ALTERNATIVES

SECTION 3

3-1 Alternatives

3.0 ALTERNATIVES

As required by NEPA and Commission policy, we evaluated alternatives to the proposed 

Project to determine whether any would be reasonable and have significant environmental

advantages compared to the proposed action. The range of alternatives analyzed included the 

No-Action Alternative, system alternatives for the Terminal Expansion and the Pipeline 

Expansion, alternative Terminal Expansion sites, alternative terminal configurations and designs, 

alternative Pipeline Expansion aboveground facility sites, and alternative compressor station 

design. 

As part of the No-Action Alternative, we considered the effects and actions that might 

result if the proposed Project were not constructed. We identified system alternatives to evaluate 

the ability of existing, modified, planned, or proposed LNG export terminals and pipeline 

systems to meet Cameron’s objectives. We also evaluated alternative sites for the Terminal 

Expansion and the compressor station of the Pipeline Expansion, as well as alternative designs 

for both facilities. 

The evaluation criteria for considering alternatives are:

• technical and economic feasibility and practicality;

• significant environmental advantage over the proposed Project; and

• ability to reasonably meet the Project primary objective of transporting and liquefying 

domestic natural gas into LNG for export, and delivering competitively priced LNG 

to foreign markets.

Cameron participated in our pre-filing process during the preliminary design stage for the 

Project (see section 1.3). This process emphasized identification of potential stakeholder issues, 

as well as identification and evaluation of alternatives that could avoid or minimize impacts. We 

analyzed each alternative based on public comments and guidance received from federal, state, 

and local regulatory agencies. Additional input used during the analysis of alternatives included 

information provided by Cameron’s field surveys, aerial photographs, U.S. Geological Survey 

(USGS) topographic maps, National Wetland Inventory (NWI) maps, existing pipeline system 

maps, agency consultations, and other publicly available information. Identical data sources 

were used when comparing the alternative to the Project (e.g., NWI maps used for both). The 

results of the alternatives analyses are provided in the following sections.

3.1 NO-ACTION ALTERNATIVE

Under the No-Action Alternative, the objectives of the Project would not be met and 

Cameron would not provide the proposed natural gas transportation capacity for export. In 

addition, the potential adverse and beneficial environmental impacts identified in section 4.0 of 

this EIS would not occur.

Development of and production from conventional and unconventional gas formations 

are occurring throughout many areas of the United States and are projected to continue for many 

years. Cameron LNG indicated it could provide LNG to foreign countries at a competitive price 
Alternatives 3-2

and, therefore, replace higher-cost shipments from other sources. With or without the No-Action 

Alternative, other LNG export projects could also be developed elsewhere in the Gulf Coast 

region or in other areas of the United States resulting in both adverse and beneficial 

environmental impacts. Expansions of alternative existing terminals with minor expansions of 

existing pipeline systems would result in similar magnitude and duration of potential adverse 

environmental impacts to those of the proposed Project. Development of any new LNG export 

terminals on previously undeveloped sites would likely result in greater environmental impacts, 

in both magnitude and duration, than those of the proposed Project.

The No-Action Alternative could also require that potential end users make other 

arrangements to obtain natural gas service, make use of alternative fossil fuel energy sources (for 

example, coal or fuel oil), or possibly make use of other traditional long-term fuel source 

alternatives (such as nuclear power) and/or renewable energy sources (for example, solar power) 

to compensate for the reduced availability of natural gas that would otherwise be supplied by the 

proposed Project. Although international energy conservation could also result from the NoAction Alternative, that option is beyond the scope of this analysis. 

We believe it is important to consider alternative energy sources as part of the alternative 

selection process. As noted above, implementing the No-Action Alternative could force 

potential natural gas customers to seek other forms of energy. Traditional energy alternatives to 

natural gas include coal, oil, hydroelectric, and nuclear power. Renewable energy resources such 

as solar, ocean energy, biomass, wind, landfill gas, and municipal solid waste represent new, 

advanced energy alternatives. Conceivably, each of these energy alternatives could support the 

generation of new electric power, which is a major consumer of natural gas along with 

residential heating, commercial, and industrial uses. 

The International Energy Agency (IEA) (2012b) reported that coal exports are increasing, 

and in the United States several new coal export projects were recently proposed, suggesting that 

in many international markets coal will remain competitive with natural gas in spite of coal’s 

greater air emissions. EPA (2013) stated that compared to the average air emissions from coalfired generation, natural gas produces half as much carbon dioxide, less than a third as much 

nitrogen oxides, and 1 percent as much sulfur oxides at power plants. Similarly, fuel oil is 

commonly used for power generation in many countries and will continue to compete with 

natural gas as a fuel source in spite of greater emissions. As a result, if the No-Action 

Alternative is selected, it could result in a greater use of other fossil fuels and a potentially 

substantial increase of environmental impacts as compared to the use of natural gas. However, 

many countries are cognizant of the greater environmental impact of coal and fuel oil and prefer 

to use natural gas as a fuel source.

There has been a recent renewed interest in electric power generation by nuclear energy. 

However, because of the increasing demand in electricity consumption worldwide, EIA (2012)

estimates that the proportion of electricity generated by nuclear power will decrease from 19 

percent to 15 percent. In addition, regulatory hurdles, public concern over nuclear power and 

nuclear waste disposal, construction costs, and plant construction lead times make it unlikely that 

nuclear generating capacity could be available to serve all the markets targeted by the Project on 

a similar timeline. Further, plans for nuclear power generation have been scaled back as 

countries reconsidered policies after the accident at the Fukushima Daiichi nuclear power plant 
3-3 Alternatives

near Fukushima, Japan, but capacity is still projected to rise, led by China, Korea, India, and 

Russia (IEA 2012a).

Renewable energy may become an increasingly significant factor in meeting future 

energy demands worldwide. As reported by IEA (2012a and 2012b), renewables are projected to 

become the world’s second-largest source of power generation by 2015, and are expected to 

close in on coal as the primary source by 2035. However, this rapid increase hinges critically on 

continued subsidies. In 2011, these subsidies (including for biofuels) amounted to $88 billion, 

but to reach the projection noted above, the subsidies would need to increase to $4.8 trillion by

2035 (IEA 2012a). 

Hydropower is currently the largest source of renewable electric power generation 

worldwide, and IEA expects this trend to continue through 2030. However, as with nuclear 

power generation, there are high costs associated with developing substantial hydropower 

projects and long time periods between project conception and the production of electric power. 

Other promising renewable energy resources include solar, ocean energy, and biomass. 

However, the cost of these types of renewable energy projects is currently high per energy output 

unit in comparison to natural gas-fired power generation. Photovoltaic production in support of 

solar energy is increasing, and the cost of photovoltaic systems is decreasing, with photovoltaic 

cells potentially able to greatly supplement electrical generation resources. 

Ocean energy is a largely unexplored renewable resource. Technologies to capture ocean 

energy are in their infancy, and environmental and engineering considerations are being studied 

to better understand the implications of placement of power generating facilities in the ocean. 

Entrepreneurs and scientists are exploring the emerging use of algae for biofuels and 

other renewable energy applications, and are working to accelerate the development of 

applications to use algal biomass. IEA (2012b) projected electric power generation from 

biomass technology to increase four-fold through 2035, but that time frame is well beyond the 

planned startup and the currently requested authorization lifetime of the proposed Project. 

Further generation of electrical power by wind would require construction of new wind 

turbines and additional electric transmission lines. Although this is likely to occur in many parts 

of the world, it is also likely that such development will be slow-paced in most countries due to 

the high cost of construction. In addition, wind power cannot be used for constant and reliable 

energy production because of the variability in winds, and other power generation facilities are 

commonly in place as backup facilities.

Electric generation from municipal waste and landfill methane are growing trends in

developed countries. Again, the cost of these facilities, including operating costs, is beyond the 

means of many countries. 

With regard to these renewable sources of energy, natural gas is often considered a 

“bridge fuel;” a fuel that bridges the time between the dominant use of fossil fuels today and the 

greater use of renewable energy sources in the future. Natural gas is cleaner burning than other 

fossil fuels and can also reliably serve as a backup fuel to renewable energy facilities, which

often provide power intermittently. 
Alternatives 3-4

There is currently considerable momentum behind advancing renewable energy 

technologies and moving toward more diversified energy sources. These advanced technologies, 

either individually or in combination, will likely be important in addressing future energy 

demands. Presumably new energy technologies will continue to offset an increasing amount of 

fossil fuels to meet growing energy demands, and that situation is not expected to change in the 

next decade. 

Although it is speculative and beyond the scope of this analysis to predict what action 

might be taken by policymakers or end users in response to the No-Action Alternative, it is 

possible that without the proposed Project, the energy needs may be met by alternative energy 

sources, likely resulting in impacts on the environment. Alternative energy forms such as coal 

and oil are available and could be used to meet increased demands for energy; however, natural 

gas is a much cleaner-burning fuel. These other fossil fuels emit greater amounts of particulate 

matter, sulfur dioxide (SO2), carbon monoxide (CO), carbon dioxide (CO2), hydrocarbons, and 

non-criteria pollutants. The use of nuclear energy as replacement of other fuel sources also 

carries undesirable consequences, such as negative public perception of the safety of electric 

generation through nuclear plants and the disposal of waste products created. Renewable 

energies, such as solar, hydroelectric, and wind are not always reliable or available in sufficient 

quantities to support most market requirements and would not necessarily be an appropriate 

substitute for natural gas in all applications. Therefore, we have dismissed this alternative as a 

reasonable alternative to meet the Project objectives.

3.2 SYSTEM ALTERNATIVES

We reviewed system alternatives to evaluate the ability of existing, modified, or proposed 

facilities to meet the stated objectives of the Project. Our analysis of the systems alternatives is 

presented below in sections 3.2.1 and 3.2.2. The purpose of identifying and evaluating system 

alternatives was to determine whether potential environmental impacts associated with the 

construction and operation of the Project could be avoided or reduced. By definition, 

implementation of a system alternative would make it unnecessary to construct all or part of the 

proposed Project, although modifications or additions to the system alternative may be required 

to increase capacity or provide receipt and delivery capability consistent with that of the 

proposed Project. Such modifications or additions may result in environmental impacts less 

than, comparable to, or greater than those associated with construction and operation of 

Cameron’s Project. 

3.2.1 Terminal Expansion System Alternatives 

For a system alternative to be viable, it must be technically and economically feasible. It 

must also be compatible with Cameron LNG’s contractual agreements relating to the export of 

LNG (see section 1.1 for information on Cameron LNG’s contractual agreements). In addition, a 

viable system alternative would offer a significant environmental advantage over the Project. 

The system alternatives considered in this analysis are depicted on figure 3.2-1 and described 
3-5 Alternatives

Figure 3.2-1 System Alternatives for the Liquefaction Terminal
Alternatives 3-6

below. Although we have considered each of the planned, proposed, or authorized projects17

below as potential system alternatives, both individually and in combination, the market will 

ultimately decide which and how many of these facilities are built.

3.2.1.1 Existing LNG Import Terminals with Planned, Proposed, or Authorized 

Liquefaction Projects

There are five operating LNG import terminals in the southeastern United States along 

the Gulf of Mexico in addition to the existing Cameron LNG Terminal:

• Freeport LNG Development, LP (Freeport LNG) Terminal;

• Golden Pass LNG, LLC (Golden Pass LNG) Terminal;

• Gulf LNG Energy, LLC (Gulf LNG) Terminal;

• Sabine Pass LNG, LP’s (Sabine Pass LNG) Terminal; and 

• Trunkline LNG Company, LLC’s (Trunkline LNG) Lake Charles LNG Terminal. 

The Sabine Pass Liquefaction Project is under construction, and the other import 

terminals are in the regulatory review and permitting process for adding liquefaction and export 

capabilities. Each of these facilities was considered as a system alternative to Cameron LNG’s 

proposed Project.

Freeport LNG Terminal

The Freeport LNG Terminal is on Quintana Island in Brazoria County, Texas. The 

import terminal, which started operations in 2008, includes two 160,000 m3 LNG storage tanks 

and a single berth capable of handling LNG carriers in excess of 200,000 m3. It has a peak send 

out capability of approximately 1.5 Bcf of natural gas. 

Freeport LNG Expansion, LP and FLNG Liquefaction, LLC (collectively, FLEX) 

propose to add liquefaction facilities to its existing terminal to provide export capacity of 

approximately 13.2 mtpy of LNG. The existing Freeport LNG Terminal is about 142 miles 

southwest of the proposed Terminal Expansion site. This project would require approximately 

86 acres for three proposed trains, each with a nominal capacity of 4.4 mtpy. FLEX filed two 

separate applications to DOE/FE to export LNG to Free Trade Agreement countries, as well as 

an amendment to the applications. DOE/FE approved the applications in February 2011 and 

2012 and approved the amendment in February 2014. On December 17, 2010 and December 19, 

2011, FLEX submitted applications to DOE/FE to export LNG to non-Free Trade Agreement 

nations, and submitted an amendment to the applications on September 19, 2013. DOE/FE 

authorized such exports on May 17, 2013, November 15, 2013 and February 7, 2014. FLEX 

filed its application with the FERC on August 31, 2012 (FERC Docket No. CP12-509-000). 

FERC issued the draft EIS for this project on March 14, 2014. 

 17 Proposed projects are projects for which the proponent has submitted a formal application with the FERC; 

planned projects are projects that are either in pre-filing or have been announced, but have not been proposed.
3-7 Alternatives

On July 31, 2012, Freeport LNG Expansion signed a 20-year agreement with Osaka Gas 

and Chubu Electric for 100 percent of the first train (4.4 mtpy), and in February 2013 signed a 

20-year agreement with BP for all of the second train (4.4 mtpy). In September 2013, FLEX 

signed separate liquefaction tolling contracts with Japan's Toshiba Corp and South Korea's 

SK E&S for all of the plant's third train.

FLEX anticipates start-up for the first liquefaction train in December 2018, with full 

service occurring as early as December 2019. The full capacity of the Freeport LNG Terminal 

expansion is contracted and use of the Freeport LNG Terminal as a system alternative to meet 

Cameron LNG’s commitments to its clients would require that FLEX construct and operate three 

additional liquefaction trains and associated facilities, similar to those of the proposed Project

which would likely result in environmental impacts similar to those of the proposed Project. 

However, FLEX has not requested authorization for the increased capacity and receipt of permits 

and approvals for the additional facilities that would be needed to meet Cameron LNG’s 

objectives. Construction of three additional trains and associated facilities at the FLEX site 

would result in impacts likely to be similar to those of constructing the liquefaction trains and 

associated facilities for proposed Project. In addition, the time required to obtain FERC 

authorization and additional permits and to construct the additional facilities would not meet 

Cameron LNG’s general timeline commitments of initial in-service date. Therefore, the Freeport 

Liquefaction Project was not considered to be significantly environmentally preferable or a 

reasonable alternative to the proposed Terminal Expansion and was removed from further 

consideration.

Golden Pass LNG Terminal 

The Golden Pass Terminal is near the town of Sabine Pass, Texas, on the western shore 

of Sabine Pass Channel, about 40 miles west of the proposed Terminal Expansion site. 

Operations started in 2010 on the approximately 477-acre site. The import terminal includes five 

155,000 m3 LNG storage tanks and two LNG carrier berths. It has a maximum send-out capacity 

of 2.5 Bcfd of natural gas. The planned export facility would use the existing storage tanks, 

berthing facilities, and pipeline infrastructure of the import terminal and would have a send-out 

capacity of 15.6 mtpy of LNG.

Golden Pass Products, LLC (GPP) received approval from DOE/FE to export LNG to 

Free Trade Agreement countries on October 7, 2012. On October 26, 2012, GPP submitted an 

application to export LNG to non-Free Trade Agreement nations. At the time this EIS was 

prepared, the GPP application to export to non-Free Trade Agreement countries was under 

review by DOE/FE. On May 9, 2013, Golden Pass announced that it had signed a Commercial 

Framework Agreement for the proposed liquefaction project to sell up to the full 15.6 mtpy 

output of the project (Golden Pass Products 2013).

On May 30, 2013, the FERC initiated the pre-filing process for the project.18 At the time 

this EIS was prepared, GPP planned to submit its application to FERC in June 2014. As a result, 

the Golden Pass LNG Terminal is substantially behind Cameron LNG in the permitting and 

review schedule and therefore would likely not be permitted for service in time to meet the 

customer commitments of the Cameron Liquefaction Project, beginning in 2017. Further, the 

 18 Docket No. PF13-14.
Alternatives 3-8

entire production volume of LNG has been committed to a customer and would not be available 

to Cameron LNG without substantially expanding the facility. The environmental impacts of 

constructing and operating the facilities needed to expand beyond the planned capacity would 

likely be similar to those of Cameron’s proposed Project. Therefore, this project would not 

provide a significant environmental advantage to Cameron’s proposed Project and was not 

considered further.

Gulf LNG Terminal

The Gulf LNG Terminal is on a 40-acre site in Pascagoula, Mississippi, about 290 miles 

east of the proposed Terminal Expansion site. The terminal started operations in October 2011

and has a send-out capacity of 1.3 Bcfd of natural gas. The import terminal includes two 

160,000 m3 LNG storage tanks and a single LNG carrier berth designed to receive LNG carriers 

up to 250,000 m3 in capacity. On June 15, 2012, Gulf LNG Liquefaction Company, LLC 

received authorization from DOE/FE to export to Free Trade Agreement countries. At the time 

this EIS was prepared, the Gulf LNG application to export to non-Free Trade Agreement 

countries was under review by DOE/FE.

Gulf LNG would construct its export project at its existing terminal with plans to export 

up to 11.5 mtpy of LNG. On December 5, 2012, Gulf LNG requested to use the FERC pre-filing 

process, and on December 14, 2012, the FERC denied the request until Gulf LNG fully complies 

with the relevant Commission regulations. At the time of preparation of this EIS, the FERC had 

not initiated the pre-filing process for Gulf LNG. 

The Gulf LNG Terminal is substantially behind Cameron LNG in the permitting and 

review schedule, if it decides to file an application, and therefore could not be permitted for 

service in time to meet the general customer commitments of the Cameron Liquefaction Project

beginning in 2017. As a result, the planned Gulf LNG Liquefaction Project does not meet the 

Project objective and was not further evaluated.

Sabine Pass LNG Terminal 

The Sabine Pass LNG Terminal is in Cameron Parish, Louisiana, on the eastern shore of 

the Sabine Pass Channel, about 38 miles west of the proposed Terminal Expansion site. The 

terminal is on an approximately 853-acre site and includes five LNG storage tanks with a total 

storage capacity of 16.9 Bcf and two LNG carrier berths. The facility has a send-out capacity of 

4 Bcfd of natural gas. 

On April 16, 2012, the FERC authorized Sabine Pass LNG to receive, process, and export 

16 mtpy of domestically produced natural gas as part of its liquefaction project (Docket No. 

CP11-72). The Sabine Pass Liquefaction Project also received authorization from DOE/FE to 

export LNG to Free Trade Agreement countries (September 7, 2010) and to non-Free Trade

Agreement countries (May 20, 2011). The Sabine Pass Liquefaction Project is permitted for up 

to four liquefaction trains, each with an average liquefaction capacity of approximately 4 mtpy, 

and in August 2013, Sabine Pass LNG applied to the FERC to construct and operate two 

additional trains. The project is under construction and will involve the permanent use of about 

191 acres as well as temporary disturbance of about 97 acres within the existing Sabine Pass 

LNG Terminal site. Approximately 22 mtpy of the potential 24 mtpy is fully committed to 
3-9 Alternatives

Sabine Pass LNG customers. Therefore, the Sabine Pass Liquefaction Project would have to 

construct additional facilities to meet the Project’s stated purpose, which would likely have 

similar environmental impacts to the proposed Project. The permitting and authorization 

processes for constructing these additional facilities and the time required for construction would 

preclude Sabine Pass LNG from meeting Cameron LNG’s timeline commitments to its 

customers. As a result of the similar environmental impacts and added time for the permitting 

process, the Sabine Pass Liquefaction Project was not considered to provide a significant 

environmental advantage or be a reasonable system alternative to Cameron’s proposed 

Liquefaction Project and was not evaluated further.

Lake Charles LNG Terminal 

The Lake Charles LNG Terminal is in Lake Charles, Louisiana, and started operations in 

1977. The import terminal is situated on approximately 125 acres about 6 miles north-northeast 

of the proposed Terminal Expansion site and has a peak send-out capacity of 2.1 Bcfd of natural 

gas. Two LNG carrier berths provide loading and unloading capacity. 

On July 22, 2011, Lake Charles Export, LLC received authorization from DOE/FE to 

export LNG to Free Trade Agreement countries from the Lake Charles LNG Terminal, and on 

August 7, 2013, received authorization from DOE/FE to export LNG to non-Free Trade

Agreement countries. On April 6, 2012, Trunkline LNG received approval from the FERC to 

use the pre-filing process for the Lake Charles Liquefaction Project. Trunkline LNG would 

construct the project on an approximately 400-acre parcel, about 0.5 mile west of the existing 

Lake Charles LNG Terminal. The facility would include three liquefaction trains, each capable 

of producing 5 mtpy for a total output capacity of 15 mtpy. Trunkline LNG initially anticipated

an in-service date of August 2018.

19 However, at the time this EIS was prepared, Trunkline 

LNG was still in the pre-filing process. 

Although the Lake Charles Liquefaction Project would provide 3 mtpy more LNG sendout capacity than the Cameron LNG Liquefaction Project, its export capacity is solely contracted 

to one customer, BG LNG. Further, the Lake Charles LNG Terminal export expansion would 

not be in service until approximately 3 years after it receives authorization from the FERC and 

all other necessary permits, and at this time it is not clear when the final EIS will be issued for 

the project. Additional facilities at the Lake Charles LNG Terminal could meet Cameron LNG’s 

objective. The environmental impacts of those facilities would likely be similar to those of 

Cameron’s proposed project. Therefore, additions to Trunkline LNG’s proposed project would 

not provide a significant environmental advantage to the proposed Project. Additionally, 

Trunkline LNG has not requested authorization for the increased capacity, and receipt of permits 

and approvals for the additional facilities required to meet Cameron LNG’s objectives would not 

meet Cameron LNG’s timeline commitments. Therefore, this alternative was not evaluated 

further.

 19 Docket No. PF12-8.
Alternatives 3-10

3.2.1.2 Proposed and Planned Stand-Alone LNG Export Terminals

In addition to the five existing LNG import facilities described above, there is one 

proposed stand-alone liquefaction project and six planned stand-alone liquefaction projects along 

the Gulf Coast:

• proposed Corpus Christi Liquefaction, LLC (Corpus Christi) Liquefaction Project;

• planned Gulf Coast LNG Exports, LLC (Gulf Coast) Liquefaction Terminal;

• proposed Excelerate Liquefaction Solutions, LLC (ELS) Lavaca Bay LNG Project;

• planned Magnolia LNG (Magnolia) Project;20

• planned Gasfin Development USA, LLC (Gasfin) LNG Project; 

• planned Waller Point LNG (Waller Point) Project; and 

• planned CE FLNG, LLC (CE FLNG) LNG Project.

21 

These projects are new or “greenfield” projects that are not associated with existing LNG 

import terminals, but we considered them as potential system alternatives. 

Corpus Christi Liquefaction Project

The proposed Corpus Christi Liquefaction Project is in San Patricio County, Texas, on 

the northeast side of Corpus Christi Bay at its previously authorized site for the Corpus Christi 

LNG Import Terminal that was never constructed due to market conditions (see Docket No. 

CP04-37). The proposed export terminal site is about 281 miles southwest of Cameron LNG’s 

proposed Terminal Expansion site and includes three liquefaction trains, each with an average 

liquefaction capacity of about 4.5 mtpy for a total send-out capacity of 13.5 mtpy; three 160,000 

m3 LNG storage tanks; and two LNG carrier docks. The proposal includes an approximately 23-

mile-long, 48-inch-diameter pipeline that would connect the LNG terminal with five interstate 

and intrastate natural gas transmission pipelines in south Texas. This project would affect 

approximately 1,000 acres of land during construction.

On October 10, 2012, Corpus Christi received authorization from DOE/FE to export 

LNG to Free Trade Agreement countries. At the time this EIS was prepared, the Corpus Christi 

application to export to non-Free Trade Agreement countries was under review by DOE/FE. 

Corpus Christi received approval to use the FERC pre-filing process on December 22, 2011, and 

submitted its application on August 31, 2012.

22 In Resource Report 1 of its application, Corpus 

Christi proposed a construction start date of October 2013 with “substantial completion of Train 

1 planned for late 2017.” In December 2013, Cheniere Energy announced that it had entered into 

a commercial agreement with PT Pertamina for approximately 0.8 mtpy and is continuing work 

toward finalizing additional commercial agreements (PR Newswire 2014), and in April 2014 

Cheniere Energy announced it had entered into a commercial agreement for 1.5 mtpy with 

 20 Docket No. PF13-9. 21 Docket No. PF13-11. 22 Docket No. CP12-507.
3-11 Alternatives

Endesa Generacion SA (Oil and Gas Journal 2014a). We anticipate that Cheniere Energy will be 

entering into commercial agreements for much of its production capacity for the first two trains 

and would not be able to provide the 12 mtpy required by Cameron LNG to meet its 

commitments to its customers without constructing additional facilities. In addition, as a 

greenfield facility requiring about 1,000 acres of land during construction and requiring new 

berthing facilities, this project would not provide a significant environmental advantage to 

Cameron’s Project. Therefore, this system alternative was not considered further.

Gulf Coast Liquefaction Project

The Gulf Coast Liquefaction Project would export LNG from a planned export terminal 

at the Port of Brownsville in Brownsville, Texas, about 376 miles west-southwest of the 

proposed Terminal Expansion site. On October 16, 2012, Gulf Coast received authorization 

from DOE/FE to export LNG to Free Trade Agreement countries. At the time this EIS was 

prepared, the Gulf Coast application to export to non-Free Trade Agreement countries was under 

review by DOE/FE and Gulf Coast had not requested that the FERC initiate the pre-filing 

process. 

The project, as proposed to DOE/FE, would include a new terminal on about 500 acres, 

four liquefaction trains capable of liquefying a total of 2.8 Bcfd of natural gas, an unspecified 

number of LNG storage tanks, a marine berth, and a pipeline connecting the terminal to existing 

natural gas transportation lines. Rather than enter into long-term natural gas supply or LNG 

export contracts, Gulf Coast would set up liquefaction tolling agreements allowing individual gas 

customers to deliver gas and receive LNG from the terminal. At the time Gulf Coast announced 

the project, it anticipated an in-service date of 2018. However, it is likely that the FERC 

environmental review and the reviews of other permit applications would result in a delay of 

about 2 years from that date if the pre-filing process were to be initiated in the second quarter of 

2014. As a result, the project will not be in service in the general timeframe of Cameron and 

would not be able to meet the contractual agreements of Cameron LNG’s customers. 

As a greenfield facility, the environmental impacts associated with development on an 

undisturbed site would likely be greater in both magnitude and duration than those of the 

Cameron Liquefaction Project. Therefore, the Gulf Coast Liquefaction Project would not 

provide a significant environmental advantage to Cameron LNG’s Terminal Expansion. In 

addition, the Gulf Coast Liquefaction Project would not be completed in Cameron LNG’s

timeline for commitments to customers. Therefore, this system alternative was not considered 

further. 

Lavaca Bay LNG Project

The planned Lavaca Bay LNG Project includes two floating liquefaction, storage, and 

offloading (FLSO) units that produce LNG from North American natural gas. The project would 

also include about 190 acres of onshore pre-treatment facilities and infrastructure associated with 

the FLSOs. LNG would be stored, as needed, prior to transferring the LNG to carriers for

export. The FLSOs would be permanently moored at a proposed shoreside dock in Port Lavaca 

in Calhoun County, Texas, about 215 miles southwest of the proposed Terminal Expansion site.
Alternatives 3-12

At full capacity, the Lavaca Bay LNG Project would include a total of eight liquefaction 

trains, storage of up to 500,000 m3 of LNG, and a send-out capacity of 10 mtpy of LNG. The 

project would consist of two phases, with one FLSO and associated facilities to be constructed 

during Phase I, resulting in an LNG export capacity of 5 mtpy. 

On August 9, 2012, Lavaca Bay received authorization from DOE/FE to export LNG to 

Free Trade Agreement countries. At the time this EIS was prepared, the Lavaca Bay application 

to export to non-Free Trade Agreement countries was under review by DOE/FE. On October 23, 

2012, ELS submitted a Letter of Intent and a preliminary WSA to the Coast Guard for 

consideration in its assessment of the waterway and issuance of a LOR regarding the suitability 

of the waterway for LNG marine traffic. On February 6, 2014, ELS filed an application with the 

FERC for the project (Docket Nos. CP14-71 and CP14-72), which would consist of two phases. 

ELS plans to initiate construction of Phase 1 in January 2015, with an in-service date of 

December 2018. ELS stated in its application that construction of Phase 2 would begin when 

sufficient commitments are made by customers to make the project commercially feasible. The 

Lavaca Bay LNG Project would not have the capacity needed to meet Cameron LNG’s 

commitments to customers. While additional facilities at the Lavaca Bay LNG Project site could 

meet Cameron LNG’s export objective, the additional facilities required may include creation of 

two new berthing areas and turning basins as well as additional pretreatment and other onshore 

facilities. We anticipate that the environmental impacts associated with offshore construction of 

those facilities (80 acres for Phase 1, and likely double that with Phase 2) would be greater than 

those of Cameron’s proposed Project (15 acres), potentially resulting in greater effects on EFH 

and sensitive aquatic and marine mammal species. Even with both phases constructed and all 

capacity provided to Cameron LNG, the project could not provide the volume of LNG 

committed to Cameron LNG’s customers and additional facilities would have to be constructed. 

Therefore, the Lavaca Bay LNG Project would not provide a significant environmental 

advantage to Cameron LNG’s Terminal Expansion. 

Magnolia LNG Project 

Magnolia would construct its liquefaction and LNG export project at the Port of Lake 

Charles in Calcasieu Parish, at the port’s Industrial Canal, off the Calcasieu Ship Channel, about 

5.5 miles north-northeast of the proposed Terminal Expansion site (see figure 3.2-1). The 

Magnolia LNG Project would be a stand-alone LNG export facility, not associated with an 

existing LNG terminal, and constructed on a 90-acre site. At full capacity, the project would 

export 8 mtpy of LNG using four liquefaction trains, each with a nominal capacity of 2.0 mtpy of 

LNG. 

On February 26, 2013, DOE/FE issued an authorization to export 4 mtpy of LNG to 

foreign countries with which the United States has existing Free Trade Agreements and issued a 

second authorization to export 4 mtpy on March 7, 2014. At the time this EIS was prepared, the 

Magnolia LNG application to export to non-Free Trade Agreement countries was under review 

by DOE/FE. On March 20, 2013, the FERC initiated its pre-filing process for the project under 

Docket No. PF13-9. Magnolia expects to file its application with the FERC in “March-April”

2014 (Oil & Gas Journal 2014b). Magnolia proposes to start construction in June 2015, with an 

in-service date of June 2018 for the first train and full service in 2019. Magnolia is in 
3-13 Alternatives

negotiations of long-term tolling agreements with three companies and has signed a fourth nonbinding tolling term sheet with the AES Group (Yahoo Finance 2014).

To meet Cameron LNG’s customer commitments, Magnolia would need to commit all of 

the capacity of the four trains to Cameron LNG and construct at least two additional trains. This 

would expand Magnolia’s greenfield project to roughly the same acreage as Cameron LNG’s 

Terminal Expansion to export 12 mtpy. However, Magnolia is in the process of negotiating 

agreements for at least a portion of the proposed LNG output capacity, which would require a 

further increase in the size of the facility to meet Cameron LNG’s export needs. As a greenfield 

facility, the environmental impacts associated with development on an undisturbed site would 

likely be greater in both magnitude and duration than those of Cameron LNG’s proposed 

Terminal Expansion. Therefore, this project does not possess a significant environmental 

advantage to Cameron LNG’s Terminal Expansion. Additionally, Magnolia has not requested 

authorization for the increased capacity and receipt of permits and approvals for the additional 

facilities that would be needed to meet Cameron LNG’s objectives. Therefore, this system 

alternative was not considered further. 

Gasfin LNG Project

The planned Gasfin LNG Project is a liquefaction and LNG export project in Cameron 

Parish on the east side of the Calcasieu Ship Channel, about 18 miles south of the proposed 

Terminal Site (see figure 3.3-1). The project would be a stand-alone LNG export facility that is 

not associated with an existing LNG terminal and would have an LNG export capacity of 1.5 

mtpy. 

On March 7, 2013, DOE/FE granted Gasfin long-term authorization to export LNG to 

countries with which the United States has existing Free Trade Agreements. At the time this EIS 

was prepared, the Gasfin application to export to non-Free Trade Agreement countries was under 

review by DOE/FE. The Gasfin Project is in the initial development phase and an anticipated 

scheduled has not yet been released. At the time this EIS was prepared, Gasfin had not requested 

that the FERC initiate the pre-filing process. We do not consider the Gasfin LNG Project to be a 

reasonable alternative to the proposed Terminal Expansion because it would not be completed in 

time or have the send-out capacity for Cameron LNG to meet its commitments to customers and 

is a greenfield project that likely would not provide a significant environmental advantage to the 

proposed Terminal Expansion. Therefore, this system alternative was not considered further. 

Waller Point LNG Terminal

The planned Waller Point LNG Project is a stand-alone liquefaction and LNG export 

facility in Cameron Parish on the western shore of the entrance point of the Calcasieu Ship 

Channel from the Gulf of Mexico, about 19 miles south of the proposed Terminal Expansion 

site. The project would have an LNG export capacity of about 1.25 mtpy. On December 20, 

2012, DOE/FE granted long-term authorization to Waller Point LNG for LNG export to 

countries with which the United States has existing Free Trade Agreements. At the time this EIS 

was prepared, the Waller Point application to export to non-Free Trade Agreement countries was 

under review by DOE/FE.
Alternatives 3-14

The project is in the initial development phase and Waller Point LNG has not announced 

a planned schedule. Further, at the time this EIS was prepared, Waller Point LNG had not 

requested that the FERC initiate the pre-filing process. We do not consider the Waller Point 

LNG Terminal to be a reasonable system alternative to the Terminal Expansion because it would 

not be completed in time or have the send-out capacity for to meet Cameron LNG’s

commitments to customers and is a greenfield project that likely would not provide a significant

environmental advantage to the proposed Terminal Expansion. Therefore, this system 

alternative was not considered further. 

CE FLNG LNG Project

CE FLNG announced plans for developing a floating LNG liquefaction and export 

terminal on the east bank of the Mississippi River north of the confluence of Baptiste Collette 

Bayou in Plaquemines Parish, Louisiana, about 245 miles east-southeast of the proposed 

Terminal Expansion site. Project facilities include two FLSO vessels, each capable of producing 

up to 4 mtpy of LNG, and approximately 125 acres of onshore facilities. The FLSOs would have 

an LNG storage capacity of 250,000 m3

. LNG carriers would berth next to the units to load 

LNG. The project would include a 45-mile-long pipeline to connect the terminal with two 

sources of natural gas: (1) the existing Enterprise Products natural gas processing plant in 

Bernard Parish, (2) and the existing Targa Venice natural gas processing plant in Plaquemines 

Parish, Louisiana. CE Pipeline, LLC plans to construct and operate the pipeline. 

The project would be a stand-alone liquefaction and LNG export facility that is not 

associated with an existing LNG terminal. On November 21, 2012, DOE/FE granted long-term 

export authorization to CE FLNG for LNG export to foreign countries with which the United 

States has existing Free Trade Agreements. At the time this EIS was prepared, the CE FLNG 

application to export to non-Free Trade Agreement countries was under review by DOE/FE, and 

CE FLNG was in the FERC pre-filing process under Docket No. PF13-11. However, because 

CE FLNG had not filed its application with the FERC at the time this EIS was prepared, it is 

likely that the start of construction would be after January 2015. The project would not be able to 

meet the general timeframe of Cameron LNG’s contractual agreements. 

To meet Cameron LNG’s customer commitments, CE FLNG would need to commit the 

entire capacity of the project to Cameron LNG’s customers and install an additional FLSO vessel 

which would require establishing an additional berthing facility and a turning basin and 

associated onshore facilities. The environmental impacts associated with development of marine 

berthing facilities and onshore facilities in an undisturbed area would likely be greater in both 

magnitude and duration than those of Cameron LNG’s proposed Terminal Expansion. 

Therefore, CE FLNG’s project would not provide a significant environmental advantage to 

Cameron LNG’s Terminal Expansion. Additionally, CE FLNG has not requested authorization 

for the increased capacity, and receipt of permits and approvals for the additional facilities that 

would be needed to meet Cameron LNG’s objectives would likely not meet Cameron LNG’s 

timeline commitments. Therefore, this system alternative was not considered further. 

3.2.1.3 Combined Export Projects Considered as a System Alternative

In its comments on the draft EIS, the Sierra Club and The Tulane Environmental Law 

Clinic (termed the Sierra Club comment letter throughout this EIS and included in Appendix L 
3-15 Alternatives

as comment letter IP2) expressed concern that the system alternative analysis for the Terminal 

Expansion presented in the draft EIS consisted only of assessments of single alternative LNG 

export projects rather than including a combination of multiple “smaller proposals.” We 

interpret that as the alternative of obtaining portions of the LNG that Cameron LNG has 

committed to its customers from two or more of the LNG export facilities considered above. 

Although such an approach is a viable concept, that goal is not achievable for the reasons 

discussed below.

Of the 12 export terminals assessed as potential system alternatives, three are fully 

subscribed and would have no excess capacity without construction of additional facilities: the 

Freeport LNG Terminal, the Sabine Pass LNG Terminal, and the Lake Charles LNG Terminal. 

The potential impacts associated with the necessary additional facilities are addressed above and 

these projects are not considered candidates for providing a portion of the volume of LNG that 

Cameron LNG has committed to its customers.

Four other export projects have not yet initiated the FERC pre-filing process: the Gasfin 

LNG Project: the Waller Point LNG Project, the Gulf LNG Terminal, and the Gulf Coast LNG 

Project. None of those projects would be operating in the general timeframe to reasonably 

achieve Cameron LNG’s commitments to provide LNG, and it is not likely that any of those 

projects would be in full production by 2019, as required by Cameron LNG’s existing customers. 

Similarly and as noted above, four other export projects would not be in service in a reasonable 

timeframe to meet the contracted need of Cameron LNG’s customers: the CE FLNG Project, the 

Lavaca Bay LNG Project, the Magnolia Project, and the Golden Pass LNG Project. 

As a result, 11 of the 12 projects considered in the system alternatives analysis would not 

be able to provide any portion of the volume of LNG required for export to meet Cameron 

LNG’s contractual commitments to existing customers. This leaves only the Corpus Christi 

Liquefaction Project as a potential system alternative. Our assessment of that project as a system 

alternative is provided in section 3.2.1.2. 

3.2.2 Pipeline System Alternatives

To serve as a viable system alternative to the proposed Pipeline Expansion, the system 

would have to (1) transport all or a part of the volume of natural gas required for liquefaction at 

the expanded terminal, and (2) cause significantly less impact on the environment than the 

proposed Pipeline Expansion. Gas provided by a system alternative must connect to either the 

existing Cameron Interstate Pipeline or directly to the expanded terminal. 

The existing Cameron Interstate Pipeline has interconnections to four interstate natural 

gas pipelines: FGT, TGP, TETCO, and Transco. These pipelines would provide natural gas to 

the expanded pipeline and were therefore not considered as system alternatives. There are three 

other pipelines in the vicinity of the existing Cameron Interstate Pipeline and the proposed 

Terminal Expansion that we evaluated as potential system alternatives to the proposed Pipeline 

Expansion: Cheniere Energy’s Creole Trail Pipeline, Trunkline Gas Company’s Trunkline

Pipeline, and the Gulf South Pipeline. 
Alternatives 3-16

3.2.2.1 Creole Trail Pipeline

The Creole Trail Pipeline is a 153-mile-long, 42-inch-diameter pipeline that can transport 

vaporized LNG from the Sabine Pass LNG Terminal and is being modified to provide natural 

gas to the Sabine Pass Liquefaction Project for liquefaction and exportation. At full capacity, the 

pipeline transports approximately 2.6 Bcfd of natural gas to the Sabine Pass Liquefaction Project 

(FERC 2011). The pipeline extends from the Sabine Pass LNG Terminal in Cameron Parish to 

interconnections with National Gas Pipeline Company of America, Transco, TGP, FGT, 

Bridgeline Holding Company, TETCO, and Trunkline. 

The Creole Trail Pipeline is being modified to provide bi-directional flow. At its 

maximum flow rate of 2.6 Bcfd, it can transport sufficient natural gas to allow the Sabine Pass 

Liquefaction Project to export up to 16 mtpy of LNG. Because all 16 mtpy of LNG from the 

Sabine Pass Liquefaction Project is committed to customers, the Creole Trail Pipeline would not 

have sufficient capacity to supply natural gas to the Cameron Liquefaction Project without 

substantially expanding the system by looping. The pipeline is in the vicinity of both the 

Terminal Expansion site and the existing Cameron Interstate Pipeline and has interconnections 

with many of the same pipelines as the proposed Pipeline Expansion. However, to provide the 

2.35 Bcfd required by the Terminal Expansion, an additional 42-inch-diameter pipeline would be 

needed over a distance at least as long as that of the proposed Pipeline Expansion. As a result, 

similar environmental impacts would occur to those of the proposed Pipeline Expansion. 

Therefore, the Creole Trail Pipeline would not provide a significant environmental advantage to 

the proposed Pipeline Expansion and was not considered further as a system alternative. 

3.2.2.2 Trunkline Gas Pipeline

Trunkline has several pipelines at the existing Lake Charles LNG Terminal 

approximately 6 straight-line miles northeast of the Cameron LNG Terminal. The existing 

pipelines vary from 24 to 36 inches in diameter, and four additional pipelines are planned to 

transport gas from the Trunkline mainline north of the Lake Charles Terminal to the planned 

Lake Charles Liquefaction Project. To connect to the Cameron LNG Terminal, Trunkline must

install a new pipeline across the Gulf Intracoastal Waterway and the Calcasieu Ship Channel, 

potentially terminating at an interconnection with the existing Cameron Interstate Pipeline north 

of the Terminal Expansion. Assuming that the planned new and looped pipelines for the Lake 

Charles Liquefaction Project would be at or near capacity, to provide the required volume of gas 

for the Terminal Expansion, Trunkline would also have to loop about 60 miles of the existing 

pipelines and planned new pipelines. The total length of new and looped pipeline, including 

about 6 miles of pipeline from the Lake Charles Terminal to the Cameron Interstate Pipeline 

north of the Terminal Expansion site, would be about 65 miles. The looped and new pipelines 

would extend over a distance more than three times that of the proposed Pipeline Expansion and 

would have substantially more environmental impacts. In addition, the new pipeline from the 

Lake Charles Liquefaction Project to the Cameron Interstate Pipeline would extend through more 

developed areas than the proposed Pipeline Expansion. Therefore, use of the Trunkline pipeline 

at the Lake Charles LNG Terminal would not have significant environmental advantages to the 

proposed Pipeline Expansion and was not considered further as a system alternative. 
3-17 Alternatives

3.2.2.3 Gulf South Pipeline

The Gulf South Pipeline system includes approximately 7,360 miles of pipeline, with a 

capacity of approximately 6.9 Bcfd. The markets served by the Gulf South Pipeline are local 

distribution companies and municipalities, natural gas-fired power plants across the Gulf South 

System, industrial end-users, and Lake Charles, Louisiana, where it provides service for 

imported LNG. 

Given the supply sources and delivery points of the Gulf South System, it is not likely 

that the system could accommodate conversion to the bi-directional capability required to 

support the Terminal Expansion or provide the 2.35 Bcfd of natural gas required for operation of 

the expanded terminal. In addition, the nearest point on the system to the Terminal Expansion

site is the Lake Charles LNG Terminal, which would require at least 5 miles of greenfield 

pipeline to connect to the existing Cameron Interstate Pipeline north of the Terminal Expansion 

site, or longer to connect directly to the expanded terminal. In either case, the pipeline would 

extend through more developed areas than Cameron Interstate’s Pipeline Expansion and cross 

under the Gulf Intracoastal Waterway and the Calcasieu Ship Channel. In addition, providing 

the required volume of natural gas would likely require looping portions of the Gulf South 

System in the vicinity of the Lake Charles LNG Terminal, and perhaps portions of the mainline. 

We would not expect that a greenfield pipeline through developed areas and looped pipeline to 

provide a significant environmental advantage to the Pipeline Expansion. Therefore, that system 

alternative was not considered further.

3.3 ALTERNATIVE TERMINAL EXPANSION SITES

We evaluated the area in the vicinity of the existing Cameron LNG Terminal for 

alternative sites to the proposed Terminal Expansion site (section 3.3.1). Proximity to the 

existing terminal was a criterion in the evaluation to allow Cameron LNG to use the existing 

infrastructure, such as the LNG storage tanks, the LNG carrier berths and cargo 

loading/unloading facilities, and associated facilities. Use of those existing facilities would 

avoid the impacts of constructing and operating new facilities. Proximity to the existing 

Cameron LNG Terminal would also minimize the length of pipeline needed to transport LNG to 

the existing LNG storage tanks and associated facilities at the Terminal. 

In response to a comment on the draft EIS submitted by the Sierra Club (comment letter 

IP2 in Appendix L), we also evaluated upland sites to avoid impacts to wetland areas. That 

assessment is presented in section 3.3.2.

3.3.1 Sites in the Vicinity of the Existing Cameron LNG Terminal

Our evaluation of alternative sites considered construction and operation of the expanded 

terminal on two sites near the western and southern borders of the existing Cameron LNG 

Terminal: Terminal Expansion Alternative Site 1 (TEA-1) is directly west of the proposed site, 

on the western side of LA-27, and TEA-2 is directly south of and adjacent to the existing LNG 

terminal (see figure 3.3-1). TEA-1 has approximately the same area as the proposed Terminal 

Expansion site (about 500 acres). Although TEA-2 has less acreage, it would require 

construction of a work dock that would increase the area depicted on figure 3.3-1. In both cases, 
Alternatives 3-18

Figure 3.3-1 Alternative Terminal Expansion Sites
3-19 Alternatives
Alternatives 3-20

we assumed that the additional LNG storage tank would be constructed on the existing LNG 

terminal site as proposed. Our impact analysis focused on wetland impacts due to the high 

prevalence of wetlands in both areas and most other impacts being similar. Affected wetland 

areas for TEA-1 and TEA-2, based on NWI wetland information, are listed in table 3.3-1 along 

with wetland and open water information for the proposed Terminal Expansion site. 

TABLE 3.3-1

Wetlands and Open Areas Affected by Alternative Terminal Expansion Sites

Type

NWI Wetland and Open Space Areas (acres)

Proposed Terminal

Expansion Site

Terminal Expansion 

Alternative Site 1

Terminal Expansion 

Alternative Site 2

Freshwater Emergent 119.4 95.7 -

Estuarine Emergent - 169.0 130.7

Scrub/Shrub 69.8 - 49.6

Forested 24.5 - -

Fresh Open Water 70.1 44.3 -

Estuarine/Marine Open Water 9.4 152.8 157.7

Total 293.2 461.8 338.0

LA-27 extends roughly parallel to and is adjacent to the western border of the existing 

terminal. The area west of the highway consists of open water and marsh, including previously 

disturbed marsh, which also includes active oil and gas production. Use of the area west of the 

highway (TEA-1) would result in impacts on about 168.6 more acres of wetland, open water, and 

marsh areas than the proposed site (about 56 percent greater). In addition, the wetlands on the 

proposed site are generally of lower quality as most are on fill from dredge deposit, whereas 

incorporation of the liquefaction terminal at TEA-1 would affect higher quality wetlands. While 

some industrial facilities are within and surrounding TEA-1, these wetlands have not been 

disturbed to the degree of those at the proposed site. Additionally, the wetlands at TEA-1 are 

estuarine, whereas the wetlands at the proposed site are palustrine. Those impacts would result 

in greater impacts on the fish and wildlife using those areas. In addition, use of TEA-1 would 

likely result in impacts on existing oil and gas production activities. Development of the 

expanded terminal in that area would require longer cryogenic pipelines to the existing and new 

LNG storage tanks than those proposed. The alternate cryogenic pipelines would extend under 

the highway creating a new right-of-way and affecting the visual character of the area west of the 

highway (most industrial facilities are east of the highway). In addition, the visual impacts 

would be greater than those at the proposed site due to the presence of industrial structures and 

night lighting on both sides of the road. 

The area to the south (TEA-2 and the surrounding area) is also primarily open water, 

includes previously disturbed marsh, and includes areas of active oil and gas production 

facilities. Use of the southern area for the Terminal Expansion would affect about 44.8 more 

acres of wetlands, marsh, and open water than the proposed site (about 15 percent greater). As 
3-21 Alternatives

for TEA-1, the wetlands of TEA-2 are primarily high-quality wetlands, whereas the wetlands on 

the proposed Terminal Expansion site are of low quality. Impacts on the wetlands, marsh, and 

open water areas of TEA-2 would affect fish and wildlife using those habitats. Use of TEA-2 

would also result in impacts on existing oil and gas production activities and would require 

longer cryogenic pipelines to the existing and new LNG storage tanks than those at the proposed 

site. The visual impacts would be similar to those of the proposed Terminal Expansion. 

The proposed Terminal Expansion site, which is north of the existing Cameron LNG 

Terminal, is undeveloped land comprised of uplands and palustrine wetlands. Portions of the 

proposed area were previously disturbed by the disposal of dredged material from maintenance 

of the Calcasieu Ship Channel and by construction activities associated with the existing 

Cameron LNG Terminal. Of the approximately 502 acres required for the proposed Terminal 

Expansion, about 70 acres is within the existing terminal. As noted throughout section 4 of this 

EIS, the potential impacts associated with construction and operation of the expanded terminal 

on the parcel north of the existing terminal would have minimal impacts. We believe these 

impacts would be substantially less than the impacts on open water, marsh, fish, wildlife, and 

active oil and gas activities associated with development of either TEA-1 or TEA-2. In addition, 

siting the Terminal Expansion at TEA-1 would have greater visual impact than that of the 

proposed site. As a result, we determined that development of the Terminal Expansion on either 

TEA-1 or TEA-2 would not provide a significant environmental advantage to the proposed 

Terminal Expansion location. Therefore, these alternatives are not considered further. 

In response to a comment by the Sierra Club (comment letter IP2 in Appendix L), we 

also considered the effects of alternative methods of providing power to the two alternative sites 

identified above. Because the two sites are in close proximity to the proposed site of the 

Terminal Expansion, we believe that the assessment of alternative methods of providing power 

to the proposed Terminal Expansion site as discussed in section 3.4.2.1 (on-site power generation 

as compared to purchasing power from the electrical grid) is applicable to these two sites. As 

noted in section 3.4.2.1, emissions for an on-site power generation option would be concentrated 

at the Terminal Expansion site, which would be the case for on-site power generation at each of 

the alternative sites (TEA-1 and TEA-2). It is likely that the emissions for purchased power 

would not be from a single source because Entergy obtains electricity from more than one power 

generation facility. Therefore, it is not possible to determine the difference of the emissions 

between purchase power and on-site generation. However, emissions from the power plants 

providing electricity to the grid would also have to be in compliance with air permits. Because 

on-site power generation would not provide a significant environmental advantage at the 

alternative sites assessed above, it is not considered further.

3.3.2 Alternative Upland Sites

In response to a comment on the draft EIS submitted by the Sierra Club (comment letter 

IP2 in Appendix L), we also conducted an assessment of upland areas as potential alternative 

sites for the Terminal Expansion. The vast majority of the area near the proposed site of the 

Terminal Expansion is open water or wetland, and our assessment had to extend well beyond the 

area near the proposed site. However, for practicality, we limited our search for upland sites to 

the area within 15 miles of the proposed Terminal Expansion site. We note that we are not 

certain of the technological feasibility of such a long cryogenic pipeline. We identified a total of 
Alternatives 3-22

eight sites using imagery dating from 2011 and 2013 with the following criteria for an 

appropriate site:

• At least 500 acres in a shape that could contain the liquefaction facilities;

• No NWI wetlands;

• No visible structures inside or within 0.25 mile of the boundary for safety reasons;

• Not within an LDWF refuge (based on LDWF shapefiles);

• Not within a National Wildlife Refuge (based on FWS shapefiles);

• Not within a national park (based on National Park Service shapefiles); and 

• No existing roads bisecting the site (based on 2013 TIGER line census data).

We did not attempt to determine land ownership, the availability of the land for purchase, 

potential zoning restrictions, or other land use restrictions. The sites, which are depicted on 

figure 3.3-2, ranged from 5.2 straight-line miles from the nearest border of the proposed 

Terminal Expansion site to 13.3 straight-line miles from the nearest border of the proposed site. 

Three of the sites are generally northwest of the existing Cameron LNG Terminal and five are 

generally east of the Terminal. To reach the existing terminal, an LNG pipeline from a site to the 

northwest would have to cross the Gulf Intracoastal Waterway and an LNG pipeline from a site 

to the east would have to cross both the Gulf Intracoastal Waterway and the Calcasieu Ship 

Channel. Development of any of the alternative sites would result in impacts that would likely 

be similar to those of development of the proposed site of the Terminal Expansion, with the 

exception of wetlands. However, due to the disturbed nature of much of the proposed site and 

the relatively low quality of the habitats of the site, impacts at upland sites could be greater than 

the impacts of the Terminal Expansion identified in this EIS. In addition, a pipeline to the 

existing LNG Terminal would affect wetlands encountered along a route to the terminal. 

Although it is possible that the Gulf Intracoastal Waterway would be crossed using the HDD 

method, geotechnical studies would have to be conducted to determine the feasibility of the use 

of HDD at the selected crossing location. 

Of more critical importance are the requirements for the design of LNG facilities to 

provide minimal risk and to ensure the safety of the public. Cameron LNG would have to 

provide full containment of the entire LNG pipeline, establish an exclusion zone along the entire 

length of the pipeline, and meet other NFTA and industry standards. Meeting those requirements 

for a pipeline that would be from 5.2 to 13.3 straight-line miles from the facility miles would be 

difficult to impossible, depending on the degree of residential, commercial, and industrial 

development along the route, and the route would likely wind through many such developments, 

resulting in a much longer pipeline. In addition to adding substantial costs to the Project, 

construction and maintenance of the pipeline would result in environmental impacts, including 

wetland impacts. As a result of these considerations, we did not consider any of the identified 

upland sites as reasonable alternatives to the proposed Terminal Expansion site. Therefore, they 

are removed from further consideration.
3-23 Alternatives

Figure 3.3-2 Upland Alterative Sites
Alternatives 3-24

3.4 ALTERNATIVE TERMINAL CONFIGURATIONS AND DESIGNS

3.4.1 Alternative Configurations

Although alternative configurations of the Terminal Expansion were evaluated, design of 

the site was limited by the siting requirements of 49 CFR 193 and other industry or engineering 

standards. Regulatory requirements stipulate that potential thermal exclusion and vapor 

dispersion zones remain on-site; therefore, those requirements dictate the locations of specific 

pieces of equipment for the liquefaction facilities. Similarly, thermal radiation zones associated 

with flares require specific distances from other pieces of equipment and from property lines. 

The selected location of each of the components of the expanded terminal was based on the 

relevant regulations, codes, and guidelines. We did not find any alternative configurations that 

would meet the regulations, codes, and guidelines and at the same time avoid or reduce impacts 

in comparison to those of the proposed terminal configuration. 

3.4.2 Alternative Design

3.4.2.1 Power Source for the Terminal Expansion

Cameron LNG originally proposed to install and operate 10 gas turbine-driven 

generators, providing approximately 240-MW of on-site electric power while purchased power 

alternatives could be more fully explored and analyzed. Cameron LNG completed its evaluation 

and eliminated on-site power turbine generators (as suggested by the Sierra Club in its scoping 

comments) in favor of purchased power for the proposed Terminal Expansion, to be supplied by 

the new non-jurisdictional Entergy 12-mile-long, 230-kV double-circuit electric transmission 

line (see section 1.4 for additional details). As a part of this non-jurisdictional facility, the 

electric transmission line would connect to a new Entergy switchyard in the southwest region of 

the Terminal Expansion site. The use of on-site power generation is now considered a design 

alternative. However, Cameron LNG still proposes to install and operate three 1.5-MW, dieselfueled stand-by generators for emergency backup power for the Terminal Expansion. 

During construction of the Entergy transmission line and switchyard, emissions, fugitive 

dust, and noise would temporarily increase due to the use of construction equipment and land 

disturbance. These increases would be temporary, end after construction is completed, and be 

similar to those that result from construction of the alternative of 10 gas-fired turbine generation 

units on the Terminal Expansion site, but occurring over a more expansive area. During 

operation, emissions and noise levels of the turbine generators would be greater than those of 

purchased power in the vicinity of the Terminal Expansion site. Table 3.4.2-1 presents a 

comparison of emissions, and table 3.4.2-2 presents a comparison of noise levels during 

operation. Air dispersion modeling results also indicate lower emissions for purchased power, 

with the exception of modeling for carbon dioxide (CO) for the 1-hour standard. For both 

options, dispersion modeling results show no exceedances of Significant Impact Levels (SILs) 

with the exception of nitrogen dioxide (NO2), which showed no contribution of exceedance of 

National Ambient Air Quality Standards (NAAQS) in refined analyses.

Emissions for the on-site power generation option would be concentrated at the Terminal 

Expansion site, whereas it is likely that the emissions for purchased power would not be from a 

single source because Entergy obtains electricity from more than one power generation facility. 
3-25 Alternatives

Therefore, it is not possible to determine the difference of the emission between the two design 

options. Because on-site power generation would not provide a significant environmental 

advantage, it is not considered further.

TABLE 3.4.2-1

Estimated Emissions for Alternative Power Sources

During Operation of the Terminal Expansion

Option

Pollutant Emissions a

Tons per year (tpy) Million 

tpy

NOx CO SO2 PM10 VOCb HAPs GHG

On-site Power Generation 3,532 1,620 17 215 83 35 5

Purchased Power 2,333 891 9 133 98 22 3

a

 Does not include indirect emissions from the power plant used to supply electricity. Rounded to nearest whole 

numbers.

b Fugitive emissions were not reported for on-site power generation, and the increase in VOCs is a result of 

fugitive emissions. Without fugitive emissions, VOCs would be 61 tons per year.

TABLE 3.4.2-2

Estimated Noise Levels for Alternative Power Sources 

During Operation of the Terminal Expansion

Option Ldn Background Noise 

Level (dBA)

Ldn with Terminal 

Expansion (dBA)

Expected Increase 

(dBA)

On-site Power 

Generation 50.9 54.2 3.3

Purchased Power 50.9 53.8 2.9

Ldn = Day-night sound level

dBa = A-weighted decibel scale

3.4.2.2 Power Source for Liquefaction Units

In response to a comment by the Sierra Club (comment letter IP2 in Appendix L), we 

also considered the effects of alternative methods of providing power to the liquefaction units of 

the proposed Project. Specifically, the commenter recommended that FERC consider “the use of 

electric motors instead of mechanical-driven gas turbines in the liquefaction process.” We 

believe that the assessment of alternative methods of providing power to the proposed Terminal 

Expansion site as discussed in section 3.4.2.1 is applicable to this potential alternative as well. 

As noted in section 3.4.2.1, the emissions for the proposed on-site power source for the 

liquefaction units would be concentrated at the site, but would be in compliance with the 

requirements of the Title V and PSD permits recently issued to Cameron LNG for the proposed 
Alternatives 3-26

Project. We anticipate that the purchased power alternative would be from a new Entergy 

transmission line, as proposed for the Project, and it is likely that the emissions for purchased 

power would not be from a single source because Entergy obtains electricity from more than one 

power generation facility. Therefore, it is not possible to determine the difference of the 

emissions between the two design options. However, emissions from the power plants providing 

electricity to the grid would also have to be in compliance with air permits. Because the use of 

purchased power to operate the liquefaction units would not provide a significant environmental 

advantage, it is not considered further.

3.5 ALTERNATIVE PIPELINE ROUTES

Cameron Interstate’s proposed pipeline route is collocated or parallel to existing rightsof-way for its entire length. To limit environmental impacts, the Pipeline Expansion would 

overlap existing rights-of-way to the greatest extent practical (about 74 percent of the route). We 

did not identify any environmental concerns that require the need to identify and evaluate 

alternative pipeline routes to minimize impacts, nor were any alternatives suggested during the 

public scoping period. 

3.6 ALTERNATIVE PIPELINE EXPANSION ABOVEGROUND FACILITY SITES

We evaluated alternative sites for the proposed compressor station and also considered 

the need to evaluate potential alternative sites for the other aboveground facilities associated with 

the Pipeline Expansion. Our assessments considered information obtained from inspection of 

maps and aerial photography and from observations during site visits along the proposed route. 

3.6.1 Compressor Station Site Alternatives 

Cameron Interstate considered five 25-acre sites for construction and operation of the 

compressor station, initially considering the availability of land to purchase along with the 

horsepower requirements of each alternative. Specifically, the location of the compressor station 

along the pipeline route dictates how much horsepower Cameron Interstate would require to 

transport natural gas into the existing Cameron Interstate pipeline which would deliver the gas to 

the Terminal Expansion.

In our evaluation of alternative compressor station sites, we considered the following:

• land availability for purchase, including the landowners’ interest in selling the 

property for use as a compressor station;

• emissions based on required horsepower;

• site access;

• length of required electrical distribution lines; and 

• potential impacts on prime farmland, agricultural land, forested land, wetlands, 

floodplains, and noise sensitive areas (NSAs).

Using these key factors, we initially determined that the four alternative sites identified 

by Cameron Interstate provided a satisfactory range of options and compared each of those sites 
3-27 Alternatives

to the proposed site. Each alternative site is about 25 acres in size; the locations are as depicted 

in figure 3.6-1 and briefly described below. 

Table 3.6.1-1 provides comparisons of the key evaluation factors considered: 

• The proposed site at MP 8.4 is on the north side of Holbrook Park Road and is 

adjacent to the proposed pipeline route. Cameron Interstate would access this site by 

constructing a 1,500-foot-long access road to the site from Holbrook Park Road

(adjacent to the proposed pipeline route).

• Compressor Station Alternative (CSA) 1 is at MP 2.6, on the east side of the proposed 

pipeline route. Cameron Interstate would access this site from an existing gravel road 

that extends along the southern boundary of the site. 

• CSA-2 is at MP 3.9, on the north side of the proposed pipeline route. Cameron 

Interstate would access this site from a gravel road that extends along the southern 

boundary of the site. 

• CSA-3 is at MP 7.6, on the south side of Holbrook Park Road and adjacent to the 

proposed pipeline route. Cameron Interstate would access this site from Holbrook 

Park Road.

• CSA-4 is at MP 17.1 on land directly adjacent to and south of the existing Ragley 

Compressor Station. The site is south of the proposed pipeline route, and Cameron 

Interstate would access the site from an area adjacent to the Ragley Compressor 

Station. 

Through consultation with the landowners, Cameron Interstate determined it would be 

unable to acquire the land for two of the alternative sites. The landowner of CSA-2 denied 

Cameron Interstate access to the site for surveying, and Cameron Interstate reported that it could 

not negotiate acceptable purchase terms of the property. In addition, Cameron Interstate could 

not negotiate acceptable purchase terms with the landowner of CSA-3. Because the lands for 

CSA-2 and CSA-3 are not available to Cameron Interstate for purchase, they are not considered 

practical alternatives, and were eliminated from further consideration. The following 

summarizes the key environmental comparisons among the remaining three sites – proposed site, 

CSA-1, and CSA-4 – based on the information presented in table 3.6.1-1. 
Alternatives 3-28

Figure 3.6-1 Alternative Compressor Station Sites
3-29 Alternatives

TABLE 3.6.1-1

Evaluation Factors Considered for Alternative Compressor Station Sites

Evaluation Factor Proposed 

Site CSA-1 CSA-2 CSA-3 CSA-4

Approximate MP 8.4 2.6 3.9 7.6 17.1

Site Parcel (acres) 25 25 25 25 25

Land Use Area (acres) a

Forested 16 20 20 23 -

Prime Farmland 15 15 23 19 25

Agriculture/Crop 

Land/Pasture - - - - 25.0

Waterbodies No No No Yes No

 Wetlands (acres) 5 10 8 5 12

Floodplain

About 28% 

of site 

within 100-

year 

floodplain

Entire site within 

100-year 

floodplain

Entire site within 

500-year 

floodplain

None None

Land Availability Yes Yes No No Yes

Site Access b Holbrook 

Park Road Gravel Road Gravel Road

Holbrook 

Park 

Road

Ragley CS 

Road

NSAs

Distance to Nearest NSA 

(feet) 3,200 3,300 4,200 7,200 1,430

Number NSAs within 1-Mile 

Radius 2 18 14 0 18

Total Horsepower Required 56,280 56,820 52,085 56,280 52,085

Relative Horsepower Required c 100% 101% 92% 100% 92%

Distance to Electric Service 

(miles) 3.5 1.2 1.4 3.5 Present at Site

a

 For the purposes of this analysis, it was assumed that the entire site area would be used for construction and 

operation and that there would not be any difference between temporary and permanent impact acreages.

b Cameron Interstate would construct a 1,500-foot-long road adjacent to its right-of-way from Holbrook Park 

Road to its compressor station.

c Horsepower requirements relative to that required for the proposed site. For example, CSA-4 would require 

approximately 92% of the horsepower required for the proposed site.

Emissions: CSA-1 and the proposed site would require the most horsepower and would 

therefore have more total emissions over the life of the Project than CSA-4. However, Cameron 

Interstate would be required to meet regulatory requirements for emissions at any site selected 

and the difference in emissions among the alternatives is not considered significant. 
Alternatives 3-30

Access road construction: The proposed site would require construction of 1,500 feet of 

new access road, whereas CSA-1 and CSA-4 would require short driveways from existing roads. 

However, Cameron Interstate would construct the access road adjacent to the proposed pipeline 

route to reduce impacts, such as habitat fragmentation and impacts on visual resources.

Construction of electrical distribution line: electrical power is present at the existing 

Ragley Compressor Station, thus CSA-4 would not require construction of a new electrical 

distribution line. CSA-1 would require about 1.2 miles of new electrical distribution line, which 

is about one-third less than the distance required for the proposed site. The impacts of 

construction and operation of either electrical distribution line would be along existing corridors 

and we believe these impacts would be minor (primarily limited to the placement of poles).

Prime farmland: The proposed site and CSA-1 would affect the same amount of prime 

farmland, both of which are about 10 acres less than CSA-4. 

Agricultural land: The proposed site and CSA-1 would not affect agricultural land, 

whereas CSA-4 would affect 25 acres of agricultural land.

Forested land: CSA-1 would affect the most amount of forest land, about 4 acres more 

than the proposed site. CSA-4 would not affect forest land. The forest land affected by the

proposed site is pine plantation. 

Wetlands: CSA-4 would affect the most wetlands, about 2 acres more than CSA-1 and 7 

acres more than the proposed site, although the wetlands at CSA-4 are within agricultural land 

and are not high-quality wetlands. The proposed site would avoid high-quality palustrine 

forested (PFO) wetlands along the Little River. 

Floodplains: CSA-1 is entirely within the 100-year floodplain and CSA-4 is outside of 

any floodplains. About 28 percent of the proposed site is within the 100-year floodplain; 

however, we concluded that there would not be an increase in flooding due to implementation of 

the Project (see section 4.1 of this EIS). 

NSAs: both CSA-1 and CSA-4 have 18 NSAs within 1 mile of the sites, which are 14 

more NSAs than for the proposed site. 

Although the potential impacts associated with emissions, access road construction, and 

construction of an electrical distribution lines would be greater at the proposed Holbrook 

Compressor Station site, we believe those differences would be minor. Although CSA-4 is not 

within a floodplain, we determined that site would be the least preferable due to higher potential 

impacts on prime farmland, agricultural land, NSAs, and wetlands. The impacts of the proposed 

site and CSA-1 on prime farmland and agricultural land would be similar; however, the proposed 

site would have less impact on forest land, wetlands, and NSAs. In addition, CSA-1 is entirely 

within a floodplain area. Therefore, we believe that none of the alternatives provide a significant 

environmental advantage and the proposed site is environmentally acceptable. 

In response to the Sierra Club comment letter to the draft EIS (comment letter IP2 in 

Appendix L), we also considered the effects of using electric motors instead of mechanicaldriven gas turbines for the Holbrook Compressor Station alternatives. We believe that the 

assessment of alternative methods of providing power to the proposed Holbrook Compressor 
3-31 Alternatives

Station site, as discussed in section 3.7.1, is applicable to this potential alternative as well. While 

the emissions for the on-site compressor units would be concentrated at the site, they must still 

be in compliance with the requirements of Title V and PSD permits. We anticipate that the 

purchased power alternative would be from a new Beauregard Electric transmission line, as 

proposed for the Project, and it is likely that the emissions would be from the Big Cajun II Power 

Plant. Emissions from the power plant providing electricity to the grid would also have to be in 

compliance with air permits. Because the use of purchased power to operate the Holbrook 

Compressor Station site alternatives would not provide a significant environmental advantage, it 

is not considered further.

3.6.2 Other Aboveground Facilities

Other aboveground facilities associated with the Pipeline Expansion include two pig 

receivers, two pig launchers, one new interconnection at Trunkline, new interconnections and 

metering ancillary facilities at the four existing interconnections, and new metering at the 

existing Cameron LNG Terminal. Cameron Interstate proposed to construct these aboveground 

facilities either within existing pipeline rights-of-way or within a developed portion of the 

existing Cameron LNG Terminal. The areas proposed for these facilities were previously 

disturbed and are maintained as industrial areas. As noted throughout section 4.0, the potential 

impacts of construction and operation of the Pipeline Expansion would be minimal, and we do 

not believe that there are alternative sites that would provide a significant environmental 

advantage to the proposed aboveground facility sites. 

3.7 ALTERNATIVE COMPRESSOR STATION DESIGN

3.7.1 Use of Electric-Powered Compressors and Purchased Power

Cameron Interstate explored the use of electric-powered compressors and purchased 

power as an alternative to the proposed natural gas-fired compressors as requested by the Sierra 

Club in its scoping comments. Cameron Interstate stated that to achieve the same deliverable 

flow rate as the proposed 12 natural gas-fired compressors (56,820 horsepower), this design 

option would require 70,000 horsepower and nine generation units.

23 These nine units would 

require approximately 52-MW of electricity to operate. Cameron Interstate also reported that to 

provide the required 52-MW of electricity, the local electric provider, Beauregard Electric CoOp, would have to install approximately 3.5 miles of additional 230-kV electric distribution lines

from a tie-in on LA-27 to the proposed Holbrook Compressor Station site. That would require 

clearing a new right-of-way adjacent to the proposed Cameron Interstate pipeline right-of-way 

from LA-27 to the Holbrook Compressor Station site. In addition to the new electric distribution 

line, a new switchyard would be required in or near the Holbrook Compressor Station site. 

Cameron Interstate also stated that using electric-driven units versus reciprocating gasdriven units would increase the cost of operating the compressor station by more than $7 million

per year, or approximately 60 percent greater based on current market rates for electric power.

This cost differential would result in a higher service rate to be passed along to the customers. In 

addition, Cameron Interstate noted that the reciprocating drivers proposed for the Holbrook 

Compressor Station would provide the highest level of service possible and were designed to 

 23 Docket No. CP13-27, Accession No. 20130423-5004(28332904).
Alternatives 3-32

meet the customer’s gas flow requirements. Electric drivers are not variable speed controlled

and would not provide the flexibility and quality of service required for the station. 

Cameron Intestate reported that Beauregard Electric purchases power from the Big Cajun 

II Power Plant, a local coal-fired power plant. Cameron Interstate provided emission data 

associated with the increased power generation from the Big Cajun II Power Plant that would be 

required to operate the Holbrook Compressor Station and determined that those emissions would 

be greater than the emissions from the proposed 12 natural gas-fired compressors for all but one 

constituent: VOCs would be substantially greater using the natural gas-fired compressor option. 

Table 3.7-1 presents a comparison of the emissions for the power options for the 

Holbrook Compressor Station. 

TABLE 3.7-1

Comparison of Emissions from Compressor Power Sources During 

Holbrook Compressor Station Operations

Estimated Emissions (tpy)

Constituent Big Cajun II Power Plant a Natural Gas-Fired Compressors

NOx 536 384.3

CO 1,420 20.7

PM10 247 0.3

SO2 2,975 1.2

VOC 9.3 199.9

PM10 = Particulate matter with an aerodynamic diameter less than or equal to 10 microns

SO2 = Sulfur dioxide

VOC = Volatile organic compound

a Increase in emission due to providing power to the Holbrook Compressor Station.

Based on our review of the Project area maps, it is likely that the 3.5-mile-long 

transmission line would require minimal tree clearing, maintenance, and additional right-of-way. 

Based on emissions data from the power options, the use of purchased power for operating the 

Holbrook Compressor Station does not appear to offer a significant environmental advantage 

over the proposed natural gas-fired compressors. Therefore, we have removed this alternative 

from further consideration.

3.7.2 Other Design Options

Based on Sierra Club scoping comments, we requested that Cameron Interstate explore 

design options for the Holbrook Compressor Station, including use of fewer, larger, more 

efficient turbines; selective catalytic reduction (SCR) to reduce nitrogen oxide emissions; and an 

oxidation catalyst to reduce monoxide emissions. Cameron Interstate indicated that it had 

examined the use of larger turbine driven compressors as an alternative to the proposed design of 
3-33 Alternatives

the Holbrook Compressor Station.

24 To achieve comparable horsepower requirements with the 

proposed reciprocating drivers, Cameron Interstate would install eight turbine-driven 

compressors which would decrease the flexibility and reliability of Cameron Interstate’s service. 

The turbines would not have variable speed control like the reciprocating drivers, further 

reducing the flexibility and quality of service provided. Cameron Interstate further stated that 

the larger turbine driven machines would also require more than 35 percent more fuel, resulting 

in more than $4 million dollars in additional annual fuel expense. As a result, we do not believe 

there is a significant advantage to the use of larger gas-fired turbines to generate power at the 

Holbrook Compressor Station. 

Cameron Interstate consulted with LDEQ regarding its air permit application, including 

development of a methodology for determining the best available control technology (BACT) for 

the compressors. In this BACT analysis, SCR and use of an oxidation catalyst were considered 

as pollution control methods. However, the BACT analysis concluded that SCR and use of an 

oxidation catalyst were not feasible pollution control options due to economic, environmental, 

and energy impacts. As these alternative designs would not have a significant environmental 

advantage, we have removed them from further consideration.

 24 Docket No. CP13-27, Accession No. 20130423-5004(28332904).