Resources 

Ann Navaro 

Land & Natural Resources Division 

Department of Labor 

Office of Regulatory Economics 

Employment & Training 

Mike O’Malley 

Department of State 

Office of Environment/Health 

Deptartment of Transportation 

Environment & Policy 

 Director 

Environmental Policies Team Leader 

Camille Mitteholz 

 Research & Special Programs Admin. 

Samuel Bonasso, Deputy Administrator 

 James O’Steen, Administrator for Pipeline Safety 

Stacy Gerard, Associate Administrator 

Office of Pipeline Safety 

Tom Fortner 

Alex Dankanich 

Mike Khayata 

John Jacobi 

Kimbra Davis 

Karen Butler 

Southern Region 

Linda Daughterty, Director 

 Federal Highway Administration 

 Florida Division Office 

 David C. Gibbs, Administrator 

 Nahir Detizio 

Environmental Protection Agency 

Office of Federal Activities 

Anne Norton Miller, Director 

Cliff Rader, NEPA Compliance Division 

 Region 4 

 J.I. Palmer, Administrator 

 Ted Walden 

 William Denman 

Federal Aviation Administration 

Office of Environment & Energy 

Matthew McMillen 

Federal Communications Commission 

Aliza Katz 
APPENDIX A 

Environmental Mailing List 

A-4 

Federal Highway Administration 

Office of NEPA Facilitation 

Fred Skaer, Director 

Federal Maritime Commission 

Karen Gregory, Assistant Secretary 

Federal Trade Commission 

Assistant General Counsel 

John Daly 

General Services Administration 

Environmental Program Manager 

Lee Salviski 

Interstate Commerce Commission 

Marine Mammal Commission 

General Counsel 

Michael Gosliner 

National Science Foundation 

Assistant General Counsel 

Charisse Carney-Nunes 

Nuclear Regulatory Commission 

Intergovernment Programs 

Osiris Siurano 

Pipeline Contractor Association 

J. Patrick Tielborg 

Rocky Mt. P/L Construction Association 

J.D. Lormand, Executive Director 

Securities and Exchange Commission 

Office of Public Utility Regulation 

David LaRoche 

Small Business Administration 

Assistant General Counsel 

Gary Fox 

The Wilderness Society 

Pete Morton, Ph.D., Resource Economist 

U.S. Senate 

Committee on Energy & Natural Gas 

Federal Senators and Representatives 

Senator Bill Nelson 

Senator Mel Martinez 

Congressman Tim Mahoney 

Congressman Alcee Hastings 

State Senators and Representatives 

Senator Ken Pruitt, District 28 

Representative Gayle Harrell, District 81 

Representative Richard Machek, District 78 

Representative William Snyder, District 82 

State Government Agencies

Advisory Council on Historic Preservation 

Deputy Secretary of State for Cultural and Historic Programs 

JuDee Pettijohn 

Attorney General of Florida 

Bill McCollum 

Department of Agriculture and Consumer Services 

Charles Bronson, Commissioner 

Office of Federal-State Relations 

Leslie Palmer 

Florida Coastal Management Program 

Director 
APPENDIX A 

Environmental Mailing List 

A-5 

Florida Department of Environmental Protection 

Hugo Carter 

Lee Hoefert 

Manuel Delosantos 

Georgia Vince 

Administrator 

Rufus Noble 

Southeast District 

Timothy Rach, Acting Director 

Tim Gray, Environmental Manager 

Permitting Manager 

Jennifer Smith 

Potable Water Permitting Director 

Jose Calas 

Stormwater Permitting Director 

 Indar Jagnarine 

Waste Water Permitting Director 

Tim Powell 

Division of Air Resource Management 

 Director 

Division of Coastal Aquatic Management 

 Director 

Division of Water Resources Management 

Director 

Division of Parks and Recreation 

 Director 

Division of State Lands 

 Director 

Office of Intergovernmental Programs 

 Sally B. Mann, Director 

Florida Department of State 

State Historic Preservation Office 

Division of Historical Resources 

 Frederick P. Gaske, Director 

Florida Department of Transportation 

District 4 Secretary 

Office of Modal Development 

 Christopher Hammel 

Florida Fish and Wildlife Conservation 

Joe Walsh 

Florida Fish and Wildlife Conservation Commission 

Director 

Regional Director 

Chuck Collins 

Florida Game and Freshwater Fish Commission 

Director 

 Regional Office 

Florida Geological Survey 

State Geologist and Chief 

Walt Schmidt 

Florida Public Service Commission 

Mary Adams Bane, Executive Director 

Florida Soil and Water Conservation Council 

 Chuck Aller 

Florida State Clearinghouse 

 Lauren Milligan 

Office of the Governer 

Governer Charlie Crist 

Siting Coordination Office 

Director 

South Florida Water Management District 

Tom Colios 
APPENDIX A 

Environmental Mailing List 

A-6 

Local Government Agencies

Martin County 

Commission Chair 

Michael DiTerlizzi 

Sarah Heard 

Doug Smith 

Susan Valliere 

Lee Weberman 

Duncan Ballantyne 

Community Services Director 

 Cheryl Bass 

County Attorney 

Stephen Fry 

County Planner 

 Eric Brent 

Emergency Management Division 

 Keith Holman, Director 

Engineering Deptartment 

Fire Prevention Chief 

Jon Pasqualone 

Property Appraiser 

Laurel Kelly 

Sheriff's Office 

Robert Crowder, Sheriff 

Captain Lloyd Jones 

Environmental Investigations 

Detective Joseph Passanesi 

Town of Sewall’s Point 

 Robert Kellogg, Town Manager 

Libraries

Blake Library 

Cummings Library 

Hobe Sound Public Library 

Hoke Library 

Indiantown Branch Library 

Robert Morgade Library 

Media

Big Lake Media 

Hometown News 

Indiantown News 

Palm Beach Post 

Stuart News 

Native American Tribes

Miccosukee Tribe of Indians of Flordia 

Billy Cypress, Chairman 

Seminole Indian Tribe 

Mitchell Cypress, Vice-Chairman 

Intervenors

Calypso LNG, LLC 

 Ray Cunningham, SUEZ Energy North America, Inc. 

Lawrence G. Acker, Dewey & LeBoeuf L.L.P. 

Florida Cities 

 Karen Alford, Gainesville Regional Utility 

 Richard Snyder, City of Lakeland 

 Jim Myers, JEA 

 Douglas F. John, John & Hengerer 

 Katherine Vaughan, Florida Gas Utility 

 Roger McDonald, City of Tallahassee 

 Claston Sunanon, Orlando Utilities Commission 
APPENDIX A 

Environmental Mailing List 

A-7 

Florida Gas Transmission Company, L.L.C. 

 Michael T. Langston 

 Frazier King 

Peoples Gas System 

 Wraye Grimard, Peoples Gas System 

 Paula Brown, Tampa Electric Company 

 Charles H. Shoneman, Bracewell & Giuliani, L.L.P. 

SG Resources Mississippi, L.L.C. 

 Mark D. Cook 

 James F. Bowe, Dewey & LeBoeuf, L.L.P. 

Tampa Farm Service, Inc 

Blair Bynum, Tampa Farm Service 

 Michael Grzelka, Schaefer, Fogan, & Associates, Inc. 

Organizations and Individuals

A-1 Financial Services Inc. 

Alice Gaskins 

Anne Lackey 

Audubon of Martin County 

Bay State Milling 

Big Heart Brigade 

Booker Park Citizens Association 

Business Development Board of Martin County 

Charles Sisco 

CSX Transportation 

Florida Atlantic University - CUES 

Florida Power & Light Company 

R. Wade Litchfield 

Sarah E. Tomalty 

Heather Stubblefield 

Guy Parker 

Harris Wall Estate & Bob Post, Jr. 

ILICO B, Inc. 

Indiantown Chamber of Commerce 

Indiantown Cogeneration L.P. 

Indiantown Company 

Indiantown Gas Company 

Indiantown Holdings L.L.C. 

Indianwood Homeowners Association 

Iris Wall & Bob Post, Jr. Trustee 

James Crosby 

James & Pearl Slay 

Jane Williams 

Kaltech, Inc. 

Lana Tran 

Louis Dreyfus Citrus, Inc. 

McNicholas & Associates 

Palm Beach County Environmental Coalition 

Palm City Chamber of Commerce 

Porto Properties 

Prism Investors L.L.C 

Resic Indiantown Invest L.L.C. 

Robert & Wilda Wright 

Shawn Keil 

Tesoro Groves Ltd Partnership 

Timothy & Phyllis Roberts 

UBS 

Viretta Priest 

Workforce Development Board 
Appendix B 

References 
B-1 

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resources, technologies, and policies for states and communities. U.S. 

Department of Energy: Energy Efficiency and Renewable Energy. Available at 

http://www.eere.energy.gov/states/alternatives/resources_fl.cfm. 

USDA, Soil Conservation Service. 1981. Soil Survey of Martin County Area, Florida. 

USGS. 2000. Land Subsidence in the United States. USGS Fact Sheet-165-00. 

December 2000. http://water.usgs.gov/ogw/pubs/fs00165/ 

USGS. 2006. USGS Education Map Catalog: Earthquakes, Volcanoes, and Landslides. 

Landslide Overview Map of the Conterminous United States. 

http://education.usgs.gov/common/resources/mapcatalog/earthquakes.html. Page 

modified 25 July 2006.

UTC, 2008. Utility Report Cards. Available at http://utilityreportcards.com/. 

White, W.A. 1970. The Geomorphology of the Florida Peninsula. Florida Geological 

Survey Bulletin No. 51. Tallahassee, Florida. 
Appendix C 

List of Preparers 
C-1

LIST OF PREPARERS 

FEDERAL ENERGY REGULATORY COMMISSION

Brown, Charles – Senior Program Analyst, Project Manager, Proposed Action, 

Socioeconomics, Alternatives, Land Use 

 B.A., Business Administration, 1972 

 

Button, Van T. - Cultural Resources and Socioeconomics 

 M.A., Anthropology, 1976, University of Arizona 

 B.A., Anthropology, 1973, Reed College 

DiAngelo, Liliana M. - Reliability and Safety 

 B.S., Chemical Engineering, 2003, University of Maryland 

Harris, Kara - Soils 

 M.P.A., Environmental Science and Policy, 2006, Columbia University 

 B.S., Environmental Biology, 2003, Alabama A&E University 

Jones, Shannon - Biological Resources

 B.S., Natural Resources Management, 1998, University of Maryland 

Wacholder, Joanne - Wildlife, Vegetation, Wetlands, Water Resources and Aquatic 

Resources

 M.S., Crop and Soil Sciences/Environmental Toxicology, 1997, Michigan State 

University 

 B.S., Environmental Biology, 1994, University of Wisconsin – Stevens Point 

Warn, Kenneth - Air Quality and Noise 

 M.P.P., Environmental Policy Concentration, 2005, the George Washington 

University 

M.S., Chemical Engineering, 1995, Lehigh University 

 B.S., Chemical Engineering, 1992, Colorado School of Mines 

White, Sentho - Reliability and Safety 

 M.S., Environmental Engineering, 2001, John Hopkins University 

 B.S., Civil Engineering, 2000, Georgia Institute of Technology 

ENVIRONMENTAL RESOURCES MANAGEMENT 

Afon, Adeyinka – Air and Noise 

M.S.E, Environmental Process Engineering, 2004, Johns Hopkins University 

 B.S., Chemical Engineering, 2002, Ladoke Akintola University of Technology, 

Nigeria 
C-2

Ashline, Lindley – Technical Editor 

 B.A., English, 2005, Appalachian State University 

Bednarski, Melinda – Water Resources, Aquatic Resources 

M.S., Aquatic Ecology, 2001, University of Bremen, Germany 

 B.S., Biology, 1999, Central Michigan University 

Blaha, David AICP – Project Manager 

 Master of Environmental Management, 1981, Duke University 

 B.A., 1978, Gettysburg College 

Drobinski, John – Geology, Soils 

M.Sc., Geology, 1979, University of Queensland, Australia 

 B.A., Chemistry, 1969, Nasson College 

Gabucan, Janice – Socioeconomics 

Masters in International Affairs, 2004, Columbia University 

 B.A., Government, 1998, Wesleyan University 

London, Phil – Wildlife, Vegetation, Wetlands 

M.S., Environmental Management and Energy Policy, ongoing, University of 

Maryland University College 

B.S., Soil and Water Science, 1992, University of Rhode Island 

Maute, Michael – Graphics 

M.S., Mapping Sciences, ongoing, State University of New York, College of 

Environmental Science and Forestry 

B.S., Geology and Geochemistry, 1998, State University of New York at Oswego 

Sadlon, William – Wildlife, Vegetation, Wetlands 

 M.S., Environmental Science & Policy, ongoing, Johns Hopkins University 

 B.A., Environmental Biology, 2003, Colgate University 
Appendix D 

Comments on the Draft Environmental 

Impact Statement and Responses 



























































1.0 – Introduction 1-2 

Figure 1.0-1 

FGS Project 

General Location Map 
S R- 7 1 0

C S X R ailr o a d

St or a g e 

F a cilit y Sit e

Pr oj e ct 

Pi p eli n e

Pr o p o s e d 

M & R St ati o n

F P L 

I nt er c o n n e cti o n

G ulf str e a m

I nt er c o n n e cti o n

0. 0 0

0. 5 0

1. 0 0

1. 5 0

2. 0 0

2. 5 0

3. 5 0 3. 0 0

3. 9 5

4. 0 5

0. 2 5 0. 5 Mil e s

Fi g ur e 2. 1- 1

F G S Pr oj e ct

Pr oj e ct F a cilit y L o c ati o n M a p

L e g e n d

R o a d s

Mil e p o st

R ailr o a d

Pr oj e ct Pi p eli n e

St or a g e F a cilit y Sit e

M & R St ati o n

C o n str u cti o n St a gi n g Ar e a
FPL Martin 

Cooling Pond

FPL Martin 

Power Plant

Cogentrix Power Plant

and Cooling Pond

Indiantown

SR-710

Fox Brown Road

Allapattah Road

SR-76 Kanner Hwy

CSX Railroad

Indiantown Commerce 

and Technology Park

Proposed Secondary 

Access Road

St. Lucie Canal

Louis Dreyfus

Facility

Figure 2.1-2

FGS Project

Project Location Map

0 1 2 0.5

Miles

2-3

Legend Roads

Railroad

M&R Station

Proposed Access Road

Indiantown Commerce and Technology Park

Noise Sensitive Area 1 Project Area (2 mile radius 

from Project)

Hydrotest Water Pipeline

Project Pipeline

St orage Facility Site

Temporary Pump Houses

Construction Staging Are a
Land Vault

Existing FPL 

Substation

SR 710

CSX Railroad

Spray Irrigation 

Field

0.1 0.05 0 0.1

Miles

Legend

Storage Facility Site

Stormwater Management Pond

Figure 2.1-3

FGS Project

Storage Facility Plot Plan

2-5
2-6

Figure 2.1-4 

FGS Project 

Typical Full Containment Storage Tank 

Suspended roof 

(insulated) 

Pre-stressed concrete 

outer tank wall 

Carbon steel liner 

Bottom heater 

Base Insulation 

Inner tank 

Reinforced concrete 

roof 

Perlite 

insulation 
2-14

Figure 2.3-1 

FGS Project 

Proposed Pipeline Right-of-Way Section 

24’ – 29’ 52’ – 57’
2-15

Figure 2.3-2 

FGS Project 

Proposed Wetland Crossing Pipeline Right-of-Way Section 

15 
St. Lucie Canal

Storage Facility 

Site

Hydrotest Water

Pipeline

Temporary 

Pump House

Temporary 

Pump House

Temporary 

Pump House

0 0.25 0.5 1

Miles

Figure 2.4-1

FGS Project

Hydrotest Pipeline Route Location Map

2-19

Legend

Hydrotest Water Pipeline

Project Pipeline

Storage Facility Site 

Temporary Pump House
3-10 3.0 –Alternatives

Figure 3.3-1 

FGS Project 

Alternative Storage Facility Sites Location Map 

Alternative Site 5 
! ! !

! !

! !

! ! !

! ! !

S R- 7 1 0 C S X R ailr o a d

St or a g e F a cilit y 

Sit e

Pr o p o s e d Pi p eli n e 

R o ut e

0. 2 5 0. 5 Mil e s

L e g e n d R o a d s

R ailr o a d

M & R St ati o n

St or a g e F a cilit y Sit e

Pr o p o s e d Pi p eli n e R o ut e

Alt er n ati v e Pi p eli n e R o ut e 1

Alt er n ati v e Pi p eli n e R o ut e 2

Alt er n ati v e Pi p eli n e R o ut e 3

Fi g ur e 3. 4- 1

F G S Pr oj e ct

Alt er n ati v e Pi p eli n e R o ut e s
S R- 7 1 0

C S X R ailr o a d

P A J P AI

P A L

P R P P

P L

P H

P D

P A

Pr o p o s e d 

M & R St ati o n

St or a g e F a cilit y

Sit e

Pr oj e ct 

Pi p eli n e

P Y

P A E

P V

P A A

0. 0 0

0. 5 0

1. 0 0

1. 5 0

2. 0 0

2. 5 0

3. 5 0 3. 0 0

3. 9 5 4. 0 5

4. 1 8

0. 2 5 0. 5 Mil e s

Fi g ur e 4. 4- 1

F G S Pr oj e ct

L o c ati o n of Pr oj e ct W etl a n d s

L e g e n d

R o a d s

Mil e p o st

R ailr o a d

Pr oj e ct W etl a n d s

St or a g e F a cilit y Sit e

Pr oj e ct Pi p eli n e

M & R St ati o n

C o n str u cti o n St a gi n g Ar e a
S R- 7 1 0

C S X R ailr o a d

Pr oj e ct 

Pi p eli n e

Pr o p o s e d 

M & R St ati o n

F P L 

I nt er c o n n e cti o n

G ulf str e a m

I nt er c o n n e cti o n

I N D U S T RI A L

A G RI C U L T U R A L

L O W

D E N SI T Y

A G RI C U L T U R A L

R A N C H E T T E

C O M M E R CI A L

G E N E R A L

A G RI C U L T U R A L

R A N C H E T T E

A G RI C U L T U R A L

St or a g e 

F a cilit y Sit e

I N D U S T RI A L

0. 0 0

0. 5 0

1. 0 0

1. 5 0

2. 0 0

2. 5 0

3. 5 0 3. 0 0

3. 9 5

4. 0 5

0. 2 5 0. 5 Mil e s

Fi g ur e 4. 7- 1

F G S Pr oj e ct

Pl a n n e d F ut ur e Pr oj e ct Ar e a L a n d U s e M a p

L e g e n d

R o a d s

Mil e p o st

R ailr o a d

Pr oj e ct Pi p eli n e

St or a g e F a cilit y Sit e

M & R St ati o n

L o w D e n sit y

I n d u stri al

C o m m er ci al G e n er al

A gri c ult ur al R a n c h ett e

A gri c ult ur al

F ut ur e L a n d U s e

C o n str u cti o n St a gi n g Ar e a
4-46

The vantage point on the figure is looking southeast from Fox Brown Road, just north of SR-710. 

Figure 4.7-2 

FGS Project 

Storage Facility Visual Simulation 

Proposed LNG 

storage tanks
4-48

Figure 4.8-1 

FGS Project 

US Census Track Boundaries 
Land Vault 

Property Line

1,600 BTU/sq.ft.-hr level

3,000 BTU/sq.ft.-hr level

10,000 BTU/sq.ft.-hr level

0 305 610 1,220

Feet

Figure 4.12-1

FGS Project

Thermal Radiation Exclusion Zones

Legend

Storage Facility Site

Thermal Radiation Exclusion Zones for LNG Tanks

4-90
Land Vault

Property Line

Sendout Spill

Sump Exclusion

Zone

Truck Station and 

Process Area Spill 

Sump Exclusion Zone

0 265 530 1,060

Feet

Figure 4.12-2

FGS Project

Vapor Dispersion Exclusion Zones

Note: Vapor dispersion exclusion zones are the distance to the 

1/2 lower flammability limit of methane.

Legend

Storage Facility Site

Vapor Dispersion Exclusion Zones

4-93
Indiantown

SR-710

Fox Brown Road

Allapattah Road

SR-76 Kanner Hwy

CSX Railroad

Indiantown Commerce 

and Technology Park

Proposed Secondary 

Access Road

St. Lucie Canal

Prism Business

Park

Quillen Development

Venture Park

FPL Martin Power Plan

and Cooling Pond

Cogentrix Power Plant

and Cooling Pond

Louis Dreyfus

Plant

0 0.25 0.5 1

Miles

Legend Roads

Railroad

Project Pipeline

M&R Station

Storage Facility Site

Potential Future Actions

4-107

Figure 4.13-1

FGS Project

Current and Potential Future Actions in the Project Area