2-1 2.0 – Description of the Proposed Action

2.0 DESCRIPTION OF THE PROPOSED ACTION

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

onshore LNG import and interstate natural gas transmission facilities. The Coast Guard is the 

federal agency responsible for assessing the suitability of the waterway for LNG marine traffic. 

The Coast Guard is also the federal agency responsible for issuing an LOR regarding the 

suitability of the waterway for LNG marine traffic.

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 of Public Convenience and 

Necessity for a new natural gas pipeline. As indicated in the Coast Guard’s LOR to Downeast, 

the Passamaquoddy Bay Waterway was determined to be suitable for the type and frequency of 

marine traffic associated with the proposed project, provided that all of the risk mitigation 

measures outlined in its WSR were fully implemented by Downeast. These measures have been 

listed in section 1.3 of the WSR. Specific details of these measures, where applicable, and the 

resources needed to implement them, are described in the Coast Guard’s WSR, included as 

Appendix B.

2.1 PROPOSED FACILITIES

Downeast proposes to construct and operate a new LNG import, storage, and vaporization 

terminal on the south side of Mill Cove, in Robbinston, Maine slightly south of the confluence of 

Passamaquoddy Bay and the St. Croix River between the towns of Eastport, Perry, and Calais, 

Maine. In addition, Downeast proposes to construct and operate a new 29.8-mile-long, 30-inchdiameter natural gas sendout pipeline extending from the LNG terminal to the existing 

M&NE pipeline system at the Baileyville Compressor Station. General LNG terminal and 

pipeline location maps are shown on figures 1-1 and 2.1-1. The proposed LNG terminal plot 

plan is shown on figure 2.1-2. Detailed pipeline route maps are included in Appendix E (see 

figures E-1 to E-6).

2.1.1 LNG Terminal Facilities

The LNG terminal facilities would consist of a vessel unloading facility (one vessel berth and 

unloading platform), two LNG storage tanks, vaporization and vapor handling system, vent 

system, hazard detection and response system, hazard control system, metering, and support 

buildings and piping structures.

Downeast’s LNG terminal would receive LNG from up to 60 LNG vessels per year, or once 

every five days in the winter and once every eight to ten days in the summer. Upon entering the 

Gulf of Maine, the vessels could potentially take two routes to reach the routine pilot boarding 

area near East Quoddy Head. One route is east of Grand Manan Island and follows the Vessel 

Traffic Scheme (VTS) as shown on nautical charts. The second route follows the Grand Manan 

Channel, west of Grand Manan Island. The Coast Guard’s WSR does not specifically authorize 

or approve one of the proposed routes to the entrance of Head Harbour Passage. The route 

chosen by the LNG vessel captain would depend on visibility, wind, tide cycle, and other such 

constraints. While no mandatory deep draft vessel routing is currently prescribed for the 

proposed transit area, Downeast proposes that LNG vessels en route to the proposed terminal 

enter the area via the Grand Manan Channel only. However, we have assessed the 

environmental impacts for both approaches to Head Harbour Passage.
2-2

Figure 2.1-1 

Downeast LNG Project 

LNG Terminal Location Map 
2-3

Figure 2.1-2 

Downeast LNG Project 

LNG Terminal Plot Plan 
2.0 – Description of the Proposed Action 2-4

Upon entering Head Harbour Passage, the LNG vessel would pass Campobello Island along the 

island’s north shore, to the northerly confluence of Friar Roads south of Indian Island and Cherry 

Isle, into U.S. waters as it nears Eastport, Maine. It would pass along that city’s eastern shore, 

up Western Passage, passing Quoddy, Maine to the west and Deer Island, New Brunswick to the 

east. The vessel’s transit would continue north through Western Passage along the international 

boundary between Canada and the United States, keeping Deer Island to the right and the Maine 

coast on the left until turning northwesterly back into U.S. waters opposite Lewis Cove to reach 

the proposed project site near the mouth of the St. Croix River. A typical transit, from the time 

an LNG vessel would enter Head Harbour Passage to the time it reaches the proposed Downeast 

LNG terminal, would take approximately two and one-half to three and one-half hours. Figures 

showing the waterway for LNG marine traffic are provided in Appendix F.

Downeast’s application to FERC proposed using vessels ranging in size from 70,000 to 

165,000 m3

, with the potential for future vessels ranging up to 220,000 m3. However, Downeast 

only conducted vessel simulations to investigate the feasibility of navigating LNG vessels up to 

165,000 m3 cargo capacity from the pilot boarding area off East Quoddy Head to the proposed 

LNG terminal. Based on the vessel simulations, Downeast has proposed using LNG vessels with 

cargo capacities no greater than 165,000 m3

.

The 2004 Sandia National Laboratories (Sandia) Report (see section 4.12) that assessed safety 

implications of a large LNG spill over water only evaluated LNG vessels with an average cargo 

carrying capacity of 148,000 m3. The Coast Guard’s WSR (Appendix B) was based on the 

analysis in the December 2004 Sandia Report. However, the WSR states that, “based on the 

conclusions presented in the Sandia Report of May 2008, the sizes of the hazard zones applied in 

association with the Downeast LNG site are considered applicable to vessels up to a maximum 

of 265,000 m3 carrying capacity.” Therefore, from an LNG spill risk-consequence perspective, 

the waterway may be suitable for these larger class vessels. However, should Downeast choose 

to use vessels with cargo capacity up to 220,000 m3 (the design capacity of the terminal), 

additional vessel simulations incorporating these larger-sized vessels would need to be 

conducted to evaluate the navigational aspects of operating vessels of this size along the 

waterway and during docking and undocking evolutions at the Mill Cove terminal site.

In our draft EIS, the sections on each resource area contained a discussion of the potential impact 

of an LNG spill, ignited or unignited, occurring along the waterway for LNG marine traffic to 

assist the Coast Guard in fulfilling its NEPA obligations related to the issuance of the LOR. 

Since the issuance of the Downeast draft EIS, the Coast Guard has determined that the LOR is 

not a federal action and that the agency has no NEPA obligations that need to be addressed by 

the FERC EIS. As a result, we have removed the discussion in section 4 on environmental 

resources that may be present in the Coast Guard’s Zones of Concern. However, the EIS

continues to contain a discussion of impacts expected from the transit of the LNG carriers (i.e. 

shore erosion, ship traffic, ballast/cooling water intake). The discussion regarding the Zones of 

Concern considered by the Coast Guard in its determination on the type and frequency of LNG 

marine traffic associated with this proposed project is described in section 4.12.7.

The 19.5-mile route from the pilot boarding area, 1.75 miles due east of East Quoddy Head, to 

the proposed terminal site is through a deep and broad natural channel. Prior to arrival at the 

marine terminal, the water depths encountered along the transit route range from about 98 feet 

off Mill Cove to 165 to 246 feet at the pilot boarding area. The narrowest points along the transit 
2-5 2.0 – Description of the Proposed Action

route are approximately 2,000 feet wide – occurring between Dog Island and Deer Island Point, 

and when passing between buoy R “UH2” and Campobello Island in Head Harbour Passage. 

The charted depth of water at the proposed marine berth is approximately 45 to 50 feet at mean 

low water, eliminating the need for maintenance dredging. The approximate distance from the 

proposed marine berth at the trestle end to the channel centerline is 3,000 feet, providing 

adequate maneuvering area off the berth for vessel mooring and turning evolutions. 

A 3,862-foot-long, 37-foot-wide pier equipped with mooring and ancillary systems would be 

constructed for the mooring of LNG vessels. The pier would include the following support 

structures:

• an abutment positioned near the existing bluff line to support the end of the trestle;

• a roadway and pipeway access trestle;

• an unloading platform;

• four breasting dolphins;

• six mooring dolphins;

• interconnecting walkways connecting the dolphins and platform; and

• a support structure for a seawater firewater pump house located midway along the trestle.

The trestle from the terminal shoreline to the unloading platform would consist of a single lane 

roadway capable of supporting water truck loading and an adjacent pipeway to support the 

necessary LNG and utility piping and cabling. There would be three vehicle passing areas along 

the roadway. The trestle and unloading platform would be supported on steel pipe piles that 

would be vibrated and driven through surficial soils to bedrock and provided with drilled and 

grouted rock sockets. A concrete deck would be the deck surface for the roadway, unloading 

platform, and under the pipeway for spill containment.

Breasting and mooring dolphins constructed at the LNG vessel berth would each be supported by 

single, large diameter steel pipe mono-piles driven to bedrock and inserted into full diameter 

drilled and grouted rock sockets. The breasting dolphins would be equipped with:

• fenders suitable to safely berth and moor the 70,000 m3 to 165,000 m3 range of LNG 

vessels being considered with the potential for future vessels ranging up to 220,000 m3

;

and

• double, high load capacity, quick release mooring hooks.

2.1.1.1 LNG Vessel Deliveries

LNG is currently shipped from a variety of sources around the world, including such locations as 

Algeria, Australia, Brunei, Indonesia, Malaysia, Nigeria, Oman, Qatar, Trinidad, and United 

Arab Emirates. Downeast anticipates that LNG could be delivered to the proposed LNG 

terminal from any of these worldwide sources. Although LNG vessels and their operation are 

directly related to the use of the proposed LNG terminal, they are not subject to the Section 3 

authorization sought in the FERC application. The Coast Guard is the federal agency that 

exercises regulatory authority over LNG facilities and the associated LNG vessel traffic, which 

ultimately affects the safety and security of port areas and navigable waterways. In addition to 

its role as a cooperating agency to FERC, the Coast Guard assesses the suitability of the 

waterway, and issues an LOR under its regulations. The LOR and associated LOR Analysis 

(WSR) is provided to FERC and to the applicable state and local authorities having jurisdiction, 
2.0 – Description of the Proposed Action 2-6

to assist with their decision-making process concerning the approval of the LNG facility. 

On January 6, 2009, the Coast Guard COTP issued an LOR and associated WSR that determined 

that the Passamaquoddy Bay waterway was suitable for the type and frequency of LNG vessels 

proposed for the Downeast LNG Project provided that all of the recommended risk mitigation 

measures as outlined in section 4.6 of the WSR were fully implemented by Downeast.

The LNG terminal berth and offloading facility would be designed to handle LNG vessels

ranging in cargo carrying capacity from about 70,000 m3 to 165,000 m3 with the potential for 

vessels with cargo capacity of 220,000 m3

. Downeast estimates that its proposed LNG terminal 

would serve an average of about 60 LNG vessels per year.

Vessels that transport LNG are specially designed and constructed. LNG vessel construction is 

highly regulated and consists of a combination of conventional vessel design and equipment, 

with specialized materials and systems designed to safely contain liquids stored at temperatures 

of -260 degrees Fahrenheit (°F) (-162 degrees Celsius [○C]). The following section presents a 

brief overview of the main design and safety features of a typical LNG vessel. Figures 2.1-3a 

and 2.1-3b show a typical LNG vessel.

Profile

Many LNG vessels, especially those of the spherical tank design, have a distinctive appearance; 

their hull shape and dome-style profile are quite different from other types of tank vessels and 

have a relatively high freeboard (i.e., the portion of the vessel above the water line) in 

comparison to other vessels. LNG weighs only about 46 percent of the weight of water and is a 

relatively light cargo; because of its low specific gravity, tank shape and volume usually extend 

above the main deck to provide increased capacity. On the other hand, some of the more 

recently built low-elevation membrane type vessels closely resemble conventional vessels in 

outward appearance, and consequently with their lower freeboards can now pass under most 

highway and rail bridges, making more ports accessible. 

Hull Design

All LNG vessels are constructed of double hull-design. Double-hull construction increases the 

structural integrity of the hull system and provides protection to the primary containment of the 

cargo if collision, grounding, or other emergency event were to occur. Portions of the space 

between the inner and outer hulls are used for ballast water, which effectively decreases the 

vessel’s freeboard and increases its overall stability during the non-laden, return voyage to the 

loading port. 

The International Code for the Construction and Equipment of Ships Carrying Liquefied Gases 

in Bulk (IGC Code ) and Coast Guard regulations require that LNG vessels meet a Type IIG

standard of subdivision, damage stability, and cargo tank location. The Type IIG criteria ensure 

the LNG vessel could withstand flooding of any two adjacent compartments without any adverse 

effect upon the stability of the vessel. The Type IIG design also requires that the cargo tanks be 

a minimum of 30 inches from the outer hull and a minimum distance above the bottom of the 

vessel equal to the beam (width) of the vessel divided by 15, or 6.5 feet, whichever is less. This 

distance factor is intended to prevent or mitigate damage occurring to the cargo tanks in the 

event of a low energy-type impact. Recent design membrane tanks are surrounded on all sides 

by heavily strengthened double-hull construction. The distance between the cargo tank and the 

vessel’s hull is at least 7 feet and up to 13 feet in places, including the bottom of the vessel.
Figure 2.1-3a

Downeast LNG Project

Typical Spherical LNG Vessel

2-7
Figure 2.1-3b

Downeast LNG Project

Typical Membrane LNG Vessel

2-8
2-9 2.0 – Description of the Proposed Action

Containment Systems

LNG vessels are classified by their cargo containment design. Components of a containment 

system include the cargo tank (sometimes called a primary barrier), a secondary barrier

(depending on tank design), and associated insulation systems (used to inhibit boil off of the gas 

and protect the steel tank surfaces from direct exposure to cryogenic temperatures). The 

containment system also includes an extensive array of onboard cargo monitoring and control 

features for safely receiving, transporting, and discharging the product. 

Three basic cargo containment designs have been developed for the marine transportation of 

LNG. The first type of design, the membrane tank, is supported by the hold/space it occupies. 

The other two designs, spherical and prismatic, are self-supporting. While membrane tanks 

could be considered “integral tanks,” meaning that they utilize the vessel’s structure as the 

strength member to contain the cargo, a spherical tank could be considered an independent tank 

and capable of self-support of the cargo’s weight. 

In the simplest of forms, membrane tanks are composed of a layer of metal (primary barrier), 

a layer of insulation, another liquid-proof layer, and another layer of insulation. In actuality 

though, a membrane design is fairly complex and involves the sandwiching of multiple 

variations of insulation and barrier materials to include different alloys of nickel and steel, 

perlite, balsa wood, Invar, polyurethane, and aluminum, just to name a few. These built-up 

layers, or panels, are anchored to the walls of the externally-framed cargo hold, and the mating 

panel joints sealed. Within the membrane systems, different construction and material variations 

exist. Membranes are found in industry under the trade names GT or No. 96, Mark III, and CS1. 

There are three types or formulations of membrane systems—Gaz Transport, Technigaz, and a 

self-supporting prismatic membrane design termed IHI. Gaz Transport and Technigaz, now a 

joint enterprise called GTT, developed the CS1 system, which incorporated features of existing 

Gaz Transport No. 96 and Technigaz MK III membrane systems. GTT membrane designs are 

increasingly being specified for new vessel construction because the design can be prefabricated 

and readily tailored to a variety of sizes. The advantages of membrane systems include: material 

fatigue problems are limited, more cargo carrying capacity, low center of gravity (less roll 

period), more deck space, and the tanks are more easily inspected internally. The disadvantages 

are: more complex structural details, higher weight and cost of initial tank construction, not 

conducive for carrying of partial loads (below 80 percent capacity) due to “free-surface effect,” 

containment space directly around the cargo tanks must be maintained in an inert state, and an 

accurate stress analysis is harder to ascertain because of the many strength members employed 

with this type of construction. 

The alternative to a membrane tank is a self-supporting tank. The most well-known is the 

Kvaerner-Moss spherical tank, which as previously mentioned, is the vessel profile that many 

people equate with the appearance of an LNG vessel in that almost half of the large spherical 

tanks appear to protrude above a vessel’s deck. The early sphere designs were shells of 9 percent

nickel steel; subsequently aluminum has been used. This free-standing tank is insulated with 

multi-layer, close-cell polyurethane panels. The sphere is installed in its own hold of a doublehulled vessel. The sphere is supported around its equator by a steel cylinder or ring, termed the 

“skirt,” which is connected to the vessel’s hull. The advantages of the Moss spherical design 

include: convenient shape for stress analysis, good internal tank and insulation space inspection 

capability, increased safety in the event of a collision or grounding due to tank location, no 
2.0 – Description of the Proposed Action 2-10

secondary barrier is required, tanks are heavier construction, and is a better design for 

transporting partial loads. The disadvantages are: tanks penetrating the main deck provide less 

protection, there is less cargo capacity, with 40 percent of the cargo being above the main deck,

the vessel’s center of gravity is higher (longer periods of roll), and the view from the bridge/pilot 

house may be more restrictive.

The second type of self-supporting tank is the prismatic IHI by Ishikawajima Heavy Industries of 

Japan. These tanks are constructed with the framing members, or stiffeners, being internal to the 

tank. IHI tanks, which are usually constructed of aluminum alloy, 9 percent nickel alloy, or 304 

stainless steel, are installed into the hold of a double-hulled vessel and insulated with reinforced 

polyurethane foam on the bottom and the sides, with covered fiberglass on the top. 

LNG vessels are of the double-hulled design regardless of the containment system used. 

A double bottom and double sides follow the full length of the cargo area and serve as ballast 

tanks, completely independent of the cryogenic cargo tanks. This double-hulled design provides 

greatly increased reliability of cargo containment in the event of grounding or collision.

Pressure/Temperature Control

LNG is carried as a liquid in order to maximize capacity of the available volume in the cargo 

tanks. Since it is impractical to force natural gas into a liquid state using pressure, the gas is 

cooled to about -261°F at the loading facility and then pumped into the vessel’s cargo tanks. 

Because the cargo is so cold, all equipment and associated surfaces are designed and constructed 

to operate at these extremely cold (cryogenic) temperatures. The intended purpose of all LNG 

containment systems is to maintain the LNG cargo at its atmospheric boiling point, which is 

about -260°F [-162○C]. When the liquid is loaded onto a vessel, it immediately starts to “boil,” 

or return to a vapor state as it warms up after contact with relatively warmer surfaces of the 

containment system and from heat leakage through the insulated surfaces of the tank. The vapor 

generated is known as boil-off. The amount of boil-off from pre-refrigerated LNG cargo is 

directly related to the efficiency of the tank insulation. Boil-off, which is primarily methane 

vapors at ambient temperature, is used as fuel for the vessel’s main propulsion system during sea 

passages. Currently, the majority of LNG vessels burn the boil-off as fuel. Typical boil-off rates 

range from 0.10 to 0.15 percent of the cargo volume per day, which equates to about 3 percent of 

the total cargo being “boiled off” and used for fuel during a typical trans-Atlantic crossing. The 

predominant propulsion systems used on LNG vessels has conventionally been steam-turbine 

reduction with dual-fuel capability, heavy fuel oil (HFO), and boil off. However, the latest 

trends in new construction have been towards diesel, diesel-electric, and gas turbine. The IGC 

Code requires pressure control for the cargo system in order to keep the cargo tank pressure 

below the tank design pressure or the maximum allowable relief valve setting. The Coast Guard 

does not permit routine venting of BOG to the atmosphere, thus they require LNG cargo systems 

used in the U.S. waters be capable of maintaining the cargo for at least 21 days without exterior 

venting, intended to eliminate the need to vent flammable vapors while in U.S. ports. Thus, all 

LNG vessels that trade in the United States are fitted with the capability of using the boil-off 

vapor as fuel for shipboard use or for a waste heat system. As a result, LNG vessels have a 

tendency towards lower emissions in comparison to conventional oil-fired vessels.
2-11 2.0 – Description of the Proposed Action

Ballast Tanks

Sufficient ballast water capacity must be provided to permit the vessel to return to the loading 

port in a stable condition under all sea conditions (see sections 4.3 and 4.5.2 for additional 

information on ballast water). Ballast water tanks are arranged within the LNG vessel’s double 

hull and are distinct and completely separate from the vessel’s cargo tanks and associated piping. 

A ballast control system, which permits the simultaneous ballasting during cargo transfer 

operations, is also incorporated into each LNG vessel. This allows the LNG vessel to maintain a 

constant draft during all phases of its operation to enhance performance. Under normal 

operating conditions, ballast water would be taken onto the vessel while at berth during and after 

LNG offloading to maintain the trim and stability of the vessel. LNG vessels would require 

between 14 million (small capacity 125,000 m3 vessel) and 17 million gallons (large capacity 

165,000 m3 vessel, including 165,000 m3 diesel vessel) of seawater ballast. This ballast water 

would be withdrawn from the surrounding area for a duration of approximately 12 hours per 

21-hour cargo unloading period. 

LNG vessels returning to load the same product usually retain a small quantity of the cargo on 

board after discharge, termed “heel,” to maintain the tanks at the reduced temperature during the 

ballast voyage. The actual amount of heel would depend on the type of cargo containment, 

vessel’s mode of propulsion, value of product versus bunkers, and anticipated duration of the 

voyage. On LNG vessels with tanks of the membrane design, it is necessary only to maintain 

sufficient cargo to ensure that upon arrival there would be some liquid in the bottom of the tanks. 

On vessels with spherical tanks, a slightly larger quantity of heel is necessary in order to 

circulate cargo through spray nozzles fitted near the top of the dome in order that sufficient cool 

down of the tank surfaces are achieved.

Vessel Safety Systems

The LNG vessels proposed for use in the Downeast Project would have to comply with all 

federal and international standards, established by many different entities generally categorized 

as the International Maritime Organization (IMO), the respective flag state, port state, and 

classification societies regarding LNG shipping. As such, vessels that transport LNG to the 

Downeast LNG terminal would be fitted with an extensive array of sophisticated cargo 

monitoring and control systems. These systems would automatically monitor key cargo 

parameters while the vessel is at sea and during all phases of cargo operations at the marine 

terminal.

The IGC Code is one of the most important international conventions for LNG vessels and 

provides a comprehensive number of design and capability requirements that flag states and 

classification societies then supplement with even more detailed requirements. Requirements 

under the IGC Code include provisions for hull design and structural analysis criteria, cargo 

containment design, specific segregation for cargo areas and piping, leak detection and alarms 

for hold spaces and insulation, pressure monitoring and control, temperature monitoring of the 

cargo tanks, emergency shutdown of cargo pumps and closing of critical valves, monitoring of 

tank cargo levels, and gas and fire detection.

The LNG vessels would be fitted with sophisticated navigational and communication equipment

including:
2.0 – Description of the Proposed Action 2-12

• two separate marine radar systems, including automatic radar plotting and radio direction 

finders;

• LORAN-C receivers;

• echo depth finders; and

• global positioning and communications technology and satellite navigation system.

All LNG vessels also have redundant, independent steering control systems that are operable 

from the bridge or steering gear room to maintain rudder movement in case of a steering system 

failure.

Fire Protection

All LNG vessels arriving at the Downeast LNG terminal would be constructed according to 

structural fire protection standards contained in the International Convention for the Safety of 

Life at Sea (SOLAS).

The vessels would also be fitted with active fire protection systems that meet or exceed design 

parameters in Coast Guard regulations and international standards, such as the IGC Code and 

SOLAS, including:

• a water spray (deluge) system that covers the accommodation house and central room, 

and all main cargo control valves;

• a traditional firewater system that provides water to fire monitors on deck and to fire 

stations found throughout the vessel;

• a dry powder extinguishing system for LNG fires; and

• a carbon dioxide system for protecting the machinery, ballast pump room, emergency 

generators, cargo compressors, etc.

Crew Qualifications and Training

All officers and crews of the LNG vessels would comply with the International Convention 

Standards of Training, Certification and Watch Keeping for Seafarers (STCW). Key members of 

the crew must have specific training in the handling of LNG and the use of the safety equipment. 

Every transfer of LNG and each cool-down, warm-up, and gas-free operation must be supervised 

by a qualified person in charge (PIC) as per 46 CFR 154.1831 and the international requirements 

of Regulation V/1 of STCW. Officers must receive simulator training in the handling of the 

vessel and the cargo systems specific to the conditions at the project site. The WSR recommends 

that all pilots receive follow-on full mission bridge simulator training taking into account the 

intended size and maneuvering characteristics for those LNG vessels under consideration and to 

ascertain the performance capabilities of intended assist tugs and escort vessels. The Coast 

Guard’s WSR also recommends that Downeast collaborate with all appropriate jurisdictions on 

joint, complimentary rulemaking to formalize traffic management practices, the implementation 

of appropriate operating parameters, and among other measures, the need for mandatory pilotage 

for all deep-draft vessels throughout the transit of the Passamaquoddy Bay Waterway, its 

approaches, and the St. Croix River. 
2-13 2.0 – Description of the Proposed Action

Vessel Selection

The specific identity of LNG vessels that would offload at the Downeast LNG terminal would 

depend on the commercial terms of the LNG purchase agreements. Transportation could be 

provided by either the LNG buyer or supplier. The different contractual arrangements for LNG 

transport can result in vessels of different sizes and countries of origin being used to transport 

LNG to the LNG terminal.

Table 2.1.1.1-1 shows the relative dimensions of LNG vessels that Downeast stated could be 

used to transport LNG to the Downeast LNG terminal. 

TABLE 2.1.1.1-1

Typical LNG Vessel Characteristics

Specifications Existing Vessels Future Vessels

Capacity (m3) 70,000 145,000 165,000 220,000

Length Overall (feet) 852 950 1,030 1,033

Beam (feet) 125 162 173 180

Draft (feet) 34 41 43 43

LNG vessels arriving at the Downeast LNG terminal must comply with all applicable 

international conventions, appropriate flag state requirements, class society rules and regulations, 

and Coast Guard port state control measures. They each have specific areas of responsibility 

which, in some cases, overlap. Overall compliance is demonstrated through periodic inspections 

and surveys, as attested by the pertinent certificates maintained aboard the vessel. During these 

examinations and/or inspections, it is also confirmed that the vessel is manned in accordance 

with international and national requirements and that the vessel’s crew is proficient by proper 

training and certification, as required. Flag states are those states/countries with whom the 

vessels are registered. Flag states are responsible for ensuring that vessels are constructed in 

accordance with the applicable international standards and any unique national requirements. 

Port states are those states to which a vessel trades in commerce. Port states impose laws and 

regulations specific to their individual ports and areas of jurisdictions. For LNG vessels 

intending to serve the Downeast LNG facility:

• U.S. Flag LNG Vessel – The Coast Guard Certificate of Inspection (COI) must be valid 

and endorsed for the vessel to transport LNG (46 CFR 154, 1979). A Coast Guard COI is 

issued for a period of five years and retention of the COI depends upon the continued 

maintenance of the vessel in a safe operating condition and satisfactory completion of 

required annual inspections during the five-year COI period.

• Foreign Flag LNG Vessel – The vessel must have a valid Certificate of Compliance 

(COC) issued by the Coast Guard. The certificate is issued after the vessel has proven 

that it complies with the Coast Guard regulations and after it has been satisfactorily 

inspected by a Coast Guard Marine Safety Office (46 CFR 154, 1979). A COC is valid 

for a two-year period and remains valid pending satisfactory completion of an annual 

mid-period examination between COC renewals.
2.0 – Description of the Proposed Action 2-14

Both United States and foreign flag vessels must be inspected annually by the Coast Guard and 

the respective flag state. Coast Guard boarding officers from COTP Sector Northern New 

England would board all LNG vessels in waters subject to the jurisdiction of the United States

prior to the vessels arriving in port to ensure applicable safety and security standards are met.

2.1.1.2 LNG Unloading and Transfer Lines

LNG vessels would use onboard pumps to transfer LNG from their cargo tanks to the shore-side 

storage tanks. Four 16-inch-diameter articulated unloading arms would be installed on the 

unloading platform to support cargo unloading operations. Three of these arms are designed for 

LNG offload from the vessel to shore, and one for vapor return, shore to vessel. One of the three 

LNG delivery arms could also be used for vapor return from the LNG storage tank to the LNG 

vessel during vessel unloading. 

The arms would be fitted with two isolating valves and powered emergency release couplings to 

protect the arm and the vessel, and to minimize spillage of its liquid content during an 

emergency disconnect. The arms could handle the range of LNG vessels being considered. 

The unloading arms would be connected by manifold to a single 36-inch-diameter, single-walled 

stainless steel insulated LNG transfer pipeline equipped with thermal expansion loops to transfer 

the LNG from the unloading platform.

Downeast would design these facilities in accordance with the requirements of 49 CFR Part 193, 

33 CFR Part 127, and National Fire Protection Association (NFPA) 59A, which the DOT 

incorporated within 49 CFR Part 193. The facilities would be designed to provide safe berthing 

for the receipt and mooring of LNG vessels and to ensure safe transfer of LNG cargoes from the 

vessels to the LNG storage tanks.

2.1.1.3 LNG Storage Tanks

The LNG transfer lines would transport the LNG to two 160,000 m3 full containment type tanks, 

with a primary inner container and a secondary outer container. Figure 2.1-4 is a drawing of a 

typical full containment storage tank. The tanks would be designed and constructed so that the 

self-supporting primary container and the secondary container would be capable of 

independently containing the LNG. The primary container would contain the LNG under normal 

operating conditions. The secondary container would be capable of containing the LNG 

(110 percent capacity of inner tank) and of controlling the vapor resulting from unlikely failure 

of the inner container. The insulated tanks would each be designed to store a net volume of 

160,000 m3 (42,267,530 gallons) of LNG at a temperature of -270°F (-168○

C) and a maximum 

internal pressure of 4.3 pounds per square inch gauge (psig).

The double-walled tanks would consist of a:

• 9 percent nickel, steel open top inner container;

• pre-stressed concrete outer container wall;

• reinforced concrete dome roof;

• reinforced concrete outer container bottom; and

• insulated aluminum deck over the inner container suspended from the roof.
2-15

Figure 2.1-4 

Downeast LNG Project 

Typical Full Containment Storage Tank 
2.0 – Description of the Proposed Action 2-16

The aluminum support deck would be insulated on its top surface with fiberglass blanket 

insulation material. The diameter of the outer container would be approximately 259 feet. The 

insulation beneath the inner container would be cellular glass, load-bearing insulation that would 

support the weight of the inner container and the LNG. The space between the sidewalls of the 

inner and outer containers would be filled with expanded perlite insulation that would be 

compacted to reduce long-term settling of the insulation. Base heating would be provided in the 

foundation to prevent frost heave. The outer container would be lined on the inside with carbon 

steel plates. This carbon steel liner would serve as a barrier to moisture migration from the 

atmosphere reaching the insulation inside the outer concrete. This liner also forms the barrier to 

prevent vapor escaping from inside the tank in normal operation.

There would be no penetrations through the inner container or outer container sidewall or 

bottom. All piping into and out of the inner or outer containers would enter from the top of the 

tank. The inner container of each tank would be designed and constructed in accordance with 

the requirements of American Petroleum Institute (API) Standard 620 and meet the requirements 

of NFPA 59A and 49 CFR Part 193.

Two fully submerged low pressure transfer pumps would be column mounted in each LNG 

storage tank. The in-tank pumps would transfer the LNG from the LNG storage tanks to LNG 

sendout pumps. Each in-tank pump would be designed to handle up to 4,600 gpm. Each pump 

would be designed for 100 percent sendout capacity and LNG vessel unloading pipeline 

recirculation.

2.1.1.4 Vaporization System

The SCVs would be installed on land to re-vaporize the LNG to natural gas. In each SCV, 

natural gas would be fired in a burner, or series of burners, submerged in a water bath. Because 

the exhaust gases are quenched within the water bath, they operate with a very high (98 to 

99 percent) thermal efficiency. The use of an SCV system eliminates the need for withdrawing 

water from the bay and/or the need to build an on-site power plant to warm (re-gasify) the LNG. 

After leaving the vaporizers, the high pressure gas would be metered prior to discharge into the 

sendout pipeline. A vaporized below grade sendout pipeline would connect between the 

vaporization system and the metering facilities that would measure the total natural gas output of 

the LNG project. Under normal operations, the terminal would have an average total output of 

500 MMcfd.

2.1.1.5 Vapor Handling System

During normal operations, ambient heat input into the LNG storage tanks and piping system 

would cause a small amount of LNG to be continuously vaporized, referred to as BOG. Some 

vaporization of LNG would also be caused by other factors such as barometric pressure changes, 

heat input due to pumping, and vessel flash vapor. During a vessel unloading, vapor in the LNG 

storage tank would be displaced by the newly added LNG. The displaced vapor would be 

returned to the vessel by vapor return blowers through a vapor return line and a vapor return arm 

connected to the vessel in order to maintain a slight positive pressure in the vessel’s tanks. 

Additional BOG would be generated due to the heat added by the vessel’s transfer pumps and the 

heat leaked into the tank and piping systems. Any BOG not returned to the vessel would be 

compressed by the BOG compressors and condensed in the BOG condenser. The condensers 

would condense the excess BOG and mix it with the inlet stream to the SCVs.
2-17 2.0 – Description of the Proposed Action

2.1.1.6 Utilities and Support Facilities 

Support facilities located within the terminal include an administration building, main control 

room (MCR), maintenance building/warehouse, utilities building, and a security building.

2.1.2 Downeast Sendout Pipeline

The natural gas pipeline facilities proposed by Downeast would consist of a 29.8-mile-long, 

30-inch-diameter natural gas sendout pipeline. The sendout pipeline would extend from the 

LNG terminal to the existing M&NE pipeline system at the Baileyville Compressor Station. The 

pipeline would be capable of transporting about 500 MMcfd of natural gas at a design pressure 

of 1,440 psig. 

2.2 LAND REQUIREMENTS 

2.2.1 LNG Terminal Facilities

The LNG terminal site would occupy approximately 80 acres of land immediately to the south of 

Mill Cove in Robbinston, Maine. During early project development Downeast held a purchase 

option for the entire parcel, and on August 9, 2013 notified the Commission that it exercised the 

option and has purchased the site. Construction and operation of the proposed LNG terminal 

would require about 47 acres of land. Construction and operation of Downeast’s pier trestle and 

unloading platform would impact about 3.6 acres of submerged lands in Passamaquoddy Bay, 

based on the surface area of the pier; however, only 0.1 acre of submerged land would be 

directly disturbed by the pilings. Downeast must obtain a Submerged Lands Lease from the 

State of Maine to construct and operate the pier and unloading platform. Downeast intends to 

file the application for the lease in conjunction with the Maine DEP application, now anticipated

in 2014. Table 2.2.1-1 summarizes the land requirements for the proposed LNG terminal. 

Access to the LNG terminal would be by way of U.S. Route 1.

TABLE 2.2.1-1

Summary of Land Requirements for the Proposed LNG Terminal Facilities

Facility/Use

Land Affected During 

Construction

(acres)

Land Affected During 

Operation

(acres)

LNG Terminal

Terminal land based facilities a/ 47.0 a/ 47.0

Pier trestle and unloading platform 3.6 3.6

Total 50.6 50.6

a/ Includes sendout pipeline pig launching facility inside the terminal property. Does not include acreage for off-site temporary 

pipeline and terminal laydown areas. These are included in section 2.2.2.

2.2.2 Downeast Sendout Pipeline

Construction of the proposed pipeline and related facilities would disturb about 265.8 acres of 

land, including a 75-foot-wide construction right-of-way for the 30-inch-diameter sendout 

pipeline, additional temporary workspaces, pipeline laydown areas, access roads, pipe storage 

areas, pigging facilities, and mainline valves (MLV).
2.0 – Description of the Proposed Action 2-18

Operation of the new facilities would require about 138.2 acres, including a 50-foot-wide

permanent right-of-way for the 30-inch-diameter pipeline, permanent access roadways, MLV, 

and pig receiving facility. After construction, the temporary right-of-way would be restored to 

its previous condition and use. The land required for operation of aboveground facilities would 

be fenced and maintained by Downeast. Table 2.2.2-1 summarizes the land requirements for the 

proposed pipeline facilities. 

2.2.2.1 Pipeline Right-of-Way and Temporary Extra Workspaces 

Downeast would construct the 30-inch-diameter sendout pipeline within a 75-foot-wide 

construction right-of-way, of which 50 feet would be retained for permanent pipeline easement 

and 25 feet would be temporary workspace. A narrower construction right-of-way ranging from 

55 to 65 feet wide would be used in limited site-specific locations, such as along residential 

areas, existing roadways, and wetlands. Figure 2.2-1 shows a typical right-of-way cross-section 

for the sendout pipeline. Additional temporary workspace of varying dimensions, located 

adjacent to the construction right-of-way of the pipeline, would be required at about 

141 locations, primarily at crossings of roads, waterbodies, and wetlands. Locations of 

additional temporary workspaces are listed in table 2.2.2.1-1.

TABLE 2.2.2-1

Summary of Land Requirements for the Proposed Pipeline Facilities

Facility

Land Affected

During Construction

(acres)

Land Affected

During Operation

(acres)

Pipeline

Pipeline Right-of-Way 201.3 a/, b/ 127.5 b/

Additional Temporary Extra Workspaces, including HDD 18.7 0.0

Terminal and Pipeline Off-Site Laydown Areas 31.7 0.0

Access Roads 10.1 10.0

Pipe Storage Area 3.2 0.0

Subtotal 265.0 137.5

Aboveground Facilities

Valve Station 0.3 d/ 0.4 e/

Pigging Receiver c/ 0.5 0.3

Subtotal 0.8 0.7

Total f/ 265.8 138.2

a/ Includes nominal 75-foot-wide construction right-of-way for the sendout pipeline.

b/ This table only shows the lands that actually would be physically disturbed by the pipeline construction and operation. Areas 

where HDD is being proposed are excluded because these areas would not be disturbed by construction or operation of the 

pipeline.

c/ Acreage for the pig launching facility is included in the land requirements for the terminal in table 2.2.1-1. The specific location 

of the pig receiver and associated interconnection facilities within the M&NE system has not been determined.

d/ The total area disturbed during the valve station construction is 0.5 acre; however, 0.2 acre overlaps the pipeline right-of-way

and is included in the pipeline right-of-way acreage.

e/ This is the acreage outside the permanent pipeline right-of-way.

f/ Rounding may result in slight differences in some calculations.
2-19

Figure 2.2-1 

Downeast LNG Project

Typical Sendout Pipeline Right-of-Way Cross Section
2.0 – Description of the Proposed Action 2-20

TABLE 2.2.2.1-1

Additional Temporary Workspace and Laydown Areas for the

Downeast LNG Terminal and Sendout Pipeline

Location Crossing Milepost Acres Staging Area Type Existing Land Use

Ridge Road NA 3.00 Pipeline and Terminal Laydown Area Developed / Grassland

Route 1 a/ NA 2.00 Pipeline and Terminal Laydown Area Developed / Grassland

Route 1 a/ NA 3.00 Pipeline and Terminal Laydown Area Developed / Grassland

US Route 1 0.0 0.11 Road Crossing Developed / Forest

Wetland 0.1 0.11 Wetland Staging Area Developed

Point of Inflection (PI) 0.2 0.11 PI Workspace b/ Forest

PI 0.2 0.11 PI Workspace Forest

Wetland 0.3 0.11 Wetland Staging Area Forest

Wetland 0.5 0.11 Wetland Staging Area Forest

Ridge Rd 0.7 0.12 Road Crossing Developed / Forest

Western Stream 0.8 0.13 Stream / Wetland Staging Area Developed / Forest

Western Stream 0.8 0.11 Stream / Wetland Staging Area Developed / Forest

Vernal Pool 1.0 0.86 Vernal Pool HDD c/ Forest

Vernal Pool 1.1 0.11 Vernal Pool Staging Area Wetland

Vernal Pool 1.5 0.60 Vernal Pool Staging Area Forest

Wetland 1.7 0.11 Wetland Staging Area Forest

Wetland 1.9 0.11 Wetland Staging Area Forest

Wetland 2.0 0.11 Wetland Staging Area Forest

Brewer Road 2.1 0.11 Wetland Staging Area / Road Crossing Forest / Wetland

Sherman Rd 2.3 0.11 Road Crossing Developed / Forest

Sherman Rd 2.3 0.12 Road Crossing Developed / Forest

Wetland 2.4 0.11 Wetland Staging Area Developed / Forest

Wetland 2.8 0.11 Wetland Staging Area Forest

Vernal Pool 3.0 0.80 Vernal Pool Staging Area c/ Forest

Vernal Pool 3.1 0.11 Vernal Pool Staging Area Forest / Herbaceous

Vernal Pool 3.3 0.11 Vernal Pool Staging Area Forest / Herbaceous

Trimble Rd 3.5 0.11 Road Crossing Developed / Forest

Vernal Pool 3.6 0.11 Vernal Pool Staging Area Forest

Vernal Pool 3.8 2.00 Vernal Pool Staging Area c/ Forest

Vernal Pool 3.8 0.11 Vernal Pool Staging Area Forest

Inland Wading Bird / Waterfowl Habitat 4.1 0.11 Inland Wading Bird / Waterfowl Habitat Forest

Inland Wading Bird / Waterfowl Habitat 4.4 0.11 Inland Wading Bird / Waterfowl Habitat Forest

Shattuck Rd 5.1 0.11 HDD Staging Area / Road Crossing Forest

Shattuck Rd 5.1 0.40 HDD Staging Area / Road Crossing Forest

Shattuck Rd 5.2 0.11 HDD Staging Area / Road Crossing Forest

Shattuck Rd 5.3 0.63 HDD Staging Area / Road Crossing Forest

PI / Wetland 5.6 0.10 PI / Wetland Staging Area Forest

Wetland 6.1 0.14 Wetland Staging Area Forest

PI / Wetland 6.3 0.23 PI / Wetland Staging Area Forest

PI / Wetland 6.4 0.13 PI / Wetland Staging Area Forest

Flowed Ponds Stream 6.7 0.10 Flowed Ponds Stream Habitat / 

Wetland Staging Area

Forest

Flowed Ponds Stream 6.7 0.11 Flowed Ponds Stream Habitat / 

Wetland Staging Area

Forest

PI 6.9 0.24 PI Workspace Forest

Wetland 7.6 0.11 Wetland Staging Area Developed / Forest

Wetland 7.7 0.11 Wetland Staging Area Forest

Wetland 7.9 0.11 Wetland Staging Area Developed / Forest

Wetland 8.0 0.11 Wetland Staging Area Developed / Forest

Inland Wading Bird / Waterfowl Habitat / 

Wetland

8.3 0.11 Inland Wading Bird / Waterfowl Habitat 

/ Wetland Staging Area

Forest

Inland Wading Bird / Waterfowl Habitat / 

Wetland

8.9 0.70 Inland Wading Bird / Waterfowl Habitat 

/ Wetland Staging Area c/

Forest

Inland Wading Bird / Waterfowl Habitat / 

Wetland

8.9 0.69 Inland Wading Bird / Waterfowl Habitat 

/ Wetland Staging Area c/

Forest

Vernal Pool 9.0 0.11 Vernal Pool Staging Area Forest
2-21 2.0 – Description of the Proposed Action

TABLE 2.2.2.1-1

Additional Temporary Workspace and Laydown Areas for the

Downeast LNG Terminal and Sendout Pipeline

Location Crossing Milepost Acres Staging Area Type Existing Land Use

Vernal Pool 9.1 0.11 Vernal Pool Staging Area Forest

Vernal Pool 9.2 0.11 Vernal Pool Staging Area Forest / Herbaceous

Vernal Pool 9.3 0.57 Vernal Pool Staging Area c/ Forest

Vernal Pool 9.3 0.12 Vernal Pool Staging Area Developed / Forest

Vernal Pool 9.5 0.11 Vernal Pool Staging Area Developed / Forest

Vernal Pool 9.6 0.11 Vernal Pool Staging Area Developed / Forest

Vernal Pool 9.6 0.51 Vernal Pool Staging Area c/ Forest

Vernal Pool 10.4 0.11 Vernal Pool Staging Area Forest

Vernal Pool 10.4 0.76 Vernal Pool Staging Area c/ Forest / Herbaceous

Vernal Pool 10.5 0.11 Vernal Pool Staging Area Forest

PI 10.7 0.14 PI Workspace Forest

PI 11.7 0.22 PI Workspace Forest

Vernal Pool / Wetland 11.7 0.11 Vernal Pool / Wetland Staging Area Forest

Vernal Pool / Wetland 12.2 0.11 Vernal Pool / Wetland Staging Area Forest

Vernal Pool / Wetland 12.2 1.28 Vernal Pool / Wetland Staging Area c/ Forest

PI 12.5 0.23 PI Workspace Forest

Vernal Pool / Wetland 12.7 0.63 Vernal Pool / Wetland Staging Area c/ Forest

Vernal Pool / Wetland 12.8 0.11 Vernal Pool / Wetland Staging Area Forest

Vernal Pool / Wetland 12.9 0.11 Vernal Pool / Wetland Staging Area Forest

PI / Wetland 13.1 0.12 PI / 90° Bend / Wetland Staging Area Forest / Wetland

US Route 1 13.7 0.11 Road Crossing Forest

US Route 1 13.8 0.11 Road Crossing Forest

Railroad Crossing 14.0 0.13 Railroad Crossing / Wetland Staging 

Area

Agricultural

Railroad Crossing 14.1 0.11 Railroad Crossing Agricultural / Developed / Forest

St. Croix River 14.1 1.65 St. Croix River Agriculture / Developed / Herbaceous

St. Croix River Near 15.2 3.18 St. Croix River d/ Forest / Wetland

St. Croix River 15.4 1.14 St. Croix River Forest / Wetland

St. Croix River 15.4 4.35 St. Croix River c/ Forest

Railroad Crossing 15.5 0.90 Railroad Crossing Forest

Railroad Crossing 15.6 0.23 Railroad Crossing Forest / Wetland

PI / Wetland 16.2 0.13 PI / Wetland Staging Area Herbaceous

PI / Wetland 16.4 0.21 PI / Wetland Staging Area Forest / Wetland

Wetland 16.6 0.11 Wetland Staging Area Forest

Wetland 16.8 0.11 Wetland Staging Area Forest

Wetland 17.2 0.11 Wetland Staging Area Developed / Forest

Wetland 17.4 0.11 Wetland Staging Area Forest

Inland Wading Bird / Waterfowl Habitat 17.7 0.38 Inland Wading Bird / Waterfowl Habitat Developed / Forest / Herbaceous / 

Wetland

Inland Wading Bird / Waterfowl Habitat 18.2 0.11 Inland Wading Bird / Waterfowl Habitat Forest

Inland Wading Bird / Waterfowl Habitat 18.2 1.87 Inland Wading Bird / Waterfowl Habitat Forest

Wetland 18.6 0.11 Wetland Staging Area Developed / Forest

Wetland 19.1 0.11 Wetland Staging Area Forest

Wetland 19.5 0.11 Wetland Staging Area Developed / Herbaceous

Wetland 19.7 0.11 Wetland Staging Area Forest / Herbaceous

PI 19.8 0.13 PI Workspace Forest / Herbaceous

US Route 1 20.1 0.12 Road Crossing Developed / Herbaceous

US Route 1 20.1 0.14 Road Crossing Agricultural / Developed

PI 20.3 0.14 PI Workspace Forest

Wetland 20.6 0.11 Wetland Staging Area Forest

Town Rd 20.9 0.13 Road Crossing Developed / Forest

Town Rd 20.9 0.11 Road Crossing Agricultural / Developed / Forest

Wetland 21.2 0.11 Wetland Staging Area Forest

Wapsaconhagan Brook 21.3 0.11 Wetland Staging Area / Stream Forest

Wapsaconhagan Brook 21.3 0.34 Wetland Staging Area / Stream Forest
2.0 – Description of the Proposed Action 2-22

TABLE 2.2.2.1-1

Additional Temporary Workspace and Laydown Areas for the

Downeast LNG Terminal and Sendout Pipeline

Location Crossing Milepost Acres Staging Area Type Existing Land Use

Wapsaconhagan Brook 21.3 0.11 Wetland Staging Area / Stream Forest

PI 21.7 0.13 PI Workspace Herbaceous

South Princeton Rd 22.1 0.11 Road Crossing Forest / Herbaceous / Wetland

South Princeton Rd 22.2 0.11 Road Crossing Forest / Herbaceous / Wetland

PI / Wetland 22.2 0.14 PI / Wetland Staging Area Forest

Wetland 22.3 0.11 Wetland Staging Area Forest

Wetland 22.6 0.11 Wetland Staging Area Forest

Wetland 22.6 0.11 Wetland Staging Area Developed / Forest

Private Road 22.8 0.11 Private Road / Wetland Staging Area Developed / Forest

Wetland 23.1 0.11 Wetland Staging Area Developed / Forest

PI / Wetland 23.4 0.11 PI / Wetland Staging Area Developed / Forest

Wetland 23.6 0.11 Wetland Staging Area Forest

PI 23.9 0.11 PI Workspace Developed

Vernal Pool 24.2 0.46 Vernal Pool Staging Area c/ Developed

Vernal Pool 24.4 0.11 Vernal Pool Staging Area Wetland

PI / Wetland 24.8 0.11 PI / Wetland Staging Area Developed / Forest

Inland Wading Bird / Waterfowl Habitat 24.9 1.26 IWWH HDD Staging c/ Forest

Inland Wading Bird / Waterfowl Habitat 25.1 0.11 Inland Wading Bird / Waterfowl Habitat Forest

Inland Wading Bird / Waterfowl Habitat 25.6 0.15 Inland Wading Bird / Waterfowl Habitat Forest / Wetland

PI / Wetland 25.7 0.13 PI / Wetland Staging Area Forest / Wetland

PI / Wetland 25.9 0.14 PI / Wetland Staging Area Forest / Wetland

Wetland 26.6 0.11 Wetland Staging Area Developed / Forest

Wetland 27.0 0.11 Wetland Staging Area Developed / Forest

US Route 1 27.2 0.11 Road Crossing Developed / Forest

PI / Wetland 27.3 0.21 PI / Wetland Staging Area Forest / Wetland

Wetland 27.5 0.11 Wetland Staging Area Forest

Wetland 27.7 0.11 Wetland Staging Area Forest

Wetland 28.3 0.11 Wetland Staging Area Forest

Grand Falls Rd 28.7 0.09 Road Crossing Developed / Forest

Grand Falls Rd 28.7 0.11 Road Crossing Developed / Forest

Inland Wading Bird / Waterfowl Habitat 28.7 1.08 Inland Wading Bird / Waterfowl Habitat Forest

Wetland 28.8 0.11 Wetland Staging Area Forest

Inland Wading Bird / Waterfowl Habitat 28.8 0.11 Inland Wading Bird / Waterfowl Habitat Forest

Inland Wading Bird / Waterfowl Habitat 29.0 0.11 Inland Wading Bird / Waterfowl Habitat Forest

Vernal Pool 29.0 0.65 Vernal Pool Staging Area c/ Forest

Vernal Pool 29.1 0.11 Vernal Pool Staging Area Forest

Vernal Pool 29.3 0.11 Vernal Pool Staging Area Forest / Wetland

Wetland 29.5 0.11 Wetland Staging Area Developed / Forest

Vernal Pool 29.6 0.57 Vernal Pool Staging Area c/ Herbaceous

Vernal Pool 29.7 0.11 Vernal Pool Staging Area Forest

Vernal Pool 29.8 0.11 Vernal Pool Staging Area Developed

Vernal Pool 29.8 0.11 Vernal Pool Staging Area Developed

a/ These laydown areas would be located on the west side of U.S. Route 1, approximately 3,000 feet south of the proposed site 

entrance.

b/ PI (Point of Inflection, the point of change on curve) workspace is the extra workspace required where the pipeline turns or bends in 

a different direction.

c/ Sendout pipeline laydown areas.

d/ Pipe storage area.

Although Downeast has identified areas where extra workspace would be required, additional or 

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

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

and approval prior to use.
2-23 2.0 – Description of the Proposed Action

Approximately 12 miles of the route for the sendout pipeline would be adjacent to existing 

rights-of-way. Table 2.2.2.1-2 lists locations where the pipeline would parallel existing rightsof-way. Downeast stated that it would coordinate with Eastern Maine Electric Cooperative

(EMEC) on the use of their transmission line right-of-way for a portion of the pipeline right-ofway. If feasible, where the pipeline would be directly adjacent to the existing right-of-way, the 

new pipeline would be offset about 5 to 10 feet from the outside edge of the existing utility rightof-way. The 50-foot-wide permanent pipeline right-of-way, as well as a portion of the 

construction right-of-way, would partially overlap the existing electric transmission line right-ofway. We recommend that:

• Downeast should not begin construction of the pipeline from milepost (MP) 17.7 to 

MP 27.2 until Downeast files with the Secretary, for review and written approval by 

the Director of OEP, updated alignment sheets, developed in coordination with 

EMEC, depicting the pipeline adjacent to the existing transmission line.

It is anticipated that the new electric transmission line that would be constructed by EMEC to 

service the terminal would be installed parallel to the pipeline from MP 0.2 to MP 11.6. The 

new transmission line would bring electric power from EMEC’s existing switchyard in Milltown 

to a new electric substation that would be located across U.S. Route 1 from Downeast’s LNG 

terminal. These are nonjurisdictional facilities that are discussed in section 2.9.

TABLE 2.2.2.1-2

Locations Where the Downeast Sendout Pipeline Would Parallel Existing Rights-of-Way

Mileposts Segment Length

(miles) Existing Easement Direction fromExisting Right-of-Way

17.7-27.2 9.5 Existing EMEC Powerline Adjacent to the south side of the electric transmission line

27.3-29.8 2.5 Existing M&NE Pipeline Adjacent to the south side of the pipeline

 

2.2.2.2 Aboveground Facilities 

Aboveground facilities associated with the proposed pipeline would include three MLVs and 

pigging and gas metering facilities. Table 2.2.2-1 lists the land requirements for these facilities 

along the sendout pipeline. The pig launching facility and MLV at MP 0.0 would be located in 

the terminal site and would require approximately 0.25 acre for both construction and operation 

and is included within the 47 acres of land associated with the terminal construction and 

operation. The MLV at MP 17.17 would require approximately 0.5 acre for construction and 

0.4 acre for permanent operation. The valve station is accessible from Haywood Lane, 

eliminating the need for an access road. The pig receiving and gas metering facilities and an 

MLV would be located at MP 29.8 within the Baileyville Compressor Station property boundary 

and would require 0.5 acre for construction and 0.3 acre during operation.

2.2.2.3 Access Roads and Contractor Yard 

Access roads would be located within the pipeline construction right-of-way where possible. 

Downeast would use four temporary access roads related to its proposed pipeline facilities (see 

table 2.2.2.3-1). Only the access road at MP 15.4 is a newly created access road that would

require clearing for a new road base. The other three access roads are existing skidder roads that 
2.0 – Description of the Proposed Action 2-24

were previously used for timbering activities. These skidder access roads have existing road 

bases; however, they would need to be upgraded prior to construction of the sendout pipeline. 

The width of the skidder roads is generally 15 to 25 feet, with numerous road segments 

exceeding 25 feet in width. The roads are compacted earth with a gravel surface and are raised 

above existing grade for positive drainage control. Replacing and supplementing the gravel 

surface that has degraded over time would be the principle improvement to upgrade the skidder 

roads for construction of the sendout pipeline. Small, localized sections of the skidder roads may

need to be widened. A total of about 10.2 acres would be required for the construction access 

roads. After the pipeline construction activities are completed, the skidder roads would not be 

restored to pre-existing conditions; however, the soils and vegetation disturbed by widening 

would be rehabilitated. The road improvements would be left in place to assist local timbering 

operators for forestry equipment access for future timber harvest. 

Downeast has identified 20 proposed pipeline and terminal laydown areas and a pipe storage 

yard, which would affect approximately 30.9 acres during the construction of the terminal and 

sendout pipeline (see table 2.2.2.1-1). These tracts would only be used temporarily during 

construction of the project. Following construction, these areas would be returned to their preconstruction conditions.

TABLE 2.2.2.3-1

Access Roads Associated with the Proposed Pipeline

Milepost Road Name/

Destination

New/

Existing

Permanent/

Temporary

Acres

Affected

5.2 Shattuck Road to MP 6.2 on the pipeline Existing Permanent 4.1

8.1 Carson Road to MP 8.1 on the pipeline Existing Permanent 3.1

10.2 Hardscrabble Road to MP 9.3 on the pipeline Existing Permanent 2.6

15.4 Private Road to MP 15.4 staging area + pipe 

laydown area

New Permanent 0.4

 

2.3 CONSTRUCTION PROCEDURES 

This section describes the general construction procedures proposed by Downeast for 

construction of the LNG terminal and sendout pipeline facilities. Section 4.0 of this EIS contains 

more detailed discussions of proposed construction and restoration procedures, as well as 

additional measures that we are recommending to mitigate environmental impacts.

The LNG terminal and sendout pipeline facilities would be designed, constructed, operated, and 

maintained in accordance with federal standards that are intended to ensure adequate protection 

for the public and to prevent LNG and natural gas pipeline failures or accidents.

Under provisions of the Natural Gas Pipeline Safety Act of 1968, as amended, Downeast would 

design, construct, operate, and maintain the LNG terminal facilities in accordance with the 

DOT’s Federal Safety Standards for Liquefied Natural Gas Facilities at 49 CFR 193 and the 

NFPA’s Standards for the Production, Storage, and Handling of LNG (NFPA 59A). These 

standards specify siting, design, construction, equipment, and fire protection requirements for 

new LNG facilities. The LNG vessel unloading facilities and any appurtenances located between 

the LNG vessel and the last valve immediately before the LNG storage tank would comply with 
2-25 2.0 – Description of the Proposed Action

the applicable sections of the Coast Guard regulations for Waterfront Facilities Handling LNG at 

33 CFR 127 and Executive Order 10173.

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

accordance with the DOT regulations at 49 CFR 192, Transportation of Natural or Other Gas by 

Pipeline: Minimum Federal Safety Standards. Among other items, these regulations specify 

material selection, design criteria, corrosion protection, and qualification for welders and 

operation personnel. In addition, Downeast would comply with the Commission’s regulations at 

18 CFR 380.15, regarding the siting and maintenance of pipeline rights-of-way.

Downeast would construct the project facilities in accordance with the FERC’s Upland Erosion 

Control, Revegetation and Maintenance Plan (Plan), Wetland and Waterbody Construction and 

Mitigation Procedures (Procedures) and M&NE’s Soil Erosion and Sediment Control Guidelines

(excluding Appendices) used to construct the Phase II Pipeline Project in northeastern Maine. 

The FERC’s Plan and Procedures are available for viewing on the FERC Internet website at 

www.ferc.gov. The M&NE Guidelines are provided in Appendix H. Since Downeast has 

adopted the FERC Plan and Procedures, and the M&NE Soil Erosion and Sediment Control 

Guidelines, they will be hereafter referred to as Downeast’s Plan, Procedures, and Soil Erosion 

and Sediment Control Guidelines. Prior to construction, Downeast would prepare an 

Environmental Control Plan (ECP) that would include its Plan and Procedures, and Soil Erosion 

and Sediment Control Guidelines as well as other applicable federal, state, and local 

requirements.

Downeast would be required to develop onshore and offshore Spill Prevention, Control and 

Countermeasure Plans (SPCC Plans) to be implemented during construction of the facilities. 

The SPCC Plans must address potential spills of fuel, lubricants, and other hazardous materials 

and describe spill prevention practices, spill handling and emergency notification procedures, 

and training requirements.

2.3.1 LNG Terminal Facilities

Downeast considered the following factors during site selection and design of the LNG terminal 

facilities in accordance with 49 CFR 193 Subpart B and 33 CFR 127:

• flammable vapor dispersion, thermal radiation protection and separation of facilities;

• seismic forces and soil characteristics; and

• wind forces and other severe natural conditions.

Construction of the LNG terminal facilities would include site preparation, activities associated 

with construction of the pier trestle, unloading platform, LNG storage tanks, and vaporization 

and support facilities.

2.3.1.1 Site Preparation

To prepare the terminal site for construction, areas of the onshore facilities that would be 

disturbed by construction activities would be stabilized with temporary erosion controls, which 

would be maintained until construction is complete. Approximately 47 acres would be cleared 

and grubbed as needed for construction.
2.0 – Description of the Proposed Action 2-26

Off-site staging areas would be used for some fabrication, employee parking, and 

material/equipment storage.

The near-surface competent bedrock would preclude the need for deep foundations or extensive 

excavations. The cut/fill balance is expected to remain on-site. The only fill that Downeast may 

be required to import is structural stone for some of the foundations and possibly the on-site 

roads. Downeast states that there appears to be adequate existing resources in the region to 

provide fill, without the need to develop a new fill resource for the LNG project. However, if a 

new fill source is required, Downeast would file the necessary information with the Commission 

for review and approval.

Some of the larger materials needed for the LNG terminal would be delivered to the project site 

and constructed from working marine barges. All other required materials would be transported 

to the site via truck.

2.3.1.2 LNG Berthing, Vessel Unloading, and Transfer Facilities

A 3,862-foot-long pier equipped with mooring systems and accessories would be constructed for 

the berthing and unloading of LNG vessels. The LNG pier trestle construction would be 

accomplished using a combination of “over the top” construction method using land-based 

equipment working from the pier as it is constructed, and off-shore marine-based equipment. 

The “over the top” method utilizes a temporary (movable) steel frame, supported on the 

permanent pilings as they are installed, to support the crane. The crane would be moved along 

the pier as pilings are installed so that bottom impacts would be limited to the location of each 

piling. As the pier construction progresses into deeper water, the construction methodology 

would switch to marine-based equipment that utilizes a jack-up barge to install the remaining 

portion of the trestle and unloading platform. This construction method would minimize the use 

of barge-mounted equipment, resulting in a substantial reduction of impacts on the seabed from 

anchoring and from propeller wash. 

Large diameter, steel pipe piles are anticipated to be used to support the trestle and loading 

platform. These piles would be vibrated and driven through any surficial soils on the seabed to 

the top of the underlying rock where they would be seated into competent bedrock. The piles

would be anchored into the bedrock using drilled rock sockets. Rock sockets would be 

constructed using rotary auger methods. Impact driving would only be required to embed or 

"seat" the piles into the top of the bedrock, likely only a few feet, to seal the bottom of the piles 

into the rock so that rock sockets can be installed. The LNG mooring and breasting dolphins 

would be constructed using floating or jack-up marine-based equipment. The dolphins would

either be comprised of multiple steel pipe piles supporting a large concrete cap, or a very large 

single steel-pipe type dolphin (monopile). The piles would be similarly driven through any 

surficial soils, if any, at the seabed until the top of rock is encountered. The piles would then be 

seated and affixed to the rock using drilled rock sockets. A precast concrete form would be used 

to contain the cast-in-place concrete used for the remainder of the pile cap. Finally, the fenders, 

mooring hooks, and other topside equipment (railing, ladders, lights, etc.) would be installed.

Once the loading platform and breasting and mooring dolphins are in-place, fabricated steel truss 

walkways would be erected by the marine equipment to interconnect the structures for personnel 

access and operations.
2-27 2.0 – Description of the Proposed Action

The following would also be incorporated into the design of the unloading platform:

• a pier jetty control room (JCR) providing control and monitoring capabilities remotely 

from the MCR during vessel unloading operations;

• a facility firefighting system extended to the unloading berth;

• a gangway to allow access to/from the LNG vessel for customs and immigration officials, 

pilots, operations personnel (including unloading supervisor), and crew members;

• gangways between the unloading platforms and berthing dolphins for use by line handlers 

during the berthing and unberthing of LNG vessels; and

• an LNG spill trough beneath the unloading platform and LNG transfer pipe to route any 

LNG spills to the terminal’s LNG spill containment system. This would be designed in 

accordance with the requirements of NFPA 59A Section 5.2.

2.3.1.3 LNG Storage and Vaporization Facilities

The most labor-intensive and time-consuming activity would be the construction of the LNG 

storage tanks. The two 160,000 m3 full containment LNG storage tanks would be built on a 

ground reinforced concrete slab foundation. The preparation of the ground for the installation of 

the LNG storage tank foundation would take approximately seven months. Once the ground is 

prepared, approximately four months would be required to install the foundation; following 

which, the construction of the LNG storage tank would take approximately 20 months to 

complete. 

Construction of the LNG storage tank and foundation would include the following key activities:

• prepare and level the area upon which the LNG storage tank and foundation would be 

located;

• form and pour the concrete foundation; the tank base heating elements would be installed 

within the poured concrete;

• construct the outer tank carbon steel liner, install the outer tank carbon steel bottom liner 

on the foundation, erect the outer tank carbon steel roof liner on the outer tank bottom,

and erect the inner tank suspended deck and connect to the steel roof;

• raise the outer tank steel roof and suspended deck using an air lift procedure and weld to 

the top compression bar;

• install the tank bottom insulation;

• install the secondary tank and inner tank bottoms;

• erect the inner tank shell;

• construct the outer tank concrete walls;

• install the outer tank concrete roof;

• install and tension concrete wall pre-stress tendons;

• install tank internal accessories, such as pump columns, bottom and top fill pipework, 

instrument wells, purge and cool-down pipework;

• install tank external accessories, such as tank instrumentation, electrical equipment, 

pipework, roof platforms, and access stairways;

• hydrotest the inner tank and, once complete, air dry the tank;
2.0 – Description of the Proposed Action 2-28

• final installation of the tank internal and annual space instrumentation;

• install tank insulation (once tank is completely dry);

• complete visual inspections and conduct final tank clean;

• install in-tank LNG pumps; and

• purge tank with nitrogen to a positive pressure and prepare for cool-down.

The storage tanks would be hydrostatically tested in accordance with API Standard 620, 

Appendix Q.8. API Standard 620 deals with the design and construction of large, welded, fielderected low-pressure carbon steel aboveground storage tanks (including flat-bottom tanks) with a 

single vertical axis of revolution, and Appendix Q deals with low-pressure storage tanks for 

liquefied hydrocarbon gases at temperatures not lower than -270°F (-168○C) (Techstreet 2008). 

Hydrostatic testing of each tank would involve filling the inner tank with approximately 

28 million gallons of water. Water used for the hydrostatic testing of the first tank would be 

used for the hydrostatic testing of the second tank. The tank would be filled and emptied as 

quickly as possible. At the maximum level calculated, the water would be maintained for at least 

48 hours for inspection. After testing, the tank would be cleaned with fresh water and dried. 

Test water would be obtained from on-site water wells, commercial providers, or the adjacent 

waterways. The water would be sampled and analyzed prior to discharge. See section 4.3.2.1 of

this EIS for further information on hydrostatic testing.

2.3.2 Pipeline and Associated Aboveground Facilities

2.3.2.1 General Pipeline Construction Procedures

Figure 2.3-1 shows the typical steps of cross-country pipeline construction. Standard pipeline

construction proceeds in a manner of an outdoor assembly line composed of specific activities 

that make up the linear construction sequence. These operations collectively include survey and 

staking of the right-of-way, clearing and grading, trenching, pipe stringing and bending, welding 

and coating, lowering-in and backfilling, hydrostatic testing, and cleanup. In addition to 

standard pipeline construction, Downeast would use special construction techniques where 

warranted by site-specific conditions. These special techniques would be used when 

constructing across residential areas, waterbodies, wetlands, and roads.

Survey and Staking

All areas to be affected by pipeline construction would be mapped and flagged well in advance 

of actual construction activity. Important resource protection areas, such as stream crossings, 

wetlands, deer wintering areas (DWAs), inland waterfowl and wading bird habitat (IWWH), and 

significant vernal pools (SVPs), would be specifically marked and flagged, as well as posted 

with signage. Prior to actual field work by the pipeline crews, the Environmental Inspector(s) 

(EI) would guide the crew management personnel on a site-by-site review of the mapped and 

protected areas. Construction restrictions and management methods designed to protect the 

specified areas would be specifically reviewed with the pipeline crews prior to construction.
2-29

Figure 2.3-1 

Downeast LNG Project

Typical Pipeline Construction Sequence
2.0 – Description of the Proposed Action 2-30

Clearing and Grading

Where necessary and unavoidable, the right-of-way would be cleared of vegetation and roughgraded to specified widths. Clearing and grading in temporary workspaces would be limited to 

encourage natural revegetation. Vegetative or other waste removed from the pipeline right-ofway would be properly disposed of in accordance with applicable permit conditions. Erosion 

controls would be installed as soon as possible after initial clearance and disturbance of an area’s 

surface soils.

Trenching

Trench excavation widths and depths would be predetermined prior to the start of pipeline 

construction. Typically, excavation would be limited to the depth required to allow for the burial 

of the pipe plus 3 feet of cover in soil areas as required by 49 CFR Part 192. Typically, the 

trench would be about 6 feet deep (for a minimum of 3 feet of cover over the pipe) and between 

10 to 25 feet wide. The depth of the pipeline should prevent any impacts from frost heaves. The 

pipeline ditch would be excavated with either a rotary trencher or track-mounted backhoe.

To avoid or minimize the mixing of topsoils with subsoils, topsoil segregation methods would be 

conducted as specified in Downeast’s Plan, Procedures, and Soil Erosion and Sediment Control 

Guidelines, agency requirements, or landowner specifications. 

Pipe Stringing, Bending, and Welding

Pipeline crews would “string” the pipe sections to be lain in a trench area along previously 

specified points. Pipe sections would be off-loaded from trucks and placed in the stringing area 

using side-boom equipment or other suitably capable equipment. The pipe sections would then 

be lined up end to end to allow for welding and bending into continuous lengths. Pipe welding 

would be performed in accordance with API Standard No. 1104 (most current revision). Quality 

assurance/quality control (QA/QC) would be conducted in accordance with 49 CFR Part 192.

Lowering-In and Backfilling

Coated and inspected pipe lengths would be lowered into prepared trenches. After the pipeline 

has been placed in the trench, the pipeline would be covered with a soil material padding that 

acts as a buffer between the pipeline and the backfill. The remainder of the trench would be 

backfilled with suitable soil material. Ideally, the material that was excavated for the trench 

would be used as backfill. Where the material is not suitable as backfill, imported material 

would be used. The trench may be over-backfilled to allow for additional settlement over time. 

Once the pipeline has been installed, it would be cleaned out of loose impediments that may have 

been left over from the installation process by using compressed air-driven manifolds.

Hydrostatic Testing

After cleaning and prior to service, the pipeline would be tested in accordance with 49 CFR 

Part 192. The test consists of placing the pipeline under hydrostatic pressure to verify its 

structural integrity for its design pressure load. If a leak or break in the line were to occur during 

testing, Downeast would repair and retest that section of pipe until the DOT specifications are 

met. After testing is completed, the water would be discharged in accordance with Maine 
2-31 2.0 – Description of the Proposed Action

Pollutant Discharge Elimination System (Maine PDES) permit requirements. Hydrostatic testing

is addressed further in section 4.3.2.2 of this EIS.

Cleanup and Restoration

Following backfilling, all work areas would be final-graded and restored to pre-construction 

contours as closely as possible. Prior to final grading, all construction debris would be picked up 

along the right-of-way. Permanent erosion control structures, such as slope breakers, would be 

installed during final grading, in accordance with Downeast’s Plan, Procedures, and Soil Erosion 

and Sediment Control Guidelines. Downeast would restore the work areas within one week after 

the trench has been backfilled and graded. In addition, restoration of wetlands would be 

conducted in accordance with Downeast’s Plan, Procedures, and Soil Erosion and Sediment 

Control Guidelines, and any COE permit conditions. Private property such as fences, field 

roads, and driveways would be restored or repaired as necessary.

Revegetation would be accomplished by seeding disturbed areas with native seed mixtures in 

accordance with the recommendations of the local office of the Natural Resources Conservation 

Service (NRCS) or as requested by the landowner. Revegetation is further discussed in 

section 4.4.2 of this EIS.

All construction work areas would be monitored for the success of revegetation and restoration. 

Inspections would be conducted after: (1) initial regrading, stabilization, and reseeding; (2) at the 

beginning and latter parts of the first full growing season; and (3) during the second growing 

season. Restoration and revegetation success evaluations would be based on predetermined 

criteria established in Downeast’s Plan, Procedures, and Soil Erosion and Sediment Control 

Guidelines and with the various agencies and expressed as conditions in relevant permits and 

approvals.

2.3.2.2 Special Pipeline Construction Techniques

Utility and Road Crossings

Prior to construction, Downeast would contact the local Dig Safe system to determine the 

location of utilities to be crossed. These utility crossings would then be marked in the field 

during pre-construction surveys.

Paved roads would be crossed using a bore. For the bore method, pits would be excavated on 

both sides of the road at the depth of the ditch. A boring machine uses an auger to drill a tunnel 

under the road, wide enough for the pipeline and casing to be pulled through. Unpaved county 

roads would be open-cut. During the cut, usually one lane of traffic would be left open. Steel 

plates may be used to cover the open trench.

Utility and road crossings would be done according to applicable permits. Local authorities 

would be kept apprised of the timing of such crossings. Roadway surfaces would be restored in 

a timely fashion according to state and local specifications.

Residential Areas

The draft EIS described 19 residences that would be within 50 feet of the permanent right-ofway. Downeast subsequently revised its pipeline route and work areas to increase the distance 

between the residences and construction work areas. There are now only two residences located 
2.0 – Description of the Proposed Action 2-32

approximately 50 feet from the construction right-of-way. Construction in residential areas 

would employ several construction practices to protect public safety and minimize disturbance of 

these areas. These practices include:

• installing safety fencing along the edge of the permanent right-of-way out to a distance of

100 feet on either side of the residence;

• preparing access and establishing environmental protection devices in accordance with 

Best Management Practices (BMPs); 

• immediate restoration of driveways, lawn areas, and landscaping within the construction 

work areas except where required for continued construction access; and

• immediate restoration of all remaining areas following final restoration.

A more detailed discussion of the route variations and residential areas can be found in 

sections 3.8.2.2 and 4.7.2.3, respectively. 

Wetlands and Waterbodies

Downeast would construct the project facilities in accordance with Downeast’s Procedures and 

Soil Erosion and Sediment Control Guidelines. For conventional wetland crossings, Downeast 

would segregate the top 12 inches of topsoil. When crossing saturated wetlands, Downeast

would use wooden swamp mats to minimize the disturbance to wetland soils. 

Most stream crossings would be open-cut using excavation equipment and the dam and pump 

crossing method. The dam and pump crossing method is a dry-crossing technique that uses 

pumps to isolate water from the construction area. Downeast proposes to cross SVPs and

selected rivers with riffle pools with horizontal directional drill (HDD) to avoid or minimize 

impacts to these sensitive environmental resources. A more detailed discussion of waterbody 

and wetland construction can be found in sections 4.3.2 and 4.4.1 of this EIS, respectively.

Rock Blasting and Rugged Topography

Rock encountered during construction would be removed using various techniques, including 

conventional backhoe excavation, dozer ripping and backhoe excavation, use of a backhoe 

hammer and backhoe excavation, or blasting and backhoe excavation. Excess rock would be 

windrowed on the right-of-way with landowner permission, or removed to an off-site approved 

rock disposal area. Blasting activity would be performed by licensed professionals according to 

strict guidelines designed to control energy release. Blasting is discussed further in 

section 4.1.1.2 of this EIS.

The proposed sendout pipeline does not cross through any areas of steep side slopes that would

require special construction techniques. Construction along moderate side slopes would be 

necessary. Permanent trench breakers consisting of sandbags would be installed in trenches over 

and around the pipe in areas of slope with the potential for erosion.

2.3.2.3 Aboveground Facility Construction Procedures

Three MLVs and two pigging facilities would be constructed for the sendout pipeline. The MLV 

and pig launching facility at the start of the sendout pipeline would be constructed within the 

LNG terminal site. The MLV at MP 17.17 north of U.S. Route 1 would require approximately 
2-33 2.0 – Description of the Proposed Action

0.3 acre for construction and 0.4 acre for permanent operation. The MLV and pigging facilities 

at the terminus of the sendout pipeline would be located at MP 29.8 within the Baileyville 

Compressor Station property boundary.

2.4 CONSTRUCTION SCHEDULE

Downeast anticipates that construction of the entire project would take a total of about 

35 months. The first part of this process would be terminal site work and foundation preparation 

for the LNG storage tanks. Once the tank foundations are in place, work would begin on tank 

construction, terminal buildings, and the marine terminal. It is anticipated that the LNG storage 

tank construction would take approximately 30 months from the start of site work. The other 

terminal facilities would be constructed in approximately 18 months with marine construction 

taking approximately 16 months. Sendout pipeline construction would take approximately 9 to 

12 months. 

2.5 ENVIRONMENTAL COMPLIANCE AND MONITORING

Downeast would implement environmental compliance and monitoring requirements from its 

Plan and Procedures and the Soil Erosion and Sediment Control Guidelines during construction 

of the LNG terminal and sendout pipeline. Downeast would also incorporate compliance and 

monitoring requirements from federal, state, and local permits obtained for the project.

Downeast would conduct mandatory environmental training for all relevant Downeast and 

contractor personnel involved with construction of the import terminal and pipeline facilities. 

Downeast would employ at least one EI for construction of the LNG terminal, and at least one EI 

for construction of the pipeline. The EIs would be responsible for monitoring construction 

activities for compliance with the conditions of the FERC Certificate, and all other applicable 

federal, state, and local permits. The EIs would have independent status, but would report to the 

Lead Downeast Inspector, and would have stop-work authority in the event of a noncompliance 

issue that requires corrective action.

The FERC and its own independent EIs would monitor the project for compliance with the 

Commission’s environmental conditions. In addition, Downeast would comply with Maine DEP 

requirements and employ third-party inspectors to ensure that erosion control and other 

environmental safeguards are in place and maintained during construction.

2.6 OPERATION AND MAINTENANCE

2.6.1 LNG Terminal Facilities

According to Downeast, imported LNG would be obtained from unspecified liquefaction plants 

throughout the world (e.g., Trinidad, Nigeria, Qatar, Algeria, Oman, Abu Dhabi, and Libya) and 

delivered via LNG vessels to the proposed terminal. LNG vessels would be under the control of 

local pilots during the LNG marine transit to and from the terminal. In accordance with the 

WSR recommendations, the attending pilots would decide, in consultation with and the 

concurrence of the COTP, whether the weather, current, visibility, and wind conditions allow 

safe entry to the harbor. Based on recommendations in the WSR, LNG vessels would be 

escorted by three to four assist tugs (depending on vessel size) to provide assistance in the 

unlikely event of a mechanical failure to the LNG vessel or during adverse weather conditions, 
2.0 – Description of the Proposed Action 2-34

with one tug tethered at all times during the transit to the terminal. The WSR also recommends 

that authorized Coast Guard vessels escort the LNG vessels during transit. In addition, the WSR 

recommends that a standby tug be moored outboard of the berthed LNG vessel during its stay at 

the terminal. 

Upon arrival at the terminal, the vessel would be berthed using a site-specific vessel approach 

system and secured with a mooring system equipped with a line monitoring system to 

continuously monitor tension of all mooring lines. The vessels would use onboard pumps to 

transfer the LNG at approximately -270°F (-168○

C) through the unloading arms and insulated 

pipe to the LNG storage tank at a rate of approximately 14,000 cubic meters per hour (m3

/hr).

During vessel unloading, vapor in the LNG storage tank would be displaced by the newly added 

LNG. The displaced vapor would be returned to the vessel by vapor return blowers through a 

vapor return line and a vapor return arm connected to the vessel in order to maintain the pressure 

in the vessel’s tanks. Additional BOG would be generated due to the heat added by the vessel’s 

transfer pumps and the heat leak into the tank and piping systems. Any BOG not returned to the 

vessel would be compressed by the BOG compressors and condensed in the BOG condenser. 

When a vessel is not unloading, the in-tank column-mounted LNG pumps would circulate LNG 

through a small diameter circulation line to the pier and back through the unloading line and to 

the sendout area in order to keep these piping systems cold. In this operating mode, BOG would 

be continuously generated in the tank due to the heat leak into the system piping, from heat leak 

through the insulated tank walls, and from the heat added by the pump. Under these operating 

conditions, the BOG would be compressed by the BOG compressors and condensed in the BOG 

condenser. 

LNG would be pumped out of the LNG storage tank via in-tank, column mounted low pressure 

LNG sendout pumps. The LNG pressure is increased to pipeline sendout pressure by high 

pressure LNG pumps before being vaporized into natural gas. Natural gas sendout would be 

routed through Downeast’s sendout pipeline to the M&NE pipeline system at the Baileyville 

Compressor Station for delivery to end users.

Downeast would operate and maintain its facilities in compliance with 49 CFR 193, 33 CFR 127, 

NFPA 59A, and other applicable federal and state regulations. In accordance with 49 CFR 

193.2503 and 193.2605 and Sections 11.3.1 and 11.5.2 of NFPA 59A, Downeast is required to 

prepare and submit manuals that address specific procedures for the safe operation and 

maintenance of the LNG storage and processing facilities. These manuals would address startup, 

shutdown, cool-down, purging, and other routine operation, maintenance, and monitoring 

procedures. In accordance with 33 CFR 127.305, Downeast would also prepare an operation 

manual that addresses specific procedures for the safe operation of the vessel unloading facilities. 

These manuals would include training requirements and programs for operation and maintenance 

personnel.

2.6.2 Pipeline and Associated Aboveground Facilities

Downeast would operate and maintain the proposed pipeline and associated aboveground 

facilities in accordance with the applicable safety standards established by the DOT Minimum 

Federal Safety Standards as specified in 49 CFR 192 and in accordance with the NGA. The 
2-35 2.0 – Description of the Proposed Action

pipeline would be patrolled from the air and/or ground on a periodic basis. This patrol would 

provide information on possible leaks, encroachment onto the right-of-way, third-party 

construction activity near the pipeline, erosion, exposed pipe, or population density changes in 

the vicinity of the pipeline. Operation would also include monitoring of cathodic protection 

units (installed for corrosion control) along the pipeline to ensure proper functioning. 

Maintenance activities would include regularly scheduled gas leak surveys, and measures 

necessary to repair any leaks. All fence posts, signs, marker posts, aerial markers, and decals 

would be painted or replaced as necessary to ensure the pipeline location remains visible from 

the air and ground. All valves would be periodically inspected and greased. Maintenance would 

also include periodic seasonal mowing of the permanent right-of-way, and vegetation control 

around aboveground facilities. Vegetation control within the 50-foot-wide permanent right-ofway would be conducted every three to five years. A 10-foot-wide area directly over the 

pipeline would be mowed on an annual basis. According to Downeast’s Plan, Procedures, and 

Soil Erosion and Sediment Control Guidelines, herbicides and pesticides would not be used in or 

within 100 feet of a waterbody or wetland. In addition, our regulations at 18 CFR 380.15 

prohibit chemical control of vegetation unless authorized by the landowner or land-managing 

agency. If chemical use is authorized, our regulations require they be approved by EPA for such 

use and used in conformance with all applicable regulations.

2.7 SAFETY CONTROLS

2.7.1 LNG Terminal Facilities

The LNG terminal facilities would be sited, designed, constructed, operated, and maintained in 

compliance with federal safety standards. Federal siting and design requirements for LNG 

terminal facilities are summarized in table 2.7.1-1.

2.7.1.1 Spill Containment

The LNG storage tanks that would be installed at the Downeast LNG terminal would be a full 

containment tank with a primary inner container and a secondary outer container. The tanks

would be designed with a self-supporting inner container. The secondary container would be 

capable of independently containing the LNG. The primary container would contain the LNG 

under normal operating conditions. The secondary container would be capable of containing 

110 percent of the inner container capacity and of controlling vapors resulting from the product 

leakage from the inner container.

In addition to the full containment storage tanks, three LNG containment basins in the process, 

vaporizer, and LNG transfer area would be located at the LNG terminal site. Each LNG spill 

containment basin would be an insulated concrete design. The containment basins would be 

designed to hold a volume equal to a 10-minute spill. In accordance with Section 2.2.2.7 of 

NFPA 59A, the containment basins would include automatically activated sump pumps to clear 

rainwater from the spill containment basins. Water removed from the spill containment basins 

would be pumped to the stormwater discharge system. The sump pumps would be equipped 

with thermal interlocks to prevent LNG from being pumped into the drainage systems.
2.0 – Description of the Proposed Action 2-36

TABLE 2.7.1-1

Federal Siting and Design Requirements for LNG Facilities

Requirement Description

Thermal Radiation Protection (49 CFR 193.2057 

and Section 2.2.3.2 of NFPA 59A) 

This requirement is designed to ensure that certain public land 

uses and structures outside the LNG facility boundaries are 

protected in the event of an LNG fire.

Flammable Vapor-Gas Dispersion Protection 

(49 CFR 193.2059 and Sections 2.2.3.3 and

2.2.3.4 of NFPA 59A)

Seismic Design (49 CFR 193.2101, and NFPA 59A)

This requirement is designed to prevent a flammable vapor cloud 

associated with an LNG spill from reaching a property line of a 

property suitable for building.

This requirement outlines the necessary site specific seismic 

hazard study and specifies that critical safety-related components 

of the facility must be designed to survive earthquake ground 

motions estimated to have a 1 to 2 percent probability of 

occurring within a 50-year period.

Wind Forces (49 CFR 193.2067) This requirement specifies that all facilities be designed to 

withstand sustained wind forces of not less than 150 miles per 

hour without the loss of structural integrity.

Impounded Liquid (Section 2.2.3.8 of NFPA 59A) This requirement specifies that liquids in spill impoundment 

basins cannot be closer than 50 feet from a property line of a 

property suitable for building or a navigable waterway.

Container Spacing (Section 2.2.4.1 of NFPA 59A) This requirement specifies that LNG containers with capacities 

greater than 70,000 gallons must be located a minimum distance 

of 0.7 times the container diameter from the property line or 

buildings.

Vaporizer Spacing (Section 2.2.5.2 of NFPA 59A) This requirement specifies that integral heated vaporizers must 

be located at least 100 feet from a property line of a property 

suitable for building and at least 50 feet from other select 

structures and equipment.

Process Equipment Spacing (Section 2.2.6.1 of 

NFPA 59A)

This requirement specifies that process equipment containing 

LNG or flammable gases must be located at least 50 feet from 

sources of ignition, a property line of a property suitable for 

building, control rooms, offices, shops, and other occupied 

structures.

Marine Transfer Spacing (33 CFR 127.105) This requirement specifies that each LNG unloading flange must 

be located at least 985 feet from any bridge crossing a navigable 

waterway. 

2.7.1.2 Hazard Detection System

A Hazard Detection and Mitigation System (HDMS) would be installed to continuously monitor 

and alert the operator of hazardous conditions throughout the terminal from fire, combustible gas 

leaks, and low temperature LNG spills. The terminal would have a dedicated standalone system 

for fire, heat, combustible gas, smoke or combustion product, and low temperature LNG spill 

monitoring. Fire and gas detection and protection of offices and other buildings would be 

networked. These would provide common alarms and status information to the HDMS. An 

independent Safety Instrumentation System (SIS) would also be installed. 

HDMS monitoring capability would be provided via graphic displays located in the MCR and 

the JCR. The terminal would be controlled primarily from the MCR which would be the primary 

operator interface and monitoring center for the terminal. The JCR would be the control center 

for unloading operations and would be located on the unloading platform and manned during 

unloading operations. Both the MCR and the JCR would be equipped to activate the emergency 

shutdown (ESD) system for the terminal. The MCR operations personnel would also be able to 
2-37 2.0 – Description of the Proposed Action

monitor critical alarms and process variables and would be able to manually shut down the 

unloading operations.

2.7.1.3 Fire Protection System

A firefighting system including fixed and portable firewater and chemical extinguishers and high 

expansion foam systems would be designed for the facility. The main components of the fire 

protection system at the LNG terminal include:

• a 360,000-gallon firewater storage tank based on a two-hour sustained flow rate, as 

required by NFPA 59A. The firewater storage tank would receive water recovered from 

the SCVs;

• electric and diesel fire pumps located onshore that would draw water from the firewater 

tank. Each pump would be designed to provide 3,000 gallons at 100 psig;

• single jockey pump to maintain system pressure in the firewater system;

• an LNG storage tank deluge system would be installed to protect storage tanks that are 

exposed to the heat from fire involving an adjacent tank. The deluge system would draw 

water from the Passamaquoddy Bay;

• emergency back-up diesel fire pumps that would draw water from the Passamaquoddy 

Bay. These pumps would be capable of supplying water directly to the pier, the LNG 

storage tank deluge system, and to the firewater tank to provide emergency makeup water 

for the firewater system; and

• dry chemical systems consisting of total flooding systems, local application (either fixed 

nozzle and/or hose line systems), and/or portable extinguishers (handheld and wheeled).

Nitrogen Snuffing System

Nitrogen snuffing would be provided at the LNG terminal vent and cold tip vent and would be 

designed to inject sufficient nitrogen within the vent to maintain oxygen levels below the 

flammability limits of methane. 

High Expansion Foam System

Downeast would install a high expansion foam system for the LNG terminal facility. The high 

expansion foam system would be designed and installed in accordance with NFPA 11A and 

would be located at each LNG spill containment basin to control ignited or unignited LNG spills.

Vent Systems

The terminal would be designed to minimize fugitive emissions with no venting during normal 

operations using a closed vent drain system. All LNG and natural gas relief valves (excluding 

LNG storage tank, fuel gas drum and LNG vaporizer relief valves) are vented to a closed vent 

system that is common with the LNG storage tank vapor spaces. In case of excess relief system 

pressure, the vent pressure control valve would dump gas to the vent stack. A continuous 

nitrogen gas sweep would be incorporated downstream of the control valve to ensure proper 

purging of the vent stack.
2.0 – Description of the Proposed Action 2-38

Emergency Shutdown System

The terminal would have an ESD system with shutdown and control devices designed to 

maintain safe operating conditions. The ESD system would be used for major incidents and 

would result in either total plant shutdown, shutdown of vessel unloading, shutdown of the 

sendout system, and/or shutdown of individual pieces of equipment depending on the type of 

incident. Two levels of shutdown would be configured for the LNG terminal:

• ESD-1 Shutdown of unloading operations and isolation of the pier and activation of the 

emergency release couplings on each of the LNG unloading arms and the vapor return 

arm.

• ESD-2 Shutdown of LNG/NG sendout operations, including ESD-1. This action would 

isolate the terminal from the natural gas sendout pipeline and from any LNG vessel that 

would be berthed at the unloading platform. 

The MCR and JCR would be equipped with push buttons that activate the ESD system.

2.7.2 Pipeline and Associated Aboveground Facilities

2.7.2.1 Corrosion Protection and Detection Systems

During construction of the proposed facilities, Downeast would install a cathodic protection 

system to prevent or minimize corrosion of the buried pipeline and aboveground facilities. The 

cathodic protection system impresses a low-voltage current on the pipeline to offset natural soil 

and groundwater corrosion potential. The condition of the pipe coating and the effectiveness of 

the cathodic protection system would be monitored during regularly scheduled cathodic 

protection surveys in accordance with federal standards and regulations. Cathodic protection 

surveys usually require walking the pipeline right-of-way with monitoring instruments. Repairs 

to the pipe, the pipe coating, or the cathodic protection system would be made as appropriate.

Downeast would also install a Supervisory Control and Data Acquisition (SCADA) system in the

operations control center to provide for pipeline control and monitoring at all times. If system 

pressures fall outside a pre-determined range, an alarm would be activated at the operations 

center. A real time leak detection system would also be provided for the pipeline.

2.7.2.2 Emergency Response Procedures

The proposed pipeline and aboveground facilities must be designed, constructed, operated, and 

maintained in accordance with the DOT Minimum Federal Safety Standards in 49 CFR 192. 

The regulations are intended to ensure adequate protection for the public and to prevent natural 

gas facility accidents and failures. Part 192 specifies material selection and qualification; 

minimum design requirements; and protection from internal, external, and atmospheric 

corrosion. Part 192 also prescribes the minimum standards for operating and maintaining 

pipeline facilities, including the requirement to establish a written plan governing these activities. 

Under Section 192.615, each pipeline operator must also establish an emergency plan that 

includes procedures to minimize the hazards in a natural gas pipeline emergency. Key elements 

of the plan include procedures for:
2-39 2.0 – Description of the Proposed Action

• receiving, identifying, and classifying emergency events, gas leakage, fires, explosions, 

and natural disasters;

• establishing and maintaining communications with local fire, police, and public officials, 

and coordinating emergency response;

• making personnel, equipment, tools, and materials available at the scene of an 

emergency;

• protecting people first and then property, and making them safe from actual or potential 

hazards; and

• emergency shutdown of system and safe restoration of service.

Part 192 also requires that each operator must establish and maintain a liaison with appropriate 

fire, police, and public officials to learn the resources and responsibilities of each organization

that may respond to a natural gas pipeline emergency, and to coordinate mutual assistance. The 

operator must also establish a continuing education program to enable customers, the public, 

government officials, and those engaged in excavation activities to recognize a gas pipeline 

emergency and report it to appropriate public officials.

2.8 FUTURE PLANS AND ABANDONMENT

Downeast has not indicated that it has plans to expand the facility beyond two 160,000 m3

storage tanks with a nominal sendout capacity of 500 MMcfd with a peak capacity of 

625 MMcfd. Downeast currently has no plans for future expansion or abandonment of the 

proposed terminal or pipeline facilities. Downeast does not foresee abandonment of the terminal 

facility prior to the expiration of its design life (25+ years) or beyond, provided that terminal 

components are properly maintained and operated. If abandonment were to occur, Downeast has 

committed to the Town of Robbinston to restore the property parcel to a non-industrial condition 

by the removal of terminal components and land restoration actions. This commitment would be 

insured by a reclamation bond or similar financial guarantee. Should the facilities be expanded 

or abandoned, a FERC authorization or Certificate and the associated environmental and nonenvironmental analysis would be required. In addition, the expansion or abandonment would be 

subject to appropriate federal, state, and local regulations in effect at that time.

2.9 NONJURISDICTIONAL FACILITIES

Electrical power to the facility would be supplied by EMEC with a direct tie-in to the property 

site. EMEC would install a new electric transmission line from their existing switchyard in 

Milltown to a new substation that would be located across U.S. Route 1 (on the west side of 

Route 1) from the terminal facility in Robbinston. The proposed location of the new electric 

transmission line and substation is shown on figures in Appendix I. Both the electric 

transmission line and the substation would be dedicated to service the Downeast LNG terminal 

site; therefore, the potential impacts are associated with the Downeast LNG Project.

The electric transmission line would be approximately 13.7 miles in length and would consist of 

a 69-kilovolt (kV) line. As described in section 2.2.2.1, Downeast anticipates that approximately 

11.4 miles of the transmission line would be adjacent to the Downeast sendout pipeline from 

MP 0.2 to MP 11.6. The remaining 2.3 miles of the electric transmission line route has not been 
2.0 – Description of the Proposed Action 2-40

finalized, but has been preliminarily sited to run northwest from the sendout pipeline to a point 

of origin in the town of Calais (see Appendix I-1). 

The substation would be located in a previously disturbed area, on private property that the 

owner has agreed to sell for the substation. Most of the construction activity is expected to occur 

within the substation area footprint, which is 0.25 acre, and the access driveway. The acreage of 

temporary impact due to construction activity is expected to be marginal and immediately 

adjacent to the substation area. The Downeast LNG terminal would receive power from the 

substation via a direct electrical feed through a belowground conduit that would pass under 

U.S. Route 1 and tie-in with the facility at the utility building. 

The transmission line would be an intrastate extension of the EMEC electrical distribution 

system. EMEC would construct, own, operate, and maintain the transmission line and the 

substation. There are no FERC-required permits or approvals for the transmission line or the 

substation. Both facilities are subject to the state review process under the jurisdiction of the 

Maine Public Utilities Commission (Maine PUC). Permits and approvals for these

nonjurisdictional facilities would be obtained by EMEC as necessary. Because Downeast would 

not require electrical service at the project site until after a FERC decision on the LNG project, 

Downeast has indicated that EMEC has not yet applied for the required environmental permits or 

approvals for the electrical facilities.

2.9.1 Summary of Environmental Impacts

Information filed by Downeast concerning the proposed sendout pipeline project, as well as data 

compiled by review of United States Geological Survey (USGS) topographic maps and National 

Wetlands Inventory (NWI) maps, has been used in the following sections to provide a summary 

of potential environmental impacts of the planned EMEC nonjurisdictional facilities. 

2.9.1.1 Water Resources

A total of six waterbodies would be crossed by the electric transmission line from MP 0.2 to 

MP 11.6. Of these, three would be minor crossings (less than 10 feet in width), and three

intermediate (between 10 and 100 feet wide). A detailed description of these waterbodies and 

others crossed by the Downeast sendout pipeline can be found in section 4.3.2.2. No 

waterbodies would be crossed by the 2.3 miles of transmission line not collocated with the 

sendout pipeline (from point of origin in the town of Calais to sendout pipeline MP 11.6). 

Activities that could affect surface waters include clearing, construction, and right-of-way 

maintenance. These activities could result in increased turbidity and sedimentation from 

rainwater runoff. It is expected that impacts from the crossing of waterbodies by the overhead 

electric transmission line would be minimal. 

2.9.1.2 Vegetation

Wetlands

The extent of impact on wetlands crossed by the electric transmission line would be dependent 

on the type of wetland affected, the existing quality of the wetland, the time of year, and the 

construction methods. 
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As detailed in section 4.4.1.3, forested wetlands along the electric transmission line route 

collocated with the sendout pipeline right-of-way are typically dominated by needle-leaved 

evergreen trees, balsam fir, red spruce, northern white cedar, and larch, with subdominant broadleaved deciduous hardwoods, paper birch, red maple, and quaking aspen. Characteristic 

understory vegetation includes beaked hazelnut, mountain holly, cinnamon fern, evergreen wood 

fern, swamp dewberry, and Sphagnum moss. Scrub-shrub wetlands are often dominated by 

meadowsweet, speckled alder, and steeplebush and have herbaceous vegetation that includes 

sensitive fern, pointed broom sedge, and rattlesnake mannagrass. Emergent wetlands are 

characterized by rushes, sedges, and broad-leaved cat-tail. 

Ten vernal pools have been identified within the electric transmission line route collocated with 

the sendout pipeline right-of-way, five of which are classified as SVPs. Table 4.4.1.3-1 

summarizes locations and general description of vernal pools located within the sendout pipeline 

corridor. The potential impacts on wetlands and vernal pools would depend on the exact location 

of the electric transmission towers/poles, proposed construction techniques, and mitigation 

measures. It is anticipated that EMEC would need to take steps to avoid or minimize impacts on 

wetlands and SVP habitats. 

Preliminary reviews of USGS topographic maps and NWI maps indicate that no wetlands would 

be crossed by the final 2.3 miles of the electric transmission line route. However, because the 

location of this route has not been finalized and no survey of the area has been conducted, the 

existence of wetlands and vernal pools cannot be verified. EMEC would consult with the Maine 

DEP to identify steps needed to avoid or minimize impacts on both wetlands and vernal pools.

Forests

The electric transmission line route is predominantly covered by mature forest habitat 

characterized as spruce-fir, spruce-northern hardwoods, and white-pine mixed hardwoods 

(Gawler and Cutko 2004). Of these forest types, the spruce fir forest is the most prevalent. 

Other vegetation communities found along the route include early successional forests and 

maintained open areas such as open fields, residential, and agricultural land. A detailed 

description of the forest environment crossed by the Downeast sendout pipeline route can be 

found in section 4.4.2.3. While the remaining 2.3 miles of the electric transmission line route 

have not yet been surveyed, it is expected that the forest composition would be similar to that of 

the proposed sendout pipeline route.

2.9.1.3 Threatened and Endangered Species

State-Listed and Other Special Status Species 

Bald Eagle

Downeast reviewed information from Maine Department of Inland Fisheries and Wildlife 

(Maine DIFW) that identified the presence of several historic and active bald eagle nests in 

proximity to the proposed sendout pipeline (see section 4.6.1.2 for details on the bald eagle and 

section 4.6.2.3 for details on bald eagle mitigation in the sendout pipeline corridor). In all, 

1.7 acres (area calculated using a radius of 0.25 mile from nest locations) of inactive nesting 

habitat were identified along the proposed sendout pipeline, which would be affected by the 

construction of the EMEC electric transmission line adjacent to the sendout pipeline corridor. 
2.0 – Description of the Proposed Action 2-42

The presence or absence of bald eagles is unknown for the remaining 2.3 miles of electric 

transmission line that would not be adjacent to the sendout pipeline right-of-way. EMEC would 

consult with Maine DIFW to determine if active or historic bald eagle nesting habitat exists in 

the area.

2.9.1.4 Land Use

Most of the land that would be affected along the electric transmission line (see section 4.7.1 for 

land use details) would be forest land. Other land uses affected along the transmission line 

would include wetland areas, developed land, agricultural land, grassland/herbaceous land, and 

unconsolidated shore. The remaining 2.3 miles of electric transmission line not adjacent to the 

sendout pipeline corridor is expected to be predominantly forest land and possibly some 

developed land near the town of Calais. 

Two residences are approximately 50 feet from the Downeast sendout pipeline construction

right-of-way at MP 0.63 and MP 0.91. It is likely that the remaining 2.3 miles of electric 

transmission line that would not be adjacent to the sendout pipeline corridor would impact 

residential structures only near the point of origin in the town of Calais. Once the electric 

transmission line route is finalized, EMEC would negotiate with the landowners to obtain an 

easement in order to construct and operate the transmission line.

2.9.1.5 Cultural Resources

From MP 0.2 to MP 11.6, there are no recorded archeological sites that are listed in or potentially 

eligible for listing in the NRHP. Two areas that are yet to be tested, pending permission of 

landowners, have the potential to contain archeological resources that may be eligible for listing 

in the NRHP. We do not currently have information about previously recorded archeological 

sites in areas of the EMEC transmission line that are not adjacent to the Downeast sendout 

pipeline.

There are no standing structures that may be eligible for listing in the NRHP that have been 

recorded within the vicinity of MP 6 to MP 11.6. A number of standing structures that are styledated as 50 years old or older have been recorded near MPs 1, 2, and 5. Visual impact on 

structures that are potentially eligible for listing in the NRHP may result from construction of the 

transmission line. The potential impacts would need to be assessed once a route is finalized and 

details of pole material, height, and interval are determined. We do not have information about 

recorded structures that may be eligible for listing in the NRHP that are located in areas not 

aligned with the Downeast sendout pipeline and that may be affected by the transmission line. 

2.9.2 Conclusion

Under NEPA, the Commission has the responsibility to review infrastructure facilities that are 

associated with, and a necessary part of, a jurisdictional project. We have summarized the 

environmental impacts of these nonjurisdictional facilities above. EMEC would obtain the

necessary permits and authorizations from the Maine PUC and other relevant agencies prior to 

construction of these facilities.