3-1 3.0 – Alternatives

3.0 ALTERNATIVES

In accordance with NEPA and FERC policy, we have evaluated a range of alternatives to the 

Downeast LNG Project, as well as alternatives for design and construction of the project. The 

purpose of this evaluation was to determine whether or not there are reasonable alternatives that 

would result in less environmental impact than the project as proposed. The proposed action 

before the FERC is to consider issuing to Downeast a Section 3 authorization for an LNG import 

facility and a Section 7 Certificate for a new natural gas pipeline.

The Commission has three possible courses of action in processing an application for a project 

such as that proposed by Downeast. The Commission may: (1) authorize the proposal with or 

without conditions; (2) deny the proposal; or (3) postpone action pending further study. 

Alternatives for the FERC action that are addressed in this section include the no action or 

postponed action alternatives, alternative energy sources, system alternatives, alternative LNG 

terminal concepts and sites, onshore facility alternatives, alternative pipeline routes, pipeline 

route variations, and alternative LNG vaporization methods. We identified potential alternatives 

based on public comments and input from federal, state, and local regulatory agencies, and our 

own independent research.

Alternatives were evaluated against the stated purpose and need of the project, as described in 

section 1.1 of this EIS. The purpose of the project is to establish an LNG marine terminal at an 

acceptable port location in New England capable of receiving imported LNG from LNG vessels, 

and storing and regasifying the LNG at an average sendout rate of 500 MMcfd. The terminal 

would provide an additional supply source of natural gas to meet increasing demand in the New

England region.

We established several key criteria to evaluate the potential alternatives identified. Each 

alternative was evaluated in consideration of whether or not it would: 

• be technically and economically feasible and practical;

• offer significant environmental advantage over the proposed project or its components; 

and

• meet the objectives of the proposed project, as described above.

With respect to the first criterion, it is important to recognize that not all conceivable alternatives 

are technically and economically feasible and practical. For example, some alternatives may not 

be feasible because the technology may not be available at the time or it may not be possible to 

implement the alternative due to costs, technological difficulties, or logistics. It is also important 

to consider the environmental advantages and disadvantages of the proposed action and to focus 

the analysis on alternatives that may reduce impacts. Further, because the total proposed LNG 

project would consist of individual components (such as the LNG terminal and the sendout 

pipeline), all of these components must be present and must function together for the alternative 

to be considered feasible.

Information used to evaluate alternatives to the proposed project included published studies, 

comments and suggestions from regulatory agencies, analyses prepared for similar projects, 

comments from the public, and data and analyses provided by Downeast in its application.
3.0 – Alternatives 3-2

Each alternative was considered until it was clear that the alternative was not reasonable or that 

the alternative would result in environmental impacts that would be greater than those of the 

proposed project, as described in section 4.0 of this EIS, and that could not be readily mitigated. 

This assessment includes the consideration of using existing or proposed LNG projects and siting 

the project in a different area.

The evaluation of alternatives is presented in the following sections:

• No Action or Postponed Action Alternatives (section 3.1)

• Alternative Energy Sources (section 3.2)

• System Alternatives (section 3.3)

• LNG Terminal Site Alternatives (section 3.4)

• Marine Facility Alternatives (section 3.5)

• LNG Vaporization Alternatives (section 3.6)

• LNG Vessel Design Alternatives (section 3.7)

• Pipeline Location Alternatives (section 3.8)

A regional siting plan has been advocated as a more desirable approach to siting LNG facilities. 

If a regional siting study is completed during our assessment of the proposed Downeast LNG 

Project, the Commission may take the conclusions into consideration. However, to date, the 

Commission has declined to substitute its judgment for that of the market. The Commission’s 

policy prohibiting subsidization of new construction by existing customers works to ensure that 

an authorized project would not be constructed without adequate support from the market. 

Further, the Commission policy of authorizing only those projects where adverse impacts have 

been minimized to the extent possible and potential benefits outweigh any residual impacts,

serves to adequately protect the public interest when any authorized project is constructed. 

Furthermore, Section 313 of the Energy Policy Act of 2005 directs FERC to establish a schedule 

for the regulatory review that ensures “expeditious completion” of NGA Section 3 and 7 

proceedings. Our NEPA scoping process has provided input from the public and regionally 

based federal, state, and local agencies. This input has been fully considered in the following 

alternatives. In addition, as part of the planning process for its proposed project, Downeast 

conducted a siting study that included coastal regions of northern New England, and we have 

incorporated the results of that study into this EIS. Ultimately, FERC will continue to seek better 

ways to balance national, regional, state, and local concerns in reviewing LNG import facilities.

3.1 NO ACTION OR POSTPONED ACTION ALTERNATIVE

As stated in section 1.1, the proposed project would establish an LNG marine terminal in New 

England capable of receiving imported LNG from LNG vessels, storing, and regasifying the 

LNG at an average sendout rate of 500 MMcfd. The terminal would provide an additional 

supply source of natural gas in the New England region (Maine, Massachusetts, New Hampshire, 

Vermont, Connecticut, and Rhode Island). The proposed storage tanks at the LNG facility 

would provide an additional 6.6 Bcf of gas storage capacity in the region. If the Commission 

denies the proposal (the no action alternative), the short- and long-term environmental impacts 

identified in this EIS would not occur. If the Commission postpones action on the application, 

the environmental impacts would be delayed; or if the applicant decided not to pursue the 

project, the impacts would not occur at all. However, if the Commission selects the no action 
3-3 3.0 – Alternatives

alternative, Downeast would not be able to provide additional natural gas supplies in order to

help meet the increasing natural gas demand in the New England region.

It is purely speculative to predict the resulting effects and actions that could be taken by other 

suppliers or users of natural gas in the region as well as any associated direct and indirect 

environmental impacts. However, LNG imports to the New England region are projected to 

continue through 2035 (EIA 2012). Downeast has stated that natural gas consumers in New 

England face a future of high natural gas prices and increased risk of supply disruption unless 

additional sources of natural gas, such as the proposed project, become available. 

No Action or Postponed Action Conclusions 

In addition to the objectives of the proposed project not being met as noted above, if the no 

action or postponed action alternative is adopted by the Commission, there are two likely 

outcomes: (1) negative environmental (i.e., increased air emissions and disposal of spent fuel and 

ash) and economic impacts associated with more limited supplies of natural gas; and/or (2) the 

development of other natural gas infrastructure projects (i.e., construction of additional pipelines 

and LNG import terminals) that meet some or all of the project objectives identified by 

Downeast. For these reasons, we believe that the no action or postponed action alternative is not 

a reasonable alternative.

3.2 ALTERNATIVE ENERGY SOURCES

The adoption of the no action alternative may result in the need for alternative energy sources, or 

other LNG facilities or additional pipeline capacity to meet the increasing demand for natural gas 

in New England. This might include constructing or expanding regional pipelines as well as 

LNG import and storage systems. Any construction or expansion work would result in specific 

environmental impacts that could be less than, similar to, or greater than those associated with 

the Downeast LNG Project. We have conducted and included in this EIS an analysis of what 

appears to be the most reasonable natural gas and LNG system alternatives that have the 

potential to meet the project objectives.

Conservation, Efficiency, and Renewable Sources of Energy 

Conservation, increased efficiency, and renewable energy practices have been, and will continue 

to be, important in meeting the future energy needs of New England. Beginning with the energy 

crisis of the 1970s, numerous aggressive energy conservation programs have been developed in 

the region. Although energy conservation measures will be important in addressing future 

energy demands for the region, these measures would reduce energy demand by only a small 

fraction and would not replace the need for the project.

Numerous renewable energy incentives have been implemented in the New England region, 

including solar income tax credits, solar access laws, solar rebate programs, property tax 

exemptions for geothermal heat pumps, net metering, green power marketing, greenhouse gas 

initiatives, and energy efficiency and renewable portfolio standards. Renewable energy sources, 

including wind, hydropower, tidal power, municipal solid wastes, wood and other biomass, and 

solar power are projected to have some role in meeting New England’s future energy needs. The 

renewable share of total energy use is projected to grow from 9 percent in 2011 to 13 percent in 

2040, while natural gas consumption is projected to grow by about 0.6 percent per year from 
3.0 – Alternatives 3-4

2011 to 2040 (EIA 2013). Therefore, while renewable energies such as hydroelectric, wind, or 

solar, are projected to increase, they will not replace the demand for natural gas. 

A 2003 report by the American Council for an Energy-Efficient Economy (ACEEE) analyzed 

projected energy demands in the Northeast. The ACEEE reviewed the national and regional 

relationship between natural gas price effects of energy efficiency and renewable energy 

practices and policies (Elliott et al. 2003). The report found that increased installation of 

renewable energy generation could affect natural gas price and availability. The report 

concluded that energy efficiency and renewable energy measures could result in a reduction in 

natural gas consumption in the northeastern states. However, the study also recognized that 

energy efficiency and renewable energy are not the only policy solutions required to address the 

future natural gas needs of the United States and that additional sources of natural gas will be 

required either from domestic sources or through the importation of gas in the form of LNG. 

The EIA projects that natural gas consumption will grow by about 0.6 percent per year through

2040 (EIA 2013). Furthermore, renewable sources of energy would have project- and sitespecific environmental issues such as the disposal of toxic materials, alterations to 

hydrological/biological systems, and visual impacts. Alternative energy sources could reduce 

some of the environmental impacts associated with the proposed project but could not 

individually or cumulatively meet the future energy needs of the New England region.

We received comments during the scoping period regarding impact of the proposed project on 

in-stream tidal power projects in the Eastport/Lubec area. Potential impact on these renewable 

energy projects is addressed in section 4.7.3.1 Land Use.

Nuclear Power Energy 

Energy from nuclear power is expected to grow at an annual rate of 0.5 percent in the United 

States and 1.6 percent in New England over the next 20 years. However, while important to the 

overall energy mix, nuclear power is projected to be only 8 percent of total energy consumption 

in the United States and 15 percent of total energy consumption in New England in 2030, 

compared to natural gas, which is projected to be 22 percent of total energy consumption in both 

the United States and New England in 2030. The EIA concludes that nuclear power energy is 

not a commercially viable substitute able to replace or significantly offset the demand for natural

gas over the next 20 years (EIA 2009). Furthermore, nuclear power energy involves significant 

environmental issues such as the disposal of toxic materials (spent fuel), alterations to 

hydrological/biological systems, and other concerns. 

Energy from Other Fossil Fuels 

EIA projects that coal consumption will increase at an average rate of less than 0.1 percent per 

year and petroleum consumption will fall slightly through 2035 (EIA 2012), while natural gas 

consumption will increase by about 0.6 percent annually (EIA 2013). Further, 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 nitrogen oxides (NOx), sulfur 

dioxide (SO2), mercury, and greenhouse gases (EIA 2009). Given there are emissions associated 

with producing, processing, transmitting, and distributing natural gas and other fossil fuels, it is 

difficult to accurately quantify the impact of an LNG import project on air quality. However, 

credible estimates of air emissions can be developed based on reasonable assumptions regarding 
3-5 3.0 – Alternatives

burning natural gas delivered by the project compared to burning fossil fuels that would likely be 

utilized if the gas from the project was not available. Table 3.2-1 lists the emissions that would 

result from the Downeast LNG Project assuming it provides a baseload rate of about 0.5 Bcfd of 

natural gas to the market and the corresponding emissions that would result if an equivalent 

amount of energy were generated using coal or fuel oil in lieu of natural gas. It is clear from the 

table that the use of either fuel oil or coal would increase emissions significantly. Additionally, 

to comply with current air emission regulations, emission control technologies could be required 

that could limit the economic viability of any new oil- or coal-fired facility.

TABLE 3.2-1

Comparison of Air Emissions from Burning Fossil Fuels a/

Fossil Fuel SO2 (tpy) NOx (tpy) PM10 (tpy) CO2 (tpy) C (tpy)

Natural Gas 55 8,277 662 9,166,666 2,500,000

Fuel Oil 43,320 16,556 938 13,291,666 3,625,000

Coal 115,890 57,946 2,566 17,416,666 4,750,000

a/ The emissions generated by coal, fuel oil, and natural gas were estimated using Best Available Control Technology (BACT) 

analyses identified on the EPA Reasonably Available Control Technology/BACT/Lowest Achievable Emission Rate 

Clearinghouse for boilers with heat input ratings between 100 and 250 million Btus per hour. The emissions from each fuel 

source are estimated based on a total annual fuel use of 182,500,000 million Btus per year (0.5 billion cubic feet per day, 

365 days per year, 1,000 Btus/cubic foot).

SO2=sulfur dioxide NOX=nitrogen oxides PM10=particulate matter CO2=carbon dioxide C=carbon tpy=tons per year

In addition to the increased emissions associated with the burning of coal or fuel oil, each of 

these fuels would also have to be imported into the project area and stored, similar to the 

proposed LNG. Use of these fuels would require more truck, barge, and train trips than the 

distribution of an equivalent amount of energy derived from natural gas distributed by pipeline, 

which would increase air emissions and traffic congestion. The burning of coal would also 

require disposal of the resulting ash. 

As the demand for natural gas is expected to continue to increase into the future, it is conceivable 

that this demand could be moderated by the increasing use of other energy sources and/or 

conservation measures. Because natural gas is the least polluting of the fossil fuels, the 

increased use of other fossil fuels would result in higher air emissions that can contribute to 

climate change, acid rain, and smog. The economic, ecological, and human health benefits of 

reduced air emissions have been well documented. It is also conceivable that increasing energy 

efficiency and use of renewable sources of energy could reduce the projected future demand for 

natural gas.

EIA (2008) studies have demonstrated that natural gas consumption in New England increased 

0.1 percent between 2003 and 2008, and natural gas consumption in the United States is 

expected to increase 0.6 percent annually through 2040. We cannot accurately predict whether

conservation measures or renewable energy sources would replace or significantly offset 

potential future demand for natural gas supplies in New England. Therefore, we believe that use 

of alternative energy sources is not a reasonable alternative to the proposed action.
3.0 – Alternatives 3-6

3.3 SYSTEM ALTERNATIVES

System alternatives would make use of other existing or proposed facilities in the region to meet 

the stated purpose of the proposed project, including LNG terminals, natural gas pipeline 

systems, and offshore natural gas development. A system alternative would make it unnecessary 

to construct all or part of the proposed project, although some modifications or additions to the 

system alternative facilities may be necessary. The purpose of identifying and evaluating system 

alternatives is to determine whether or not potential environmental impacts associated with 

construction and operation of the proposed facilities could be avoided or reduced while still 

meeting the project objectives.

3.3.1 Pipeline System Alternatives

As an alternative to constructing a new LNG import terminal, we considered the feasibility of 

using or expanding existing interstate pipeline transmission systems to provide an equivalent 

amount of natural gas to the New England region as that proposed by Downeast. Existing 

interstate pipeline systems with major delivery points in New England that could potentially 

serve as system alternatives include those owned and operated by M&NE, Portland Natural Gas 

Transmission System (PNGTS), Algonquin, and Tennessee Gas (see figure 3.3-1).

M&NE Pipeline System

The M&NE pipeline system in the United States consists of about 215 miles of 24-inch-diameter 

pipeline from the Canadian border near Calais, Maine, to Westbrook, Maine; about 101 miles of 

30-inch-diameter pipeline jointly owned with PNGTS between Westbrook and Dracut, 

Massachusetts; and about 24 miles of 30-inch-diameter pipeline from Methuen to Beverly, 

Massachusetts. The M&NE system interconnects with PNGTS in Westbrook, Maine; with the 

Tennessee Gas system in Dracut, Massachusetts; and the Algonquin system in Beverly, 

Massachusetts. The M&NE system receives and transports natural gas from developments in 

offshore Nova Scotia. Capacity of the United States portion of the M&NE pipeline is about 

0.42 Bcfd. On February 15, 2007, the Commission authorized M&NE’s Phase IV Project which 

will increase the M&NE system capacity to 0.83 Bcfd. The Phase IV Project delivers natural gas 

capacity from the Canaport LNG Project, which is currently in operation in eastern Canada. 

Construction of the M&NE Phase IV Project was completed and the facilities placed into service 

in January 2009. A discussion of the Canaport LNG Project as a potential system alternative is 

included in section 3.3.2.1. On April 16, 2008, we approved M&NE’s request to initiate prefiling for the M&NE Phase V Project (PF08-17-000), which would increase capacity on its 

system by up to 0.17 Bcfd year-round, plus an additional 0.03 Bcfd capacity during the winter 

months. The project would provide additional capacity to transport new natural gas supplies 

from EnCana’s Deep Panuke gas field project in Maritimes Canada (see section 3.3.3). 

However, on March 2, 2009, M&NE informed the FERC that it will not be proceeding with the 

Phase V Project. It was resolved that the Phase V shipper would not need the proposed M&NE 

facilities to transport its production to markets in the U.S. Northeast.
3-7

Figure 3.3-1 

Downeast LNG Project 

Existing Interstate Pipeline Systems 

Considered as Potential System Alternatives 
3.0 – Alternatives 3-8

The M&NE pipeline is the pipeline that Downeast anticipates would transport the additional 

0.5 Bcfd of natural gas from the proposed Downeast LNG terminal to existing interconnections 

in the New England market. As an alternative to the proposed Downeast LNG Project, the 

M&NE pipeline could be used to transport natural gas received from other source(s) to the New 

England market. Depending on the source and volume of natural gas, construction of additional 

gas facilities may be necessary to provide or transport the additional gas. Since the source and 

volume are not known, it is not possible to evaluate this as an alternative, or if it would provide a 

significant environmental advantage over the proposed project.

PNGTS Pipeline System

The PNGTS pipeline system includes about 144 miles of 24-inch-diameter mainline pipeline 

from the Canadian border near Pittsburg, New Hampshire to Westbrook, Maine, and about 

101 miles of 30-inch-diameter pipeline jointly owned with M&NE between Westbrook and 

Dracut, Massachusetts. The PNGTS system interconnects with M&NE at Westbrook, Maine and 

with Tennessee Gas at Dracut. The system is connected to the TransQuebec and Maritimes 

Pipeline in Canada which receives natural gas primarily from production areas in western 

Canada and the United States. The system has capacity of about 0.24 Bcfd from Pittsburg to 

Westbrook, and 0.21 Bcfd from Westbrook to Dracut. Because the PNGTS system is connected 

to the M&NE system near the primary market area, an expansion of the PNGTS system could 

provide a conceptual system alternative to the Downeast LNG Project. However, an expansion 

of the PNGTS system would be required to support the additional 0.5 Bcfd proposed by 

Downeast. The exact nature of the expansion that would be required and the related 

environmental impacts is not known, but could include construction of additional pipeline and 

compression along the existing PNGTS system. Because an expansion of the PNGTS system 

would have its own set of environmental impacts, we do not believe that expansion of the 

PNGTS pipeline would be a reasonable system alternative or an environmentally preferable 

alternative to the Downeast LNG Project. In addition, this system alternative would not meet the 

Downeast LNG Project objectives of providing a source of imported natural gas and additional 

natural gas storage facilities.

Algonquin Pipeline System

Algonquin, a subsidiary of Spectra Energy, transports about 1.6 Bcfd of natural gas from eastern 

Pennsylvania to the Boston, Massachusetts area. Algonquin interconnects with the end-point of 

the M&NE system in Beverly, Massachusetts, and the Tennessee Gas system in Mendon, 

Massachusetts. To supply an additional 0.5 Bcfd of natural gas to the region, the Algonquin 

system may require modification and/or expansion. In addition, because Algonquin’s operating 

pressure is only 750 pounds per square inch (psi), the existing 24-inch-diameter pipeline would 

need to be replaced with larger diameter pipeline along much of the system, or additional loop 

pipeline added adjacent to the existing pipeline as well as additional compression added to 

existing or new compressor stations. Because the Algonquin pipeline system is connected to the 

M&NE system near the primary market area, use of the Algonquin system could provide a 

conceptual system alternative to the Downeast LNG Project. However, an expansion of the 

Algonquin system may be necessary to support the additional 0.5 Bcfd proposed by Downeast. 

In 2013 Algonquin proposed a system expansion called the Algonquin Incremental Market

project (FERC Docket No. PF13-16-000) which would increase capacity on its system by up to 
3-9 3.0 – Alternatives

about 342,000 dekatherms per day, or approximately 0.3 Bcfd. Algonquin states this project 

would allow abundant regional natural gas supplies from the Appalachian basin, which would 

include Marcellus shale, to flow reliably into the Northeast. The project would include 

construction of approximately 37 miles of new pipeline, additional horsepower at five existing 

compressor stations, three new meter stations, and modifications to existing meter stations. New 

construction and modifications would occur along Algonquin’s system in New York, 

Connecticut, Rhode Island, and Massachusetts.

Based on the projected increase in capacity on Algonquin’s system (0.3 Bcfd), if this project 

were constructed it could provide a partial alternative to the additional 0.5 Bcfd of natural gas 

supply proposed by the Downeast LNG Project. However, this system alternative would not 

meet the Downeast LNG Project objectives of providing a source of imported natural gas and 

additional natural gas storage facilities. Downeast has proposed its project in anticipation of a 

need for additional natural gas volumes in New England, beyond that which would be provided 

by Algonquin’s proposed system expansion. The Commission must evaluate the merits and 

associated environmental impacts of the proposed Downeast LNG Project. Future market 

demand could justify construction of the Downeast LNG Project in addition to an expansion of 

the Algonquin pipeline system.

Tennessee Gas Pipeline System

Tennessee Gas, a unit of the El Paso Corporation, serves the New England region through points 

in New York and Pennsylvania, with end points in southern New Hampshire and eastern 

Massachusetts, north and south of Boston. The source of natural gas in this system is from 

various production areas in the Gulf of Mexico as well as Marcellus Shale region in 

Pennsylvania and Ohio. The Tennessee Gas system interconnects with the joint M&NE/PNGTS 

pipeline in Dracut, Massachusetts and with the Algonquin system in Mendon, Massachusetts. In 

November 2012, Tennessee Gas placed a new expansion project in service that increased 

capacity on its 300 Line system which moves product from the Marcellus Shale region to 

markets in New England and northern New York. Its Northeast Supply Diversification Project 

added 250,000 dekatherms per day (about 240 MMcfd), which is about 40 percent of the

proposed peak delivery capacity of the Downeast LNG Project. A similar future expansion of 

the Tennessee Gas system could potentially provide a volume of natural gas to New England that 

could make up the volume proposed by Downeast. The exact nature of an expansion is not 

known, however, such an expansion may require significant new pipeline facilities along its 

system, including through densely developed areas. Because an expansion of the Tennessee Gas 

system would have its own set of environmental impacts, we do not believe that expansion of the 

Tennessee Gas system would be a reasonable system alternative or an environmentally 

preferable alternative to the Downeast LNG Project. In addition, this system alternative would 

not meet the Downeast LNG Project objectives of providing a source of imported natural gas and 

additional natural gas storage facilities.

Conclusions on Pipeline System Alternatives

Expanding or modifying the existing pipeline systems to be able to deliver the natural gas 

volumes proposed by Downeast to northern and eastern New England would result in a variety 

of environmental impacts depending on the project size, length, and design. It is typical for 

significant pipeline construction projects in the region to result in short- or long-term impacts on 
3.0 – Alternatives 3-10

water resources, vegetation, wetlands, wildlife habitats, and land use. Substantial expansion or 

modifications to existing pipeline systems may be required to deliver the gas volumes to the 

markets proposed by Downeast. In addition to construction-related effects, operation of pipeline 

compressor stations may also result in permanent noise and air quality impacts.

We expect that new pipelines or proposals to modify existing pipelines will continue to increase 

the capacity of existing systems delivering natural gas to New England. Nevertheless, these 

projects could not meet the project objectives of providing access to new natural gas supplies 

from around the world. Expansion of an existing pipeline system would also not meet the 

project objective of increasing the supply diversity in the region. Even if a pipeline system 

alternative was combined with the use of an existing, modified, or proposed LNG facility, the 

environmental impacts of such an alternative would not provide a clear advantage over the 

Downeast LNG Project.

3.3.2 LNG Terminal System Alternatives

Existing and potential new LNG terminals considered as potential system alternatives to the 

project are shown in figure 3.3-2. With the exception of the existing operating terminals, all of 

the potential new LNG terminals considered in our analysis were previously proposed and at 

various states of approval or construction, but all have since been cancelled or suspended and are 

no longer actively proposed. LNG terminals included in our analysis are, or would be, located in 

the New England coastal region or in eastern Canada (FERC 2013a, 2013b; Natural Resources 

Canada 2011). Because of the close proximity of several proposed LNG import projects in 

eastern Canada, and because some of these projects would supply natural gas, at least partially, 

to the northeastern United States, we have included these projects in our alternatives analysis. 

Our analysis did not consider existing or proposed LNG terminals in other parts of North 

America, such as the Mid-Atlantic, Southeast, and Gulf Coast regions, because these facilities 

serve different markets, and use of those facilities would require substantial new infrastructure 

development to transport gas to New England. Further, we did not consider the proposed 

KeySpan LNG Terminal Project in Providence, Rhode Island, because in June 2005 the 

Commission declined to authorize this project. In August 2005, KeySpan filed an appeal of that 

denial. In January 2006, FERC upheld its denial, and Keyspan withdrew its appeal and 

suspended further work on the project in 2007. Table 3.3.2-1 lists the LNG terminals considered 

in our analysis and their relevant characteristics.

3.3.2.1 Existing LNG Terminals in New England and Eastern Canada

Distrigas LNG Terminal

The Distrigas LNG facility is owned by GDF Suez. The facility is about 250 miles from the

proposed Downeast LNG Project on a 24-acre site on the Mystic River in Boston Harbor 

that is surrounded by industrial development. In service since 1971, the Distrigas facility is the 

oldest LNG import terminal in the United States. In 2000 and 2001, the FERC authorized 

installation of a vapor recovery system to recover flash gas during vessel unloading, replacement 

of all vaporizers to be compatible with a new thermal transfer system and a new adjacent power 

plant, and the installation of additional vaporizers and pumps to provide natural gas service to an 

electric power generation plant. Installation of these new facilities is complete. 
M a i n e

V e r m o n t

N e w

H a m p s h i r e

M a s s a c h u s e t t s

N e w

Y o r k

C o n n e c t i c u t R h o d e

I s l a n d

AES

Battery

Rock

Canaport

Calais

Rabaska

Cacouna

Maple

Bear

Head

Downeast

Broadwater

Keyspan

Weaver's Cove

Northeast Gateway

Neptune

Quoddy Bay

Distrigas

Deep Panuke

Legend

Existing LNG Terminal

LNG Proposals

0 40 80 120 160 20

Miles

P:\Downeast-3253\Team Information\GIS\Spatial\MXD\Sendout_Pipeline_Reroute_Figures_082608\Figure3.3-2.mxd

Figure 3.3-2 

Downeast LNG Project

Existing and Proposed LNG Terminals

in Coastal New England and Canada

CANADA

3-11
3.0 – Alternatives 3-12

TABLE 3.3.2-1

Existing and Potential New LNG Terminals Considered as Alternatives

Project

Location and 

Approximate 

Distance from 

Downeast

Daily 

Sendout 

Capacity 

(Bcfd)

Target Market Facility Type Status

Existing In-Service Projects

Distrigas LNG Boston, 

Massachusetts 

(250 miles)

0.7 New England Onshore Operating

Northeast Gateway 

Energy Bridge

Offshore Gloucester, 

Massachusetts

(250 miles)

0.8 New England Offshore, shuttle 

regasification 

vessel (SRV) a/

Operating as of May 2008.

Neptune LNG 

Deepwater Port

Offshore Gloucester, 

Massachusetts

(250 miles)

0.4 New England Offshore, SRV a/ Operating as of May 2010.

Canaport LNG St. John, New 

Brunswick 

(60 miles)

1.0 New England and 

eastern Canada

Onshore Operating as of June 2009.

Potential New Projects (Previously planned but currently suspended or cancelled)

Weaver’s Cove 

LNG

Fall River, 

Massachusetts 

(300 miles)

0.8 New England 

(southeastern 

Massachusetts 

and Rhode Island)

Onshore Approved by FERC; Filed 

application for offshore berth 

alternative in January 2009. 

Project withdrawn by the 

proponent in June 2011.

Bear Head LNG Point Tupper, Nova 

Scotia 

(290 miles)

1.0 New England and 

eastern Canada

Onshore Construction began 2004 but 

suspended/cancelled due to 

lack of long-term LNG supply. 

Maple LNG Goldboro, Nova 

Scotia

(250 miles)

1.0

(additional 

1.0 with 

expansion)

Eastern Canada Onshore Approved by Canadian 

government. Project withdrawn 

by the proponent in August 

2010.

Cacouna Energy Gros Cacouna, 

Quebec

(230 miles)

0.5 Quebec, Ontario, 

Northeast US

Onshore Approved by Canadian 

government; Suspended as of 

December 2008. Decision to 

not extend option to lease 

project site announced in 

November 2009.

Rabaska Quebec City, 

Quebec

(230 miles)

0.5 Quebec, Ontario Onshore Approved by Canadian 

government; Project 

suspended. 

Quoddy Bay LNG Perry, Maine

(8 miles)

2.0 New England Onshore FERC dismissed application via 

Order issued October 17, 2008

Calais LNG Calais, Maine

(10 miles)

1.0 New England Onshore FERC dismissed application via 

Order issued April 2012.

Grande-Anse 

Project

Port of GrandeAnse, Quebec, 

Canada

1.0 Quebec, Ontario Onshore Project suspended. 

AES Battery Rock Boston, 

Massachusetts

(250 miles)

0.8 New England Onshore Announced in 2006, cancelled 

in April 2007.

a/ Shuttle regasification vessels (SRVs) are marine vessels that transport LNG and have onboard vaporization equipment.

Vaporized LNG is transferred from the SRV to a pipeline riser that is attached to an offshore buoy.
3-13 3.0 – Alternatives

The Distrigas facility has two tanks that can store 155,000 m3 of LNG. The facility has an 

installed vaporization capacity of 1.035 Bcfd; however, due to pipeline capacity, maximum 

sendout is limited to 0.715 Bcfd. A significant quantity of LNG is loaded onto LNG trucks and 

delivered to peakshaving facilities throughout New England. The four-bay truck station on the 

site can fill up to 100 trucks per day. Distrigas signed a deal with its supplier in 2010 that would 

bring in up to 30 LNG vessels per year to this facility.

The Distrigas facility is dedicated to LNG imported by GDF Suez and is not operated as an 

open-access import terminal that provides terminalling services to other parties. To provide the 

same service as proposed by Downeast, Distrigas would need to add another 320,000 m3 of 

storage and up to about 0.5 Bcfd of vaporization. There is no space on the existing 24-acre site 

to construct the additional facilities associated with the proposed Downeast LNG Project, nor is 

there available adjoining property to accommodate these facilities and the associated exclusion 

zones. Therefore, we believe that expansion of the existing Distrigas LNG import terminal is not 

a feasible system alternative.

While it does not appear that the existing Distrigas facility could be reasonably expanded to 

satisfy all of the objectives of the Downeast LNG Project, it is conceivable that the facility could 

be expanded to provide some additional natural gas sendout capacity. For example, in 2003 the 

Commission received an application to review the Everett Extension Project. Although this 

proposal was later withdrawn by the proponents because it was not thought to be economically 

viable, the Everett Extension Project would allow Distrigas to mitigate some take-away 

constraints and allow sendout of an additional 0.11 Bcfd of natural gas via a pipeline operated by 

Algonquin. The project would depend on construction of the Deer Island Lateral, which was 

approved by the Commission in 2002 but never constructed, and a new lateral pipeline that 

would extend from the Deer Island Lateral to a connection with Algonquin’s existing J-System, 

which interconnects with the Distrigas LNG facility in Everett, Massachusetts. The facilities 

required for the project would include reconfiguration of existing vaporization equipment within 

the existing boundaries of the Distrigas property and new pipeline facilities to be constructed by 

Algonquin. 

The pipeline facilities for the Everett Extension Project would include 12.4 miles of pipeline 

(including the Deer Island Lateral Pipeline), with 4.2 miles onshore and the other 8.2 miles 

offshore in Boston Harbor. About 2.4 miles of the offshore pipeline would be installed using 

HDD techniques and the remaining portion would be installed by dredging, jetting, or plowing. 

Impacts would include temporary disruption of local roadways and recreational trails, noise 

during construction, increased turbidity and sedimentation as a result of offshore construction, 

and direct and indirect impacts on aquatic resources. Because of environmental and permitting 

constraints, the working conditions in Boston Harbor, and other factors, the Everett Extension 

Project was not considered economically viable. We are not aware of other ways in which the 

Distrigas LNG facility could be reasonably expanded to allow additional natural gas sendout or 

provide more LNG storage. Therefore, we do not believe that an expansion of the Distrigas 

LNG facility is an economically feasible alternative, nor would it offer significant environmental 

advantage over the proposed project.
3.0 – Alternatives 3-14

Northeast Gateway LNG Project

The Northeast Gateway Energy Bridge (Northeast Gateway) Project is an offshore LNG import 

facility located within Massachusetts Bay, about 13 miles south-southeast of Gloucester, 

Massachusetts. The Northeast Gateway Project began operation in May 2008, and is capable of 

mooring specially designed LNG regasification vessels with a capacity of about 138,000 m3. 

This facility has no LNG storage capability, and is capable of providing a baseload delivery of 

0.4 Bcfd and peak deliveries of approximately 0.8 Bcfd through a 16.4-mile-long, 24-inchdiameter submarine pipeline connecting to the Algonquin HubLine Pipeline System.

The Northeast Gateway Project serves the same New England market as proposed for the 

Downeast LNG Project, and provides about the same baseload delivery and slightly more peak 

delivery as proposed by Downeast. However, Northeast Gateway does not provide any storage 

capacity, and therefore does not meet Downeast’s objectives of providing natural gas storage 

facilities. It may be possible that the Northeast Gateway Project could be modified to accept 

additional LNG vessel deliveries, and increase the baseload delivery to the New England market 

enough to be considered an alternative to the Downeast LNG Project. Such an expansion would 

require modification of the existing permits and authorizations, and may require expansion of the 

existing sendout pipeline or addition of a second pipeline. Therefore, while the Northeast 

Gateway Project partially meets one of the objectives of the Downeast LNG Project, it does not 

meet all of the objectives, and we do not believe that the Northeast Gateway Project would serve 

as a system alternative to the Downeast LNG Project. We have, however, further evaluated the

potential for the Northeast Gateway Project in combination with the Neptune LNG Project 

(discussed below) to be a system alternative to the Downeast LNG Project (see section 3.3.2.2).

Neptune LNG Project

The Neptune LNG Project is an offshore LNG import facility located within Massachusetts Bay 

approximately 22 miles northeast of Boston, Massachusetts, and approximately 7.0 miles southsoutheast of Gloucester, Massachusetts. The facility is located in federal waters on the Outer 

Continental Shelf and is designed for mooring specially designed LNG regasification vessels

with a capacity of about 140,000 m3. The project includes two separate buoys to allow continual 

delivery of gas with an average throughput capacity of 0.4 Bcfd and a peak capacity of 

0.75 Bcfd. The facility does not have LNG storage capacity. The project connects to the 

existing Algonquin HubLine Pipeline System. The project became operational in May 2010. 

However, in May 2012 Neptune LNG requested, and the Maritime Administration approved, a 

temporary five-year suspension of operations at the facility. During the suspension period the 

Neptune LNG Project must maintain compliance with the terms, conditions, and requirements of 

the deepwater port license amendment. Because the suspension of operations is temporary, we 

continue to consider the Neptune LNG Project as a potential alternative.

The Neptune LNG Project serves the same Boston area market proposed for the Downeast LNG 

Project, and provides about the same baseload delivery and slightly more peak delivery than 

proposed by Downeast. However, the Neptune Project does not provide any storage capacity, 

and would therefore not meet Downeast’s objectives of providing natural gas storage facilities. 

Therefore, while the Neptune LNG Project would partially meet one of the objectives of the 

Downeast LNG Project, it could not meet all the objectives, and we do not believe that the 

Neptune LNG Project would serve as a system alternative to the Downeast LNG Project. We 
3-15 3.0 – Alternatives

have, however, further evaluated the potential for the Neptune LNG Project in combination with 

the Northeast Gateway Project to be a system alternative to the Downeast LNG Project (see 

section 3.3.2.2).

Canaport LNG Project

The Canaport LNG Project is located at the Irving Canaport facility near St. John, New 

Brunswick, Canada. The project includes three LNG storage tanks and vaporization to provide a 

sendout capacity of 1.2 Bcfd. The project began operating in June 2009. Markets for natural gas 

from the Canaport facility include use of the gas at the existing refinery at Canaport (and 

possibly a new power plant), sale of gas to local and New Brunswick markets, and supply to 

potential demand along the existing pipeline corridor. Natural gas from the Canaport LNG 

Project not consumed in Canada can be transported to the same U.S. markets that the Downeast

LNG Project would supply through the same M&NE pipeline system.

A potential alternative to the Downeast LNG Project could be an expansion of the Canaport 

LNG Project that would provide an additional 320,000 m3 of storage and up to 0.5 Bcfd of 

vaporization and sendout capacity. While it appears additional land area may be available at the 

Canaport LNG site for a fourth LNG storage tank and additional vaporization, we have not 

conducted, nor are we aware that others have conducted, an engineering review to determine if 

the terminal site could be physically enlarged to provide additional LNG storage and 

vaporization capacity beyond what is currently approved. An expansion of the LNG storage and 

sendout capacity would require additional LNG vessel deliveries to the terminal, and possibly an 

additional ship berth. Expansion of the Canaport LNG Project as an alternative to the Downeast 

LNG Project could also require additional or expanded pipeline facilities in Canada and the 

United States to increase take away capacity. The exact nature of such an expansion and any 

related environmental impacts have not been identified, however such an expansion would likely 

require construction of a new LNG storage tank and vaporization facilities, additional LNG 

vessel traffic, and possibly new natural gas pipelines. Therefore, such an alternative would have 

environmental impacts generally similar in nature than the proposed Downeast LNG Project. 

Also, it is unclear if the Canaport LNG Project site could support such an expansion. For these 

reasons, we do not believe that an expansion of the Canaport LNG Project would be an 

environmentally preferable alternative. 

3.3.2.2 Combination of Existing Projects

It is possible that some combination of two or more of the existing LNG terminal projects 

described above, or future expansions of those projects, could provide an equivalent of the 

proposed delivery of 500 MMcfd of natural gas to the New England market and could serve as 

an alternative to the proposed Downeast LNG Project. Under such an alternative, the necessary 

changes or expansions at each project could be incremental, and related environmental impact at 

each project could also be relatively minor. However, when combined, cumulative impacts from 

these expansions could be similar or greater than impacts from the proposed project. The total 

environmental impact of such an alternative would depend on exactly which projects and which 

components of each project were included or expanded to make up the alternative. The potential 

alternative of a combined Northeast Gateway LNG and Neptune LNG Projects is discussed 

below.
3.0 – Alternatives 3-16

Northeast Gateway LNG and Neptune LNG Projects

We believe a combination of the existing Northeast Gateway Project and Neptune LNG Project 

merits evaluation as a potential alternative to the proposed Downeast LNG Project. Such a 

combination would provide a new delivery point of natural gas to New England via an LNG 

import terminal. The potential for either project alone to serve as an alternative is discussed 

above.

The Northeast Gateway and Neptune LNG Projects combined would provide a baseload delivery 

of 0.8 Bcfd and peak deliveries of approximately 1.55 Bcfd, and could therefore meet 

Downeast’s purpose of providing 500 MMcfd (0.5 Bcfd) baseload and up to 625 MMcfd 

(0.625 Bcfd) peak delivery, of natural gas to the New England market. Neither Northeast 

Gateway nor Neptune LNG would provide LNG storage; therefore, even a combination of both 

existing projects would not meet the objective of the Downeast LNG Project of providing 

320,000 m3 of storage capacity. However, the ability of the combined projects to provide 

baseload delivery and peak delivery of 0.3 Bcfd and 0.925 Bcfd, respectively, above that 

proposed by Downeast, may compensate for the lack of LNG storage capacity. In addition, it is 

possible that a new storage facility could be constructed to add storage capacity to either existing 

project. No such facility has been identified or proposed and the potential site and related 

potential environmental impacts of this conceptual alternative have not been identified.

Environmental impacts of the existing projects have been evaluated and described in their 

respective EISs, and an alternative of both existing projects combined would not result in 

additional environmental impacts beyond that described in the respective EISs. A combined 

Northeast Gateway and Neptune LNG Projects alternative, without LNG storage, would not have 

land-based impacts, and we believe would have less environmental impact than the proposed 

Downeast LNG Project. However, Downeast has proposed its project in anticipation of a need 

for additional natural gas volumes in New England, beyond that which would be provided by 

Northeast Gateway and Neptune LNG. The Commission must evaluate the merits and associated 

environmental impacts of the proposed Downeast LNG Project. Despite the current weak 

economy and resulting short-term decrease in domestic energy consumption, future market 

demand could justify construction of the Downeast LNG Project, in addition to the existing 

Northeast Gateway and Neptune LNG Projects.

3.3.2.3 Previously Proposed LNG Projects

The LNG projects discussed below are no longer proposed, or have been placed on hold for 

various reasons. We have included discussion of them as alternatives, in case their status were to 

change in the future.

Weaver’s Cove LNG Project

In June 2005, the Commission approved the Weaver's Cove LNG Project in Fall River, 

Massachusetts (Docket No. CP04-36-000). To address environmental and safety concerns raised 

by various stakeholders, Weaver’s Cove proposed an amendment to its proposed project in 

January 2009 under Docket No. CP04-36-005. The amendment would involve construction of 

an offshore LNG berth in Mount Hope Bay and cryogenic LNG transfer pipelines that would 

transport LNG from the offshore berth to the onshore LNG storage tanks at the authorized 

terminal. Weaver’s Cove withdrew its application for the project in June 2011.
3-17 3.0 – Alternatives

As originally proposed, the Weaver’s Cove LNG Project would serve specific customers in the 

Northeast and New England states. As an alternative to Downeast’s proposal, it is possible that 

the Weaver’s Cove LNG Project as approved could be expanded to provide the additional 

storage and sendout capacity proposed by Downeast. To provide the same service as proposed 

by Downeast, it would be necessary to add another 320,000 m3 of storage and up to 0.5 Bcfd of 

vaporization. In its application, Weaver’s Cove stated that if there is a future demand for natural 

gas in its market area, the maximum sendout capacity could be increased by an additional 

0.2 Bcfd with the addition of heaters and a vaporizer. It is also possible that an additional 

storage tank could be added, provided adjacent land area could be secured to provide the 

necessary safety and exclusion zones. While it appears additional land area may be available at 

the Weaver’s Cove site, we have not conducted, nor are we aware that others have conducted, an 

engineering review to determine if the terminal site could be physically enlarged to provide 

additional LNG storage and vaporization capacity beyond what is proposed by Weaver’s Cove. 

In addition, an expansion of the LNG storage and sendout capacity would require additional 

LNG vessel deliveries to the terminal, and possibly an additional ship berth. Construction and 

expansion of the Weaver’s Cove terminal as an alternative to the Downeast LNG Project would 

also require additional or expanded pipeline facilities to increase take away capacity, the length 

and location of which is not known. The construction and expansion of the Weaver’s Cove LNG 

Project as an alternative to the Downeast LNG Project would result in its own set of 

environmental impacts similar to, or potentially greater than, those from the proposed Downeast 

LNG Project. Furthermore, Weaver’s Cove has withdrawn the application for the project and it 

is uncertain if a revised or similar LNG project would ever be proposed at the Weaver’s Cove 

site. Therefore, we do not consider construction and expansion of the Weaver’s Cove LNG 

Project to be a practical alternative to the Downeast LNG Project.

Bear Head LNG Project

Anadarko Petroleum planned to build the Bear Head LNG Project on Cape Breton Island, Nova 

Scotia. The project would be constructed and operated in two phases, with the first phase 

providing sendout capacity of 1.0 Bcfd and the second phase increasing sendout capacity to 

1.5 Bcfd. Construction began in 2004, however it was halted in May 2006, and on 

February 6, 2007, Anadarko announced the project will be put on hold because it was unable to 

obtain long-term LNG supply. The initial proposal included delivery of natural gas from Bear 

Head LNG to northeast Canada and United States markets, with delivery to the United States via 

an expansion of the existing M&NE system. To accommodate this supply to the United States 

(and supply from the Canaport LNG Project, see below), M&NE entered into the FERC Prefiling Review Process (PF05-17-000) for the Phase IV Expansion Project, initially proposed to 

include 146 miles of looped 36-inch-diameter pipeline along the existing route and six new 

compressor stations in Maine and Massachusetts, terminating in Dracut, Massachusetts. In May 

2006, in response to the announcement that construction of the Bear Head LNG Project had been 

discontinued indefinitely, M&NE modified the Phase IV proposal to eliminate a new compressor 

station and all but 1.7 miles of new pipeline in Maine (Docket No. CP06-335-000). Because the 

Bear Head LNG Project is now on hold with no immediate plans to continue development, we do 

not believe it is a feasible system alternative to the Downeast LNG Project. Even if the Bear 

Head LNG terminal were to become operational, substantial upgrades to the downstream 

interstate pipeline systems and, potentially, the LNG terminal itself would be required to meet 

regional market needs. Impacts associated with these upgrades would be equal to, or greater 
3.0 – Alternatives 3-18

than, those associated with the Downeast LNG Project. Therefore, if the Bear Head LNG Project 

were to be constructed, we do not believe that an expansion of it would be an environmentally 

preferable alternative to the Downeast LNG Project.

Maple LNG Project

Maple LNG proposed to construct an LNG import terminal in Goldboro, Nova Scotia. The 

terminal would include LNG storage and regasification facilities, and would be constructed in 

association with an adjacent petrochemical complex and an electric co-generation facility. As 

proposed, the project would have a natural gas sendout capacity of 1.0 Bcfd and originally 

projected an in service date of 2009. The sendout pipeline from the LNG facility would tie into 

the Canadian portion of the existing M&NE system. An application for the project was filed in 

January 2005 with the Nova Scotia Department of Environmental Labor. Maple LNG had 

received Canadian federal and provincial approval, as well as the required permits to construct 

and operate the terminal and petrochemical facility (Natural Resources Canada 2008). However, 

plans to develop the project were halted by Maple LNG in April 2010.

Although the project would tie into the M&NE system, Maple LNG had not determined what 

part of the sendout from the project would be directed to the United States. As planned, much of 

the natural gas made available from the terminal would be used in the adjacent petrochemical 

complex and co-generation plant in Canada. Therefore, while the Maple LNG Project as 

originally proposed could be a partial alternative to the Downeast LNG Project, it would likely 

only provide a small portion of Downeast’s proposed volume of natural gas to New England, if 

any.

A potential alternative to the Downeast LNG Project could be an expansion of the Maple LNG 

Project that would provide an additional 320,000 m3 of storage and up to 0.5 Bcfd of 

vaporization and sendout capacity. While it appears additional land area may be available at the 

Maple LNG site for additional LNG storage and vaporization, we have not conducted, nor are we 

aware that others have conducted, an engineering review to determine if the terminal site could 

be physically enlarged to provide additional LNG storage and vaporization capacity beyond what 

is currently approved. While the exact nature of such an expansion and any related 

environmental impacts have not been identified, an expansion of the LNG storage and sendout 

capacity would likely require additional LNG vessel deliveries to the terminal, and possibly an 

additional ship berth. Construction and expansion of the Maple LNG Project as an alternative to 

the Downeast LNG Project may also require additional or expanded pipeline facilities in Canada 

and the United States to increase take away capacity. Because construction and expansion of the 

Maple LNG Project would likely require construction of new LNG storage and vaporization 

facilities, additional LNG vessel traffic, and new natural gas pipelines, such an alternative would 

be expected to have similar environmental impacts than the proposed Downeast LNG Project. 

Also, it is unclear if the Maple LNG Project site could support such an expansion. Furthermore, 

plans to develop the project have been halted by Maple LNG and it is uncertain if a new or 

revised project would ever be proposed at the site. For these reasons, we do not believe that 

construction and expansion of the Maple LNG Project would be an environmentally preferable 

alternative.
3-19 3.0 – Alternatives

Cacouna Energy LNG Project

TransCanada and Petro-Canada proposed an LNG storage and regasification project on Gros 

Cacouna Island in the St. Lawrence River near Riviere du Loup, Quebec. The capacity of this 

facility would be about 0.5 Bcfd and was originally proposed to be in service in 2009. About 

150 miles of new pipeline would be constructed to provide necessary sendout capacity. The 

provinces of Quebec and Ontario would be the primary markets for this project; however, the 

northeastern United States is also a potential market.

The Cacouna Energy LNG Project could potentially supply a portion of the natural gas to New 

England that is proposed by the Downeast LNG Project. However, the volume of gas that would 

be available to the northeastern U.S markets is uncertain, and it is reasonable to assume that most 

natural gas would be dedicated to markets in Quebec and eastern Ontario. The project was 

awarded Canadian federal and provincial regulatory approval in June 2007; however, Cacouna 

Energy announced on December 31, 2008, that it was closing its offices for an indefinite period 

due to world market LNG supply conditions and other economic factors, stating that conditions 

do not exist for construction of the terminal at this time. In November 2009, the proponents 

announced that they would not extend the option to lease the project site, and the project is 

considered suspended. Therefore, we do not believe that the Cacouna Energy LNG Project 

would be a practical alternative to the Downeast LNG Project.

Rabaska LNG Project

The Rabaska LNG Project was proposed in Lévis near Quebec City, Quebec, and included a 

jetty, a cryogenic pipe, two LNG storage tanks, and regasification equipment. The Rabaska 

LNG terminal was proposed to connect to the Canadian gas transport network through a 24-inchdiameter pipeline, extending approximately 26 miles from the LNG terminal to the Trans Quebec 

and Maritimes Pipeline distribution station in Saint-Nicolas. The entire 0.5-Bcfd proposed 

sendout capacity was designated for markets in Quebec and eastern Ontario, with no capacity 

designated for the United States. The Rabaska project proponents received Canadian federal and 

provincial approval, as well as the required permits to construct and operate the facility. In 

addition, Rabaska signed a Memorandum of Understanding with Russia’s Gazprom for LNG 

supply starting in 2014. However, Rabaska has since halted plans to develop the project (Natural 

Resources Canada 2011). Given the lack of capacity for U.S. northeast markets, and the fact that 

Rabaska has suspended plans for the project, we conclude the Rabaska LNG Project is not a 

viable system alternative to the Downeast LNG Project.

Grande-Anse Project 

Énergie Grande-Anse Inc. had proposed to develop and build in collaboration with the Saguenay 

Port Authority (SPA) an LNG import terminal in the Port of Grande-Anse, along the Saguenay 

River in Quebec, Canada. The LNG terminal would include a deep water wharf to be built and 

operated by the SPA; cryogenic piping and accessories to deliver the LNG to the storage tanks; 

three storage tanks, each having a capacity of 160,000 m3; and a regasification facility. Énergie 

Grande-Anse Inc. estimated that approximately 110 LNG vessels per year would transport the 

LNG along the Saguenay River to the Port of Grande-Anse. As proposed, the facility would

have an initial send-out capacity of about 1 Bcfd (Natural Resources Canada 2008). The project 

began review by the Canadian Environmental Assessment Agency as well as by the Government 

of Québec under the Quebec Environment Quality Act. However, Énergie Grande-Anse has 
3.0 – Alternatives 3-20

since suspended plans to develop the project (Natural Resources Canada 2011). As originally 

proposed, the project’s sendout capacity was designated, in order of priority, first for markets in 

Quebec and Ontario, and last for markets in the Northeast United States. Given the uncertainty

of capacity for U.S. northeast markets, and the fact that plans to develop the project have been 

halted, we conclude the Grande-Anse Project is not a viable system alternative to the Downeast 

LNG Project. 

Quoddy Bay LNG Project

On December 15, 2006, Quoddy Bay LNG filed an application with the FERC (Docket 

No. CP07-35-000) seeking authority to construct and operate a new LNG import terminal and 

storage facility at Split Rock on the Passamaquoddy Tribe’s Pleasant Point Reservation, in 

the Town of Perry, Maine. In a February 29, 2008 filing, Quoddy Bay indicated possible 

revisions to the project design pending negotiations with LNG suppliers and investigation into 

the use of additional mitigation measures. On April 25, 2008, the Commission suspended its 

review of Quoddy Bay LNG’s application since Quoddy Bay LNG was unable to provide any 

further information regarding possible revisions to the project design, or information required 

by FERC staff to proceed with its engineering review and preparation of the draft EIS. On 

October 17, 2008, the Commission dismissed Quoddy Bay’s applications. This dismissal was 

without prejudice to Quoddy Bay filing a new application in the future if Quoddy Bay is able to 

finalize its design and provide a complete application.

As originally proposed, Quoddy Bay’s proposed LNG terminal site would be about 8 miles south 

of Downeast’s proposed site. The Quoddy Bay LNG Project would include two LNG ship berths 

and associated unloading platforms and pipeline, a submarine cryogenic pipeline, three 160,000 

m3 storage tanks, and a 36-mile-long, 36-inch-diameter natural gas sendout pipeline extending 

from the LNG terminal to the existing M&NE pipeline system at the Baileyville, Maine 

Compressor Station. The maximum sendout capacity of the Quoddy Bay LNG Project would be 

about 2.0 Bcfd. 

The Quoddy Bay LNG Project would supply more natural gas volume to New England than is 

proposed by Downeast; therefore, the Quoddy Bay LNG Project as originally proposed could 

potentially serve as a system alternative to the Downeast LNG Project. However, given that the 

Quoddy Bay LNG Project application has been dismissed, we do not consider the project as a 

viable or reasonable system alternative to the proposed project. 

Calais LNG Project

On May 30, 2008, Calais LNG Project Company LLC (Calais LNG) filed a request with the 

FERC to initiate the NEPA Pre-filing Process for a proposed LNG import, storage, and 

regasification terminal near Ford Point on the St. Croix River in the City of Calais, Washington 

County, Maine. On June 18, 2008, the FERC initiated the NEPA Pre-filing Process for the 

Calais LNG Project. The project would be about 15 miles upriver from the proposed Downeast 

LNG terminal and would have two 160,000 m3 LNG storage tanks and a normal sendout 

capacity of about 1.0 Bcfd and peak sendout capacity of 1.5 Bcfd. The project would connect to 

the M&NE Pipeline system near the Baileyville Compressor Station with about 20 miles of 

36-inch-diameter pipeline, using a pipeline route similar to Downeast’s proposed sendout 

pipeline route beginning at about MP 14. The Commission dismissed the Calais LNG project 
3-21 3.0 – Alternatives

application in April 2012, and the project is no longer under review. As originally proposed, the

Calais LNG Project would supply more natural gas volume to New England than is proposed by 

Downeast; therefore if constructed, the Calais LNG Project could potentially serve as a system 

alternative to the Downeast LNG Project. However, because the project is not currently 

proposed, and it is uncertain if a new or revised project would ever be proposed at the Calais 

LNG project site, we do not believe that construction of the Calais LNG project would be a 

viable system alternative. If the Calais LNG project were to be proposed again at some future 

date, we would conduct a full evaluation of the project, including the potential for the project to 

be an alternative to the Downeast LNG Project.

AES Battery Rock LNG Project

In 2006, AES Corporation announced plans for a proposed LNG import, storage, and 

regasification facility to be located on Outer Brewster Island within the Boston Harbor Islands 

State Park, in Boston Harbor. AES indicated the project would provide 0.8 Bcfd sendout 

capacity and 6.0 Bcf of storage capacity, and would require about 1.2 miles of new pipeline to 

connect to the existing Algonquin HubLine pipeline and the interstate pipeline system and the 

northeast natural gas markets. The project would require administrative removal of Outer 

Brewster Island from the state park. In April 2007, AES announced it would not pursue this 

project due to competition from the offshore Northeast Gateway and Neptune Projects, and 

opposition from various groups. Therefore, we do not believe the AES Battery Rock LNG 

Project is a feasible alternative to the Downeast LNG Project. 

3.3.2.4 Proposed Offshore Natural Gas Development

New offshore natural gas drilling in coastal New England or Maritimes Canada could potentially 

provide new sources of natural gas supply to New England. One such project has been identified 

that may be in production within the general time frame and that could be considered a potential 

alternative to the proposed Downeast LNG Project.

Deep Panuke Offshore Gas Development Project

The Deep Panuke Project is located offshore southeast of Halifax, Nova Scotia, Canada. The 

project includes an offshore production unit, subsea production wells and connecting pipelines, 

and a 22-inch subsea pipeline connecting to M&NE’s facilities in Goldboro, Nova Scotia. The 

Deep Panuke Project has a design capacity for production of about 300 MMcfd. A portion of the 

new production would be sent to the M&NE system, and up to about 200 MMcfd (0.2 Bcfd) 

would be available to New England markets through the M&NE U.S. system. Construction 

commenced in November 2008 and gas production began in 2013.

The Deep Panuke Project, through its delivery of natural gas supplies by way of the M&NE 

pipeline system, provides a new source of natural gas supply to the same New England area 

market as the Downeast LNG Project, but can provide only about one half the volume of natural 

gas proposed by Downeast. The Deep Panuke Project does not provide any storage capacity, and 

would therefore not meet Downeast’s objectives of providing natural gas storage facilities. 

Therefore, the Deep Panuke Project would partially meet the objectives of the Downeast LNG 

Project, but it could not meet all the objectives. The Deep Panuke Project would also have its 

own set of environmental impacts, primarily from the development of offshore production 

facilities, but also from some onshore receiving facilities and associated pipelines. Therefore, we 
3.0 – Alternatives 3-22

do not believe that the Deep Panuke Project alone would be a reasonable alternative to the 

Downeast LNG Project.

It is possible that the Deep Panuke Project in combination with some other system alternative(s) 

could meet the objectives of the Downeast LNG Project. However, Downeast has proposed its 

project in anticipation of a need for additional natural gas volumes in New England beyond that 

which would be provided by other reasonably foreseeable energy projects. The Commission 

must evaluate the merits and associated environmental impacts of the proposed Downeast LNG 

Project. Despite the current weak economy and resulting short-term decrease in domestic energy 

consumption, future market demand could justify construction of the Downeast LNG Project, in 

addition to other proposed and approved projects. 

3.4 LNG TERMINAL SITE ALTERNATIVES 

3.4.1 Regional Review

Downeast conducted a Regional Site Selection (RSS) Study to determine a location or locations 

where an LNG import terminal could be sited to serve the New England market. The RSS Study 

evaluated prospective LNG terminal sites in coastal New England, including sites where new 

LNG import terminals have already been proposed by other developers. Site selection criteria 

included three primary categories: (1) Community Acceptance and Feasibility; (2) Marine 

Technical and Environmental Issues; and (3) Land Technical and Environmental Issues. For 

purposes of the RSS Study, an LNG import terminal project was assumed to have the following 

attributes: 

• a marine/river terminal for unloading double-hulled LNG vessels including pier, 

breasting and mooring dolphins, unloading platform, and cryogenic pipe LNG transfer 

system; 

• one or two LNG double-walled containment storage tanks with an approximate capacity 

of 160,000 m3; 

• regasification process equipment consisting of vapor handling systems and a closed-loop 

vaporization system capable of handling a sendout rate of 0.5 Bcfd; 

• a natural gas connector pipeline of a site-specific distance and market sendout size 

(estimated to be at least 24-inch-diameter); and 

• plant operation systems and facilities for safety control and management, office and 

employee support buildings, and stormwater control. 

Site acreage requirements varied according to site-specific conditions. Sites that were evaluated 

ranged from 15 acres to more than 100 acres. The RSS Study also considered alternative designs

that would minimize environmental impact or enhance safety and operation processes. Such 

alternatives included, but were not limited to, the following:

• alternative LNG storage tank designs and placement (e.g., partial or wholly excavated 

LNG tank storage placement, alternative containment type storage tank designs, and 

lower-profile, broader-based tank designs); 
3-23 3.0 – Alternatives

• alternative LNG unloading pier designs, including submerged or floating pipe transfer 

systems in high tidal fluctuation areas (most of study area); 

• alternative regasification systems including sole reliance on clean energy support 

industries and/or heat exchange systems associated with existing power generation 

plant(s) wishing to convert from coal to natural gas and elimination of heated water 

discharges; and 

• alternative off-site natural gas pipeline routes utilizing, as much as possible, existing road 

and/or railroad rights-of-way. 

Generally, the RSS Study excluded sites that would have entailed the following: 

• the need for a power generation plant as a heating “source” for LNG vaporization; 

• an open-loop vaporization system requiring the use of sea water or river water to reheat 

the LNG for send-out; and 

• a pier design and site locale that would require development or maintenance dredging to 

accommodate deep draft LNG vessels. 

Downeast’s RSS Study incorporated environmental siting criteria and a valuation ranking system 

using traditional siting criteria for a coastal LNG import terminal, as well as incorporating public 

and governmental interests as expressed in local media, trade publications, and public comment 

forums. The RSS Study also included results of numerous interviews conducted by Downeast 

throughout the study area covering a broad range of interests and stakeholders. Downeast 

weighted the site selection criteria in an attempt to be equally representative of community 

interests, engineering design limitations, and environmental protection. The selection criteria 

included evaluation of the distance to existing natural gas pipeline transmission infrastructure.

3.4.1.1 Results of RSS Study

Downeast’s RSS Study evaluated 27 sites along the coast of New England from New Haven, 

Connecticut to Robbinston, Maine (figures 3.4-1 and 3.4-2). The site selection evaluation matrix

showing results for each of the 27 sites is included in Appendix J of this EIS. The RSS Study 

ranked each of the sites using the selection criteria discussed above, which resulted in 14 of the 

27 sites, and 9 of the top 10 sites being located in Maine. Downeast’s proposed Mill Cove site, 

in Robbinston, Maine, was ranked as number 1. Two other potential sites in the Town of 

Robbinston were ranked 2 and 3, a site in Perry, Maine was ranked as number 4, and a second 

site in Perry, at Gleason Cove, was ranked as number 15.

The results of the RSS Study conducted by Downeast show there are a number of potentially 

suitable locations for new LNG import terminals along the New England Coast. The RSS study 

also identifies sites that would generally be considered unsuitable for development of an LNG 

import terminal. We generally agree with the results of the RSS study, however, we note that the 

selection criteria used by Downeast to rank each location incorporated some level of subjectivity 

in the weighting of each selection criteria. The rankings also factored in project and companyspecific criteria such as acceptable project cost, acceptable level of financial and regulatory risk, 

and existing or developing relationships with each community. The FERC staff has reviewed 

and analyzed the results of the RSS Study on the suitability of Downeast’s proposed site and 

whether another site(s) would be a preferred alternative to the proposed site.
Salem

Quincy

Neptune

Keyspan

Quonset

Sagamore

Downeast

New Haven

Distrigas

New London

Boston Harbor Islands

Weaver's Cove

Northeast Gateway

Brayton Point and East Providence

Maine

New Brunswick

Vermont

New Hampshire

Massachusetts

Nova Scotia

Connecticut

Augusta

Canaport

Montpelier

Fredericton

Quebec

Albany

Hartford

Saint John

Providence

Boston

Montreal

Figure 3.4-1 

Downeast LNG Project

Potential Non-Maine LNG Sites Evaluated in Coastal New England

Legend

Existing LNG Terminal

Potential LNG Sites

LNG Proposals

3-24
Site 1

Site 2

Site 3

Site 4

Site 5

Site 6

Site 7 Site 8

Site 9

Site 10

Site 11

Site 12 Site 13

Site 14

0 10 20 30 40 5

Miles

P:\Downeast-3253\Team Information\GIS\Spatial\MXD\Sendout_Pipeline_Reroute_Figures_082608\Figure3.4-2.mxd

Figure 3.4-2 

Downeast LNG Project

Potential LNG Terminals in Maine

Legend

Primary Maine Review Sites

3-25
3.0 – Alternatives 3-26

3.4.2 Local LNG Terminal Site Location Alternatives

Of the 27 potential sites for LNG terminals included in Downeast’s RSS Study, 14 sites were 

located in Maine (figure 3.4-2). Following is a brief description of the results of Downeast’s 

evaluation of each of these sites and our recommendation for each site.

3.4.2.1 Mill Cove Site, Robbinston, Maine

This site is Downeast’s proposed site and is identified as Site Number 3 on figure 3.4-2 and in 

table J-1 in Appendix J. Of the major site selection criteria evaluated by Downeast, Downeast 

has a purchase agreement for legal control of the site and exclusion zones (and have since 

purchased the site); there is sufficient depth and shipping channel width for LNG vessel access 

with no dredging required; potential impact on existing port activities was judged to be low; and 

it was judged to be compatible with existing and future marine and adjacent land uses. It is not 

in proximity to a large population center; degree of visibility was judged to be low; and there 

were judged to be no environmentally sensitive species present. Based on the review of site 

selection criteria, this site was chosen by Downeast as its proposed site.

3.4.2.2 Cannery Site, Robbinston, Maine

This site is an industrial site previously used for a sardine cannery located near the mouth of the 

St. Croix River in Robbinston, Maine, about 1.5 miles north of the proposed site, and is 

identified as Site Number 1 on figure 3.4-2 and in table J-1 in Appendix J. Of the major site 

selection criteria evaluated by Downeast, legal control by Downeast of the site and exclusion 

zones is feasible; there is sufficient depth and shipping channel width for LNG vessel access

with no dredging required; potential impact on existing port activities was judged to be low; and 

it was judged to be compatible with existing and future marine and adjacent land uses. It is not 

in proximity to a large population center; degree of visibility was judged to be low; and there 

were judged to be no environmentally sensitive species present. Compared to the proposed site, 

this site would require a slightly longer transit by LNG vessels through Passamaquoddy Bay, and 

would be slightly closer to the shoreline of St. Andrews across the St. Croix River, possibly 

increasing its visibility. Although this site was judged to be suitable for an LNG import terminal, 

we have not identified significant environmental advantages of the Cannery Site over the 

proposed site. Therefore, we do not recommend use of the Cannery Site alternative.

3.4.2.3 Gravel Pit Site, Robbinston, Maine

This site is located on the shoreline of the St. Croix River in Robbinston, Maine, about 1.0 mile 

north of the proposed site, and is identified as Site Number 2 on figure 3.4-2 and in table J-1 in 

Appendix J. Of the major site selection criteria evaluated by Downeast, legal control by 

Downeast of the site is feasible, but control of the entire exclusion zones would require purchase 

of some homes. There is sufficient depth and shipping channel width for LNG vessel access

with no dredging required; potential impact on existing port activities was judged to be low; and 

it was judged to be compatible with existing and future marine and adjacent land uses. It is not 

in proximity to a large population center; degree of visibility was judged to be low; and there 

were judged to be no environmentally sensitive species present. Compared to the proposed site, 

this site would require a slightly longer transit by LNG vessels through Passamaquoddy Bay, and 

would be slightly closer to the shoreline of St. Andrews across the St. Croix River. Although 

this site was judged to be suitable for an LNG import terminal, we have not identified significant 
3-27 3.0 – Alternatives

environmental advantages of the Gravel Pit Site over the proposed site. Therefore, we do not 

recommend use of the Gravel Pit Site alternative.

3.4.2.4 Coastal Site, Robbinston, Maine

This site is located on the shoreline of the St. Croix River in Robbinston, Maine, about 3 miles 

north of the proposed site, and is identified as Site Number 4 on figure 3.4-2 and in table J-1 in 

Appendix J. Of the major site selection criteria evaluated by Downeast, there are mixed parcels 

of land in the vicinity of the site and residences that may require purchase within the exclusion 

zones; there is sufficient depth and shipping channel width for LNG vessel access with no 

dredging required; potential impact on existing port activities was judged to be low; and it was 

judged to be compatible with existing and future marine and adjacent land uses. It is not in 

proximity to a large population center; degree of visibility was judged to be low; and there were 

judged to be no environmentally sensitive species present. Compared to the proposed site, this 

site would require a longer transit by LNG vessels through Passamaquoddy Bay, and would be 

slightly closer to the shoreline of St. Andrews across the St. Croix River. Although this site was 

judged to be suitable for an LNG import terminal, we have not identified significant 

environmental advantages of this alternative over the proposed site. Therefore, we do not 

recommend use of the Coastal Site alternative.

3.4.2.5 Gleason Cove Site, Perry, Maine

This site is located in Gleason Cove in Perry, Maine, about 6 miles south of Downeast’s 

proposed site, and is identified as Site Number 5 on figure 3.4-2 and in table J-1 in Appendix J. 

Of the major site selection criteria evaluated by Downeast, preliminary evaluation indicated

exclusion zones for the site may extend beyond U.S. Route 1; there is generally sufficient depth 

and shipping channel width for LNG vessel access, but some limited dredging might be required; 

potential impact on existing port activities was judged to be high; and it was judged to be 

compatible with existing and future marine and adjacent land uses. The site is in relatively close 

proximity to a large population center (Perry); degree of visibility was judged to be high; and 

there is endangered species habitat present. Compared to the proposed site, this site would 

include a 6-mile shorter transit by LNG vessels through Passamaquoddy Bay, and would not be 

visible from St. Andrews. Because the Gleason Cove Site would be in close proximity to a large 

population center, and due to potential impacts on port activities and impacts from dredging, we 

do not believe that the Gleason Cove Site offers a significant environmental advantage over the 

proposed site; therefore, we do not recommend use of the Gleason Cove Site alternative.

3.4.2.6 Estes Head Site, Eastport, Maine

This site is located on Estes Head on the shoreline of Broad Cove, at the southern tip of the 

peninsula in Eastport, Maine, about 13 miles south of Downeast’s proposed site, and is identified 

as Site Number 6 on figure 3.4-2 and in table J-1 in Appendix J. Of the major site selection 

criteria evaluated by Downeast, preliminary evaluation indicated exclusion zones for the site 

would cover nearby homes; there is sufficient depth and shipping channel width for LNG vessel 

access with no dredging required; potential impact on existing port activities was judged to be 

high; and it was judged to be compatible with existing and future marine uses. Potential impact 

on existing and future land use was judged to be high. The site is in close proximity to a large 

population center (Eastport); degree of visibility was judged to be high; and there is no 

endangered or sensitive species habitat present. This site would also require the sendout pipeline 
3.0 – Alternatives 3-28

to somehow exit the southern tip of the Eastport peninsula, which would require traversing 

Cobscook Bay to the south or west, or construction through Eastport to the north and then along 

or within Route 190 for about 6 miles before exiting the peninsula. Compared to the proposed 

site, this site would require an LNG vessel transit route about 10 miles shorter than required to 

reach the proposed site, and would avoid transit through Western Passage and Passamaquoddy 

Bay. Because the Estes Head Site would be in close proximity to homes and a large population 

center, and the sendout pipeline would have to cross Cobscook Bay or directly through Eastport, 

we do not believe the Estes Head Site is environmentally preferable to the proposed site, and 

therefore, we do not recommend use of the Estes Head Site alternative.

3.4.2.7 Quoddy Head Site, Lubec, Maine

This site is located adjacent to the Coast Guard station on the north side of West Quoddy Head in 

Lubec, Maine, about 18 miles south of Downeast’s proposed site, and is identified as Site 

Number 7 on figure 3.4-2 and in table J-1 in Appendix J. Of the major site selection criteria 

evaluated by Downeast, preliminary evaluation indicated there are nearby homes, but not within 

the exclusion zones for the site; there is sufficient depth and shipping channel width for LNG 

vessel access with no dredging required; potential impact on existing port activities was judged 

to be low; and it was judged to be compatible with existing and future marine uses. Potential 

impact on existing and future land use was judged to be low, with the exception of potential 

impact on recreational use of Quoddy Head State Park. The site is in close proximity to a large 

population center (Lubec); degree of visibility was judged to be high; and there is potentially 

sensitive species habitat present. LNG vessels would access this site from around the south side 

of Campobello Island via the Grand Manan Channel rather than around the north side as would 

be required for Downeast’s proposed site, thus avoiding entirely the need to traverse Western 

Passage and Passamaquoddy Bay. Because the Quoddy Head Site would be in close proximity 

to Lubec and due to the potential impact on Quoddy Head State Park, we do not believe the 

Quoddy Head Site would offer significant environmental advantages over the proposed site; 

therefore, we do not recommend use of the Quoddy Head Site alternative.

3.4.2.8 South Road Site, Lubec, Maine

This site is located along South Road near Woodward Point in Lubec, Maine, about 17 miles 

south of Downeast’s proposed site, and is identified as Site Number 8 on figure 3.4-2 and in 

table J-1 in Appendix J. Of the major site selection criteria evaluated by Downeast, preliminary

evaluation indicated there is sufficient land available at the site for the necessary exclusion 

zones; there is sufficient depth and shipping channel width for LNG vessel access with no 

dredging required; potential impact on existing port activities was judged to be low; and it was 

judged to be compatible with existing and future marine and land uses. The site is not in close 

proximity to a large population center; degree of visibility was judged to be low; and there is 

potentially sensitive species habitat present. LNG vessels would access this site from around the 

south side of Campobello Island via the Grand Manan Channel then through Lubec Channel, 

rather than around the north side of Campobello Island as would be required for Downeast’s 

proposed site, thus avoiding entirely the need to traverse Western Passage and Passamaquoddy 

Bay. Although this site was judged to be suitable for an LNG import terminal, we have not 

identified significant environmental advantages of the South Road Site over the proposed site. 

Therefore, we do not recommend use of the South Road Site alternative.
3-29 3.0 – Alternatives

3.4.2.9 Bailey’s Mistake Site, Lubec, Maine

This site is located within a bay called Bailey’s Mistake at the southern end of the township of 

Lubec, Maine, about 22 miles south of Downeast’s proposed site, and is identified as Site 

Number 9 on figure 3.4-2 and in table J-1 in Appendix J. Of the major site selection criteria

evaluated by Downeast, preliminary evaluation indicated there is sufficient land available at the 

site for the necessary exclusion zones and no houses are present within those zones; there is 

sufficient depth and shipping channel width for LNG vessel access with no dredging required; 

potential impact on existing port activities was judged to be low; and it was judged to be 

compatible with existing and future marine and land uses. The site is not in close proximity to a 

large population center; degree of visibility was judged to be low; and there is potentially 

sensitive species habitat present. LNG vessels would access this site from the Grand Manan 

Channel. Although this site was judged to be suitable for an LNG import terminal, we have not 

identified significant environmental advantages of the Bailey’s Mistake Site over the proposed 

site. Therefore, we do not recommend use of the Bailey’s Mistake Site alternative.

3.4.2.10 Cutler Former Navy Base Site, Cutler, Maine

This site is located within the former Cutler Navy Base on Little Machias Bay, in Cutler, Maine, 

about 36 miles south of Downeast’s proposed site, and is identified as Site Number 10 on 

figure 3.4-2 and in table J-1 in Appendix J. Of the major site selection criteria evaluated by

Downeast, preliminary evaluation indicated there is sufficient land available at the site for the 

necessary exclusion zones and no houses are present within those zones; however, control would 

have to be obtained from the Navy. There is sufficient depth and shipping channel width for 

LNG vessel access with no dredging required; potential impact on existing port activities was 

judged to be medium; and it was judged to be compatible with existing and future marine and 

land uses, although it would be in close proximity to high recreational use areas (Cross Island 

NWR). The site is not in close proximity to a large population center; degree of visibility was 

judged to be medium; and there is potentially sensitive species habitat present. LNG vessels 

would access this site from the Grand Manan Channel. Although this site was judged to be 

suitable for an LNG import terminal, we have not identified significant environmental 

advantages of the Cutler Navy Base Site over the proposed site. In addition, Cutler Residential 

Development, LLC has constructed a residential community on the site, Beachwood Bay Estates, 

consisting of 62 condominium units and associated amenities. Therefore, we do not recommend 

use of the Cutler Navy Base Site alternative.

3.4.2.11 Gouldsboro Former Navy Base Site, Gouldsboro, Maine

This site is located on the former Navy Base on Prospect Harbor in the Town of Gouldsboro, 

Maine, about 70 miles south of Downeast’s proposed site, and is identified as Site Number 11 on 

figure 3.4-2 and in table J-1 in Appendix J. Of the major site selection criteria evaluated by

Downeast, preliminary evaluation indicated there is sufficient land available at the site for the 

necessary exclusion zones and no houses are present within those zones; however, control would 

have to be obtained from the U.S. government. There is sufficient depth and shipping channel 

width for LNG vessel access with no dredging required; an existing dock for large ships; 

potential impact on existing port activities was judged to be medium; and it was judged to be 

compatible with existing and future marine and land uses, although it would be in close 

proximity to high recreational use areas in Prospect Harbor. The site is not in close proximity to 
3.0 – Alternatives 3-30

a large population center; degree of visibility was judged to be medium; and there is potentially 

sensitive species habitat present. LNG vessels would access this site directly from the Gulf of 

Maine. Although this site was judged to be suitable for an LNG import terminal, we have not 

identified significant environmental advantages of the Gouldsboro Navy Base Site over the 

proposed site that would justify using the Gouldsboro Navy Base Site instead of the proposed 

site. In addition, Cianbro Corp. declined to pursue an LNG terminal on the former Navy base.

The Navy intends to transfer a portion of the site to the National Park Service, and another 

portion is being handed over to the town of Gouldsboro, Maine. There have also been 

discussions for a number of years about constructing an Aquaculture Business Park on the site of 

the former Navy communications center, which could house up to 15 businesses involved in 

land-based commercial aquaculture activities. Therefore, we do not recommend use of the 

Gouldsboro Navy Base Site alternative.

3.4.2.12 Sears Island Site, Searsport, Maine

This site is located on former Navy property on Sears Island in Penobscot Bay in the Town of 

Searsport, Maine, about 95 miles south of Downeast’s proposed site, and is identified as Site 

Number 12 on figure 3.4-2 and in table J-1 in Appendix J. The site is currently owned by the

state. Of the major site selection criteria evaluated by Downeast, preliminary evaluation 

indicated there is sufficient land available at the site for the necessary exclusion zones and no 

houses are present within those zones; however, control would have to be obtained from the 

state. There is sufficient depth and shipping channel width for LNG vessel access with no 

dredging required; potential impact on existing port activities was judged to be medium; and it 

was judged to be compatible with existing and future marine and land uses, although it would be 

in close proximity to high recreational use areas in Penobscot Bay and shoreline areas. The site 

is not in close proximity to a large population center; degree of visibility was judged to be 

medium, but with a high number of potential viewers; and there is potentially rare species habitat 

present. To reach this site, LNG vessels would have to traverse about 25 miles up Penobscot 

Bay to the mouth of the Penobscot River. Although this site was judged to be suitable for an 

LNG import terminal, we have not identified significant environmental advantages of the Sears 

Island Site over the proposed site. Therefore, we do not recommend use of the Sears Island Site 

alternative.

3.4.2.13 Mack Point Site, Searsport, Maine

This site is located on Searsport Harbor in Penobscot Bay, across from Sears Island, in Searsport, 

Maine, about 95 miles south of Downeast’s proposed site. The site is identified as Site Number 

13 on figure 3.4-2 and in table J-1 in Appendix J. The site is currently an industrial port operated

by Sprague Energy and the Montreal, Maine, and Atlantic Railway. Of the major site selection 

criteria evaluated by Downeast, preliminary evaluation indicated there is sufficient land available 

at the site for the necessary exclusion zones and no houses are present within those zones; 

however, control would have to be obtained from the current operators. There is sufficient depth 

and shipping channel width for LNG vessel access; however, dredging would be required for a 

turning basin to accommodate LNG vessels. Potential impact on existing port activities was 

judged to be medium, and it was judged to be compatible with existing and future marine uses. 

Potential impact on existing and future land use of the site and surrounding areas was judged to 

be high, and it would be in close proximity to high recreational use areas in Penobscot Bay and 

shoreline areas. The site is not in close proximity to a large population center; degree of 
3-31 3.0 – Alternatives

visibility was judged to be medium; and there were no known rare or sensitive species present. 

To reach this site, LNG vessels would have to traverse about 25 miles up Penobscot Bay to near 

the mouth of the Penobscot River. Although this site was judged to be suitable for an LNG 

import terminal, we have not identified significant environmental advantages of the Mack Point 

Site over the proposed site. Therefore, we do not recommend use of the Mack Point Site 

alternative.

3.4.2.14 Harpswell Former Navy Site, Harpswell, Maine

This site is located on a former Navy fuel depot facility on Harpswell Neck in Casco Bay in the 

Town of Harpswell, Maine, about 180 miles south of Downeast’s proposed site. The site is 

identified as Site Number 14 on figure 3.4-2 and in table J-1 in Appendix J. The site is currently

controlled by the Town of Harpswell. Of the major site selection criteria evaluated by 

Downeast, preliminary evaluation indicated there is sufficient land available at the site for the 

necessary exclusion zones and no houses are present within those zones; however, control would 

have to be obtained from the town. There is sufficient depth and shipping channel width for 

LNG vessel access with no dredging required. Potential impact on existing port activities was 

judged to be medium, and it was judged to be compatible with existing and future marine uses, 

with an existing dock present. Development of the site for an LNG terminal was judged to be 

consistent with existing and potential future land use, although it would be in close proximity to 

high recreational use areas in Casco Bay and surrounding shoreline areas. The site is not in close 

proximity to a large population center; degree of visibility was judged to be medium; and there 

are potential habitat for sensitive species present. To reach this site, LNG vessels would have to 

traverse about 8 miles through Casco Bay. This site was the site of a previously planned LNG 

terminal project (Fairwinds LNG), which was cancelled in March 2004 after the Town of 

Harpswell voted against leasing the property to the project proponent. Although this site was 

judged to be suitable for an LNG import terminal, we have not identified significant 

environmental advantages of the Harpswell Former Navy Site over the proposed site. 

In addition, because a previous LNG import project was proposed for the site but denied by the 

Town of Harpswell, the feasibility of this site is questionable. Therefore, we do not recommend 

use of the Harpswell Former Navy Site alternative.

3.5 MARINE FACILITY ALTERNATIVES

Downeast evaluated five alternative designs for the marine unloading terminal. Each alternative 

would meet the same general facility requirements including a single berth able to unload LNG 

vessels from 70,000 m3 to 220,000 m3 capacity; the unloading platform would be capable of 

supporting the necessary LNG unloading and vapor return equipment; and all marine facilities 

would be located within the site’s conceptual property limits determined from imaginary lines 

extending perpendicular from the land site property borders. The marine facility alternatives that 

were evaluated are discussed below.

3.5.1 Long Trestle – Straight Alignment (Proposed Design)

Downeast’s proposed marine facility design consists of a long trestle with a straight alignment. 

This alternative would include locating the unloading platform so that LNG vessels would have 

access to a natural water depth of at least 45 feet and extending an above-water access trestle 

from the shore to the unloading platform. The trestle would be linear, extending in a straight line 
3.0 – Alternatives 3-32

from the shoreline about 3,862 feet. The trestle would provide access for personnel and vehicle 

traffic as well as for the piping to transport the product to the LNG storage tanks. Preliminary 

information obtained by Downeast indicates seabed composition would be rock along about twothirds of the trestle length, with soft bottom for the remainder. Where the seabed is rock, trestle 

support piles would require rock-socketed pile foundations, and traditional driven piles could be 

used for soft bottom.

Advantages of the proposed design include access to LNG facilities, pipelines, and utilities for

operation, maintenance, and emergency response vehicles and personnel that would be provided 

by a road along the trestle from the onshore facility to the waterside facilities. This design would 

also avoid the need for dredging and the associated environmental impacts, since the trestle 

would extend the necessary distance from shore to reach the natural water depth of 45 feet. 

Another advantage of this alternative is that it is a traditional design in common use for other 

LNG facilities, and has a proven record of performance and constructability. Also, this 

alternative may increase public safety since it would place the unloading platform at a distance 

from shore that would be far removed from an ignition source onshore should there be a spill 

event on the unloading platform or LNG vessel.

Disadvantages of this alternative would include visual and noise impacts on the surrounding

areas because of the length of the trestle extending from the shoreline. This impact may be 

greatest for residents located on North Mill Cove, as well as across Passamaquoddy Bay in 

St. Andrews. Visual impacts would include view of the trestle during the day, as well as lighting 

on the trestle at night. Visual impacts are discussed further in section 4.7.4. In addition, the 

COE, New England District, has published guidelines for the placement of fixed and floating 

structures in navigable waters of the United States that are regulated by the New England District 

(COE 1996). The guidelines suggest that no structures on a linear waterway should extend more

than 25 percent of the waterway width at mean low water. The proposed pier design appears to 

extend just over 25 percent of the width of the St. Croix River/Passamaquoddy Bay at the Project 

location, depending on where the width is measured between the irregular shoreline on both the 

United States and Canadian sides of the waterway. The guidelines are not policy or regulation, 

and would typically not result in COE permit denial. In its review of the project-specific section 

404/401 permit for the Project, the COE would determine if the proposed pier design would be 

acceptable for the site-specific conditions. 

3.5.2 Long Trestle – Bent Alignment

This alternative would involve a trestle similar to the proposed alternative, except the trestle 

would include a bend mid-way along its length and would be about 440 feet longer than the 

proposed straight trestle. The alternative trestle would begin by extending perpendicular to the 

shoreline for about 2,200 feet in a slightly more northeast direction than the proposed trestle. 

This portion of the trestle would be shoreward of the mean low water line. The trestle would 

then bend to the east for about 2,100 feet until reaching a natural water depth of at least 45 feet. 

This alternative would place the end of the trestle and the LNG unloading platform about 

1,900 feet northwest of the proposed location. Downeast evaluated this alternative partly to 

reduce the length of trestle that would be within the navigational waterway to address the New 

England COE navigational guideline regarding pier length into linear waterways (COE 1996). 

Downeast also evaluated the alternative because it would require less rock-socketed pile 
3-33 3.0 – Alternatives

foundations, and was also initially believed to allow greater accommodation of weir fishing 

south of the trestle than would be allowed by the proposed trestle placement.

The primary advantages of a long trestle with bent alignment would be the same as for the 

proposed trestle design: access to LNG facilities, pipelines, and utilities for operation, 

maintenance, and emergency response vehicles and personnel that would be provided by a road 

along the trestle from the onshore facility to the waterside facilities. This alternative would 

avoid the need for dredging and the associated environmental impacts, since the trestle would 

extend from shore the necessary distance to reach natural water depth of 45 feet. This alternative 

is a traditional design in common use for other LNG facilities, has a proven record of 

performance and constructability, and may also increase public safety since it would place the 

unloading platform at a distance from shore that would be far removed from an ignition source 

onshore should there be a spill event on the unloading platform or LNG vessel. An advantage of 

this alternative over the proposed trestle design is that the alternative would traverse less hard 

rock bottom, which would allow greater use of traditional piles and less use of rock-socketed pile 

foundations. Traditional piles can be installed faster and with less bottom disturbance than rocksocketed piles. Another advantage of this alternative is that it would reduce visual and noise 

impacts for residents across Passamaquoddy Bay in St. Andrews by increasing the distance from 

the pier.

This alternative would place the trestle and unloading platform much closer to the shoreline 

along the north shore of Mill Cove; therefore, potential visual and noise impacts on the Mill 

Cove shoreline areas would be greater for this alternative than for the proposed trestle design. 

This alternative trestle design would be less than 500 feet from the shoreline of Mill Cove where 

the trestle would bend to the northeast near Mill Point. By comparison, at the closest point the 

proposed alignment would be about 1,700 feet from Mill Point. Because this alternative would 

be about 440 feet longer than the proposed trestle design, it would also require more pilings and 

associated bottom disturbance than the proposed design. Downeast initially felt the bent trestle 

design may have less impact on weir fishing than the proposed straight trestle design. However, 

Downeast states that based on discussions with weir fishermen, the bent trestle design would not 

be expected to reduce potential impact on weir fishing over the proposed straight trestle design. 

We do not believe the potential advantages of this alternative outweigh the disadvantages, and do 

not believe this alternative would be environmentally preferable over the proposed trestle design. 

Therefore, we do not recommend use of the alternative using a long trestle with a bent alignment.

3.5.3 Short Trestle with Dredging

As an alternative to extending the trestle the full distance from shore necessary to reach the 

natural water depth of 45 feet, Downeast evaluated shorter trestle lengths combined with 

dredging. Downeast evaluated trestle lengths that would be 100, 500, and 1,000 feet shorter than 

the proposed long trestle. The area of dredging and volume of dredged material would be 

necessarily greater as the trestle is shortened. Based on estimates of bottom type, dredging 

necessary for this alternative would also require underwater blasting. Except for the shorter 

length, the trestle design of this alternative would be similar to the proposed design. 

The primary advantages of a shorter trestle with dredging would include those of the proposed 

trestle design – access to LNG facilities, pipelines, and utilities for operation, maintenance, and 

emergency response vehicles and personnel that would be provided by a road along the trestle 
3.0 – Alternatives 3-34

from the onshore facility to the waterside facilities. This alternative would be a traditional 

design in common use for other LNG facilities, and has a proven record of performance and 

constructability. An additional advantage of this alternative over the proposed trestle design is 

that the alternative would extend a shorter distance from shore and therefore may be less visible 

from certain areas along the north shoreline of Mill Cove and from St. Andrews. The alternative 

would also extend a shorter distance into navigable waters, which would be in line with the COE 

navigational guidance (COE 1996), and could result in less impact on marine navigation. The

alternative would also require fewer piles than the proposed trestle design because of its shorter 

length.

The primary disadvantages of this alternative would include those of the proposed trestle design 

– visual and noise impacts on onshore communities. Because the trestle under this alternative 

would be shorter, these impacts could be somewhat less than the proposed design depending on 

the visual vantage point onshore. However, even if the trestle were 1,000 feet shorter than the 

proposed design, the trestle would extend about 2,800 feet from shore and would be visible from 

most locations along the shoreline of Mill Cove that currently have a view of the cove. 

Therefore, this alternative would not significantly reduce visual impacts. Noise impacts on 

onshore areas from activities on the LNG vessels and unloading platform would be slightly 

higher for this alternative than the proposed trestle design because the noise sources would be 

closer to shore. Another major disadvantage of this alternative is that it would require dredging 

and blasting in order to create the water depth necessary for LNG vessels to reach the LNG 

unloading platform at the end of the shorter trestle. Dredging and blasting would result in shortterm impacts on the marine bottom habitats and surrounding aquatic resources from bottom 

disturbance, turbidity, noise, and settling of sediment on adjacent bottom habitats. Long-term 

impacts could also result from periodic maintenance dredging required to maintain the depth of 

the channel.

During scoping, we received a comment that the EIS should also evaluate use of shallower draft 

vessels that may allow use of a shorter trestle design but without the need for dredging. 

Downeast’s proposed action is based on a depth of the berth and channel of 45 feet to allow for 

LNG vessels from 70,000 m3 to 220,000 m3 capacity. Draft of LNG vessels of this range 

generally varies by less than 2 feet. Therefore, some reduction in the amount of dredging could 

be achieved by limiting the project to smaller vessels. However, there are only a small number 

of the smallest sized LNG vessels in the worldwide fleet, with the most common sized LNG 

vessels in the range of 125,000 to 150,000 m3

. We do not believe the potential advantages of the 

short trestle alternative, with or without dredging, outweigh the disadvantages, and do not 

believe that this alternative would be environmentally preferable over the proposed trestle 

design. Therefore, we do not recommend use of the alternative using a short trestle.

3.5.4 Sea Island with Submarine Pipelines

This alternative would eliminate the trestle entirely, and instead would involve building the LNG 

unloading platform as a sea island with no physical above-water connection to the shore. The 

unloading platform would be placed at the same location as the proposed design in sufficient 

water depth to accommodate LNG vessels without the need for dredging. With this alternative, 

personnel would access the LNG unloading platform and berth by small marine craft. This 

alternative would require construction of a pier for small craft and tugs that would be usable at 

all tides, which would extend an estimated 1,000 feet from shore. The piping which carries the 
3-35 3.0 – Alternatives

LNG product to the shore would be located as a submarine type unit. A trench would be 

excavated for the submarine pipelines for most of the distance. At the shore interface, the 

pipeline would be installed by HDD and brought up into the LNG storage tank area to avoid an 

approximately 60-foot-high bluff along the shoreline.

The primary advantage of this alternative is that it would eliminate the visual impact associated 

with the above-water trestle. When an LNG vessel is not at berth, the visible components of the 

marine facilities would be the LNG unloading platform, which at its closest point would be about 

3,862 feet from shore, and a pier for small craft and tugs. Downeast states that by eliminating 

the trestle, this alternative may also provide for continued use of the existing fish weirs in 

Mill Cove.

The primary disadvantage of this alternative is the significant amount of dredging and blasting 

that would be necessary to excavate the trench for the nearly 4,000 feet of submerged pipelines 

between the LNG unloading platform and shore. Dredging and blasting would result in bottom 

disturbance, turbidity, noise, and settling of sediment on adjacent bottom habitats. This 

alternative would limit access to the LNG unloading platform and berth for operation, 

maintenance, repair, and emergency response equipment and personnel. This alternative would 

provide no access for trucks or cranes, and access by other equipment would be by barge. 

Personnel access would be by multiple daily shuttles of a small launch to and from shore, with a 

harbor tug likely required during severe weather conditions. Access to the submerged pipelines 

for maintenance and repair could take significantly longer than for pipelines on the proposed

aboveground trestle. Downeast states that the limited access allowed by this alternative would 

substantially reduce operational flexibility.

Because the sea island alternative with submerged pipelines would result in a significant amount 

of blasting and dredging for installation of the pipelines, and because this impact would be 

avoided by use of the proposed pier design, we do not believe this alternative would provide an 

environmental advantage over the proposed design. In addition, while this alternative would 

eliminate the visual impact of the trestle, it would still include visual impact from approximately 

1,000 feet of new pier. Therefore, we do not recommend use of the sea island alternative with 

submerged pipelines.

3.5.5 Sea Island with Pipelines in Directionally Drilled Tunnel

This alternative would be similar to the sea island alternative with submarine pipelines, as it 

would eliminate the trestle entirely and would involve building the LNG unloading platform as a 

sea island with no physical above-water connection to the shore. However, for this alternative, 

the pipelines from the LNG unloading platform to the onshore LNG storage tanks would be 

installed in a directionally drilled tunnel rather than by trenching. The tunnel would be ten feet 

in diameter, which is beyond the size for typical HDD technology. The tunnel would be 

constructed by a tunnel boring machine or conventional horizontal drill and blast. The unloading 

platform would be placed at the same location as the proposed design in sufficient water depth to 

accommodate LNG vessels without the need for dredging. Personnel would access the LNG 

unloading platform and berth through the tunnel. This alternative would require construction of 

a pier for small craft and tugs that would be usable at all tides, which would extend an estimated 

1,000 feet from shore. This alternative would include construction of one tunnel for LNG 

product pipelines. 
3.0 – Alternatives 3-36

The primary advantage of this alternative is the same as for the sea island with submerged 

pipelines – the visible components of the marine facilities would be substantially less than the 

proposed trestle, and it would eliminate the visual impact associated with the above-water trestle. 

When an LNG vessel is not at berth, the visible components of the marine facilities would be the 

LNG unloading platform, which at its closest point would be about 3,862 feet from shore, and 

approximately 1,000 feet of pier for small craft and tugs. Downeast states that by eliminating the 

trestle, this alternative may also provide for continued use of the existing fish weirs in Mill Cove. 

This alternative would also require no dredging or blasting, either for deepening of the LNG 

berth or for installation of pipelines.

The primary disadvantage of this alternative is limited access to the LNG unloading platform and 

berth for operation, maintenance, repair, and emergency response equipment and personnel. 

This alternative would provide for no access for trucks or cranes, and any access by other large 

equipment would be by barge. Downeast states that the limited access allowed by this 

alternative would reduce operational flexibility.

Because the pipelines in this alternative would be installed in a directionally drilled tunnel rather 

than by blasting and dredging, environmental impacts of this alternative would be substantially 

less than impacts from the dredging that would be required for the sea island alternative with 

submarine pipelines. However, Downeast’s marine geotechnical investigation indicated that the 

subsurface material underlying the trestle area is bedrock from the shore out to approximately 

1,000 feet and then becomes soft marine sediment deposits the remainder of the distance out to 

the unloading platform. The sediments are very soft and could not support the superimposed 

weight of a tunnel without significant settlement and a high likelihood of failure. Because 

geotechnical investigations show that underlying sediments could not support the weight of a 

tunnel, we have eliminated this alternative from further consideration. 

3.6 LNG VAPORIZATION ALTERNATIVES

LNG is vaporized, or returned to natural gas, by heating the LNG; there are a number of 

alternative LNG vaporization processes currently available. Downeast’s proposed design 

includes the use of SCVs for LNG vaporization. In addition to SCVs, Downeast analyzed 

potential use of open rack vaporizers (ORVs), heat integrated ambient air vaporizers (HIAAV),

and shell and tube vaporizers (STVs) with low temperature heat transfer fluid (HTF).

3.6.1 Submerged Combustion Vaporizers (Proposed Vaporization)

SCVs are composed of stainless steel tubes that are submerged in a water bath containing a 

submerged combustion chamber. The combustion chamber burns a low-pressure natural gas and 

is supplied with air via an electric air blower. The heated exhaust from the combustion chamber 

is sent to the water bath containing the stainless steel tubes with the LNG flowing inside and 

transfers the heat needed to vaporize the LNG. SCV technology is a closed loop system that 

does not require water intake and discharge; however, condensate water is produced from the 

combustion process. The primary advantages of the SCV technology are its compact size, high 

thermal efficiency, closed loop water use, and ease of operation and maintenance. 

Disadvantages are the release of regulated air emissions generated during the combustion 

process, and potential discharge of condensate water if it is not reused. Downeast selected SCVs 

as its proposed regasification system based on the suitability of the system to the site location
3-37 3.0 – Alternatives

and terminal operational requirements, and based on its desire to use a closed loop system to 

minimize impact on the marine aquatic environment.

3.6.2 Open Rack Vaporizers

ORVs are widely used where LNG facilities are located in close proximity to a readily available 

supply of seawater. They are made of aluminum alloy and use seawater as a sole source of heat. 

Pumps are used to move the seawater from an overhead distributor over long-finned aluminum 

panels with the LNG flowing inside. Vaporization of the LNG is accomplished by transferring 

heat from the seawater to the LNG. As the seawater passes over the aluminum panels, it is 

cooled and collected in troughs at the bottom of the ORV before it is discharged back into the 

water source. Vaporization effectiveness depends on seawater temperature, which must be at 

least 46°F and preferably warmer. The primary advantages of ORV technology are its 

operational flexibility, ease of maintenance, stable heat transfer, and limited fuel consumption 

and air emissions. The primary disadvantages of this technology are the withdrawal and 

discharge of large volumes of seawater, and potential impingement and entrainment of 

organisms during withdrawal and thermal impacts on the receiving waterbody during discharge. 

This technology also has limited effectiveness in northern climates where the source of water is 

below 46°F for much of the year. Because this vaporization technology would require use of 

large volumes of seawater, and the withdrawal and discharge of seawater would involve potential 

additional environmental impacts on aquatic systems, we do not believe that use of ORVs would 

provide an environmental advantage over the proposed use of SCVs, and therefore do not 

recommend use of ORV vaporization for the Downeast LNG Project.

3.6.3 Combined Loop (SCVs and ORVs)

It is also possible to vaporize LNG using a combined loop system that incorporates both SCV 

and ORV technology. For example, this could be used in northern climates where ORV 

technology could be used when water temperatures are above 46°F, and SCV used for the 

remainder of the year. Such a combined system would require additional space on site to 

incorporate both systems. Because a combined loop system at the proposed Downeast LNG site 

would require seawater intakes during operation using ORV technology, we do not believe this 

alternative would provide an environmental advantage over the proposed use of SCV, and 

therefore, we do not recommend use of a combined loop vaporization system for the Downeast 

LNG Project.

3.6.4 Heat Integrated Ambient Air Vaporizers

HIAAVs take heat from the surrounding air and transfer it to vaporize LNG as it passes through 

an exchanger. The natural convection of air and subsequent heat transfer rate would be enhanced 

by the height of the exchanger. HIAAVs are set up in trains and each train is equipped with four 

vaporizers. The primary advantages of the HIAAV technology are the use of surrounding air in 

the heating process, little to no emissions during the warmer months, no noise generation from 

heating fans, and no use of intermediate fluids or secondary exchangers. The primary 

disadvantages with this vaporization technology are its sensitivity to changes in air temperature, 

humidity, and wind speed; potential to create fog on warm days; production and disposal of 

water; and the need for a backup system during cooler months. Because of these potential 

disadvantages, we do not believe use of HIAAV would provide an environmental advantage over 
3.0 – Alternatives 3-38

use of SCVs, and therefore do not recommend use of HIAAV vaporization for the Downeast 

LNG Project.

3.6.5 Shell and Tube Vaporizers

STVs are compact vaporizers with a high heat transfer coefficient. LNG is vaporized by passing 

the LNG through a series of tubes that are surrounded by an external fluid. This external fluid 

could consist of seawater in a single-pass seawater system or an intermediate fluid consisting of 

a water and glycol mix, propane, or ammonia in a closed loop system. In a single-pass seawater 

system, the seawater would be contained within the shell. The LNG would enter vaporizer tubes 

at a bottom channel cover, pass through an exchanger, and exit at a top channel cover. Seawater 

would enter through the side of the exchanger at an upper and lower inlet where it would be 

circulated over the tubes with the LNG flowing inside and warming it to a gaseous state where it 

would exit at the top of the shell. STV technology using a single-pass seawater system requires 

an abundant supply of seawater. The primary disadvantages of this technology are fouling and 

maintenance of the shell and tube exchangers, frequent periods of downtime for maintenance, 

potential freezing of the shell and tubes, and impingement and entrainment of marine organisms. 

We do not recommend use of this alternative for these reasons.

Although alternative LNG vaporization technologies exist, use of these technologies for the 

Downeast LNG Project would likely result in a similar level of (although different) 

environmental impacts, and in some cases (ORV and STV) potentially greater environmental 

impacts. We believe that use of alternative LNG vaporization technologies for the Downeast 

LNG Project would not provide any significant environmental advantage over the proposed use 

of SCVs, and therefore do not recommend use of an alternative vaporization technology.

3.7 LNG VESSEL DESIGN ALTERNATIVES TO REDUCE WATER USAGE

NOAA Fisheries requested that the EIS include an analysis of alternative LNG vessel designs 

that could reduce water usage, similar to alternative vessel designs in use for the Northeast 

Gateway and Neptune offshore LNG projects (see section 3.3.2.1 of this EIS). LNG vessels 

calling on the Downeast LNG terminal would be at the terminal an average of about 21 hours. 

While at the terminal, each vessel of approximately 145,000 m3 could cycle up to 40 million 

gallons of seawater (vessel). This water would be used for engine cooling and for ballast water 

(one-time use of 15 million gallons). 

The LNG vessels calling on the Northeast Gateway and Neptune offshore LNG ports would have 

similar seawater usage requirements while at the offshore port facilities (estimated to be eight 

days per visit). However, unlike the typical LNG vessels that would call on the Downeast LNG 

terminal, the vessels calling on the Northeast Gateway and Neptune ports are specially designed 

to include on-board regasification of LNG. The requirements of on-board regasification of LNG 

provide unique opportunities for use of seawater heat exchangers between the LNG 

regasification system and normal vessel operational cooling systems. Such heat exchangers 

enable the on-board regasification vessels to operate under a closed-loop heat recovery and 

exchange mode while active regasification of LNG is underway, which reduces average daily 

water use while at port from approximately 56 mgd to 5 mgd.
3-39 3.0 – Alternatives

Because the proposed Downeast LNG terminal is designed for accepting and storing natural gas

in its liquid phase, the LNG vessels calling on the terminal would be of conventional design and 

not equipped with regasification system components such as those described above. Therefore, 

the opportunity to utilize alternative LNG vessel designs are not available to the Downeast LNG 

Project.

3.8 PIPELINE LOCATION ALTERNATIVES

In evaluating alternatives for Downeast’s sendout pipeline, we reviewed both route alternatives 

and route variations. We examined route alternatives that could reduce or avoid impact on 

environmentally sensitive resources such as special-use areas, waterbodies, and extensive 

wetlands. Route alternatives generally follow a different alignment for a long segment of the 

proposed route. Route variations differ from route alternatives in that they are generally short 

deviations identified to avoid or reduce construction impacts on specific, localized resources that 

may include cultural resource sites, residences, site-specific terrain conditions, or specific 

landowner concerns.

3.8.1 Pipeline Route Alternatives

3.8.1.1 Alternatives Affecting the Moosehorn NWR

We evaluated three pipeline route alternatives that would each cross a portion of the Moosehorn 

NWR. These alternatives are generally described below and shown in Appendix K figure K-1. 

However, because of the FWS’s decision denying Downeast’s application request for a right-ofway across NWR lands, these alternatives are not considered feasible, and therefore are not 

analyzed in detail in this EIS.

3.8.1.2 Original Proposed Route (Option 4)

Downeast’s original proposed route, called Option 4 in Downeast’s application, would cross 

3.5 miles of the Moosehorn NWR. This route was included in Downeast’s application to the 

FWS requesting a right-of-way across refuge lands, and which was denied by the FWS based on 

its determination that the pipeline is not a compatible land use. Because of this determination, 

we believe this is not a reasonable alternative and have not analyzed it in further detail in 

this EIS.

3.8.1.3 Moosehorn/Railway Alternative

The Moosehorn/Railway Alternative, called Option 1 in Resource Report 10 of Downeast’s 

application, was Downeast’s original preferred route for the sendout pipeline. The alternative 

would be within an inactive Maine Central railway grade for about 9.2 miles, and would cross 

about 6.5 miles of the Moosehorn NWR. Downeast determined it would not be able to secure an 

irrevocable lease from the current owner of the rail right-of-way, the Maine Department of 

Transportation (Maine DOT). Without an irrevocable lease, the railway must be kept available 

for possible future reactivation, in which event Downeast would be required to relocate the 

pipeline and disrupt service. Therefore, Downeast dropped this route as its preferred route. 

Because this alternative would require crossing the Moosehorn NWR and the FWS has 

determined that a pipeline crossing of the refuge is not a compatible land use, we believe this is 

not a reasonable alternative and have not analyzed it in further detail in this EIS.
3.0 – Alternatives 3-40

3.8.1.4 Howard Lake Alternative

The Howard Lake Alternative is a segment of the pipeline route alternative Downeast identified 

as Option 2 in its application. The alternative would begin at MP 2.2 of the proposed route and 

turn west-northwest following existing secondary and unimproved roads and a portion of 

inactive Maine Central railway grade for about 9.3 miles, ending within the Moosehorn NWR. 

The advantage of this alternative is that it would be about 3.8 miles shorter than the 

corresponding segment of proposed route, thus reducing the area of construction disturbance. 

However, the alternative would cross about 3.0 miles of the Moosehorn NWR. Because this 

alternative would require crossing the Moosehorn NWR and the FWS has determined that a 

pipeline crossing of the refuge is not a compatible land use, we believe this is not a reasonable 

alternative and have not analyzed it in further detail in this EIS. 

3.8.1.5 Western Alternative

The Western Alternative is a segment of the pipeline route alternative Downeast identified in its 

application as Option 5. The Western Alternative would entirely avoid crossing the Moosehorn 

NWR. 

The Western Alternative would begin at the Downeast LNG terminal at MP 0.0 of the proposed 

route, and would follow U.S. Route 1 north for about 0.5 mile, turn southwest and follow Ridge 

Road for about 5.2 miles to the intersection with South Meadow Road, and then follow South 

Meadow Road for about 4.6 miles. The alternative would then turn west/northwest for about 

20.5 miles along new right-of-way before ending at the proposed pipeline route at MP 28.2 at the 

existing M&NE pipeline at the crossing of U.S. Route 1 northwest of Woodland. In this section, 

the alternative would cross the Dennys River, pass south and then west of Meddybemps Lake, 

and would cross the western edge of the area known as Meddybemps Heath. The alternative is 

shown on figure K-1 in Appendix K. Table 3.8.1.5-1 compares major environmental 

characteristics of the Western Alternative with the corresponding segment of proposed route.

TABLE 3.8.1.5-1

Comparison of the Western Alternative with the Corresponding Segment of Proposed Route

Environmental Factor Corresponding Segment 

of Proposed Route

Western

Alternative

Total Length (miles) 27.0 30.8

Length Adjacent to Existing Rights-of-Way (miles) 9.8 a/ 10.3

Construction Disturbance (acreage) b/ 245.4 280.0

Wetlands Affected (acres) c/ 23.28 52.8

Waterbodies Crossed (number) 24 12

Length within Moosehorn NWR (miles) 0.0 0.0

Residences within 50 feet of Construction Work Area (number) 2 53

a/ Does not include placement adjacent to a planned new electric transmission right-of-way between MPs 0.2 and 11.6.

b/ Based on nominal right-of-way width of 75 feet.

c/ Determined from NWI mapping for alternative, and field delineation for corresponding segment of proposed route.

The primary advantage of the Western Alternative is that it would cross 12 fewer waterbodies 

than the corresponding segment of the proposed route, including avoiding a crossing of the 
3-41 3.0 – Alternatives

St. Croix River. The alternative would also avoid the Moosehorn NWR. The disadvantages of 

the Western Alternative include longer length, greater wetland impact, and more residences 

within 50 feet of the construction right-of-way than the corresponding segment of proposed 

route. In addition, as mapped by Downeast, the 10.3 miles of the alternative that would be 

adjacent to existing rights-of-way would be within or immediately adjacent to roadways. It is 

unlikely that pipeline construction could be accomplished for such long distances within these 

roadways as envisioned by Downeast, and that an offset from these roadways would be required 

to avoid residential and other developments and to minimize traffic disruptions.

Also, if the Downeast LNG Project were approved, EMEC would construct a 69-kV electric 

transmission line from its existing substation in Milltown to a new substation along U.S. Route 1 

directly across from the LNG terminal site. It is anticipated that Downeast’s proposed pipeline 

route would be adjacent to, and the right-of-way would partially overlap, about 11.4 miles of this 

EMEC right-of-way. Installation of the transmission line would occur during construction of the 

LNG terminal, prior to construction of the sendout pipeline. Therefore, if the project were 

approved, it is anticipated that the proposed pipeline route would be adjacent to about 11.4 miles 

of recently created right-of-way. This would be in addition to the currently existing rights-ofway that the proposed pipeline would be adjacent to. This would increase the environmental 

advantage of the corresponding segment of proposed route over the Western Alternative. 

We believe the disadvantages of this alternative outweigh its advantages, primarily due to 

increased impacts on residential areas, increased wetland impacts, and constructability issues 

associated with roadway construction. Therefore, we believe the alternative would not be 

environmentally preferable to the corresponding segment of proposed route. Therefore, we do 

not recommend use of the Western Alternative.

3.8.2 Pipeline Route Variations

During review of the proposed sendout pipeline, we identified route variations that may avoid or 

minimize environmental impact on specific sensitive areas or areas of concern. We evaluated 

these route variations to determine if they would be environmentally preferable to the 

corresponding segments of the proposed route.

3.8.2.1 Baring Plantation Variation

In a letter filed with the Commission on March 17, 2008, a local resident recommended a route 

variation that would avoid the Baring Plantation residential community near MP 17. 

Construction of the sendout pipeline along this suggested route variation potentially would 

impact up to 24 vernal pools or their 250-foot buffers. Downeast did evaluate this route 

variation as part of its design of the amended pipeline route; this option was eliminated from 

further consideration due to the impacts on the vernal pools and their associated wetland 

communities. We concur with this evaluation.

3.8.2.2 Route Variations for Residences within 50 feet of the Permanent Right-of-Way

In October 2009, Downeast filed modified site-specific residential construction plans, and 

subsequently revised those plans in January 2010. The January 2010 plans included route 

variations to minimize impacts on the 19 residences located within 50 feet of the permanent 
3.0 – Alternatives 3-42

sendout pipeline right-of-way. These variations are incorporated into Downeast’s proposed route 

for the sendout pipeline that is analyzed in section 4 of the EIS.

Downeast has modified its proposed route to include the following route variations to minimize 

impacts on each residence that was previously located within 50 feet of the permanent right-ofway. The residence located near MP 0.63 was 49 feet from the proposed permanent right-of-way 

and within a proposed ATWS area. Downeast now proposes to reduce the permanent right-ofway width by 5 feet so that it is 54 feet from the structure and to eliminate the ATWS. The 

ATWS on the other side of Ridge Road is at least 50 feet from the residence.

The residence located near MP 0.91 was previously 6 feet from the permanent right-of-way and 

within a pipe laydown area. Downeast now proposes to move the pipeline route to the west 

closer to Sweeney Road and reduce the size of the pipe laydown area so that both would be more 

than 50 feet away from the residence. 

For the one residence located near MP 1.35 that was previously within the temporary right-ofway and the two residences located near MP 1.45 that would be within the permanent right-ofway, Downeast now proposes to continue the HDD pipe installation located at MP 1.11 to extend 

50 feet beyond the edge of the residential structures, position a new 25-foot by 200-foot HDD 

ATWS at the south end of the extended HDD installation, position a new 50-foot by 743-foot 

pipe laydown area at the south edge of that new HDD ATWS, and position a new 12.5-foot by 

200-foot HDD ATWS at its north edge. With this variation, the proposed construction work area 

is now over 600 feet from the residence at MP 1.35, and would be about 110 feet from the 

residences at MP 1.45 at the closest point. 

There is one residence located near MP 5.16 that was previously within the permanent right-ofway. Downeast now proposes to create a new HDD installation beginning at MP 5.1 and 

continue in a straight line to MP 5.24, create a 17,500 square foot HDD ATWS and a new 25-

foot by 200-foot HDD ATWS near the southeastern end of the new HDD installation at MP 5.1. 

In addition, Downeast proposes to create a 50-foot by 549-foot laydown area and a 25-foot by 

200-foot HDD ATWS near the northwestern end of the new HDD installation at MP 5.27 and 

remove the two ATWS on Shattuck Road. With this variation, the construction work area would 

be about 250 feet from the residence near MP 5.16 at the closest point.

For the residences located near MPs 23.94, 23.97, 24.01, 24.05, 24.09, 24.12, 24.15, 24.17, 

24.19, 24.21, 24.27, 24.32, and 24.48, Downeast has incorporated a route variation that would 

now relocate the pipeline right-of-way closer to the U.S. Route 1 right-of-way; combine the 50-

foot by 600-foot laydown area located at MP 24.20 and the 25-foot by 200-foot HDD ATWS 

located at MP 24.28 into one 25-foot by 750-foot laydown area located between the right-of-way 

and U.S. Route 1; relocate the 25-foot by 200-foot HDD ATWS located at MP 24.41 between 

the right-of-way and U.S. Route 1; and remove each 25-foot by 200-foot HDD ATWS on the 

northwest side of the pipeline at each end of the HDD. This variation would now move the 

pipeline centerline at least 75 feet away from each of the listed residences, and the temporary 

construction workspace at least 50 feet from the residences.

The January 2010 site-specific plans depicting these route variations are included in Appendix P

of the final EIS. The route variations generally result in reduced impacts on these residences.
3-43 3.0 – Alternatives

3.8.3 Single or Collocated Sendout Pipelines

We received comments during scoping that the EIS should evaluate a single sendout pipeline that 

could be used for a combination of either the Downeast LNG and Quoddy Bay LNG Projects, or 

the Downeast LNG and Calais LNG Projects, or two pipelines as proposed, but located adjacent 

to each other to the extent possible to avoid creation of two new rights-of-way. 

These alternatives were analyzed in detail in the draft EIS; however, both the Quoddy Bay and 

Calais LNG Projects are no longer proposed. As described in section 3.3.2.3, the Commission 

dismissed Quoddy Bay’s application on October 17, 2008 and Calais LNG’s application on 

April 4, 2012. Therefore, we do not believe the alternatives of a single or collocated sendout 

pipelines are feasible, and have not analyzed them in this EIS.