4-1 4.1 – Geologic Resources

4.0 ENVIRONMENTAL ANALYSIS

The environmental consequences of constructing and operating the proposed Downeast LNG 

Project would vary in duration and significance. Four levels of impact duration were considered: 

temporary, short-term, long-term, and permanent. Temporary impact generally occurs during 

construction with the resource returning to preconstruction condition almost immediately 

afterward. Short-term impact could continue for up to three years following construction. 

Impact was considered long-term if the resource would require more than three years to recover. 

A permanent impact could occur as a result of any activity that modifies a resource to the extent 

that it would not return to preconstruction conditions during the life of the project, such as the 

construction of an LNG terminal. We considered an impact to be significant if it would result in 

a substantial adverse change in the physical environment.

In this section, we discuss the affected environment, general construction and operational 

impacts, and proposed mitigation for each resource. We have also included a discussion on the 

waterway for LNG marine traffic, including the potential impacts on environmentally sensitive 

resources along the waterway.

Downeast, as part of its proposal, agreed to implement certain measures to reduce impact. We 

evaluated Downeast’s proposed mitigation to determine whether additional measures are 

necessary to reduce impact. These additional measures appear as bulleted, boldfaced paragraphs 

in the text. We recommend that these measures be included as specific conditions to 

authorizations that the Commission may issue to Downeast.

Conclusions in this EIS are based on our analysis of the environmental impact and the following 

assumptions:

• Downeast would comply with all applicable laws and regulations;

• the proposed facilities would be constructed as described in section 2.0 of this document; 

and

• Downeast would implement the mitigation measures included in the application and 

supplemental filings to the FERC.

4.1 GEOLOGIC RESOURCES

4.1.1 Geologic Setting

Maine, New Hampshire, and Massachusetts are part of the New England Physiographic 

Province, which forms a portion of the Appalachian Highlands Division. The region is 

subsequently divided into three major physiographic zones: the White Mountain, the New 

England Upland, and the Seaboard Lowland sections. The project crosses the two latter sections. 

The New England Upland occupies northern, eastern, and central Maine. It is an area with 

moderate relief characterized by hills and low mountains from a few hundred feet to about 

1,500 feet. The Seaboard Lowland in Maine, New Hampshire, and Massachusetts lies along the 

coast between the New England Upland and the Atlantic Ocean. It varies in width from about 

20 miles near the New Hampshire border to about 60 miles near the New Brunswick border. 

This section has generally low relief and elevations typically of less than 400 feet, except for 

occasional hills and low mountains in isolated spots. 
4.1 – Geologic Resources 4-2

Much of the landscape was shaped by Wisconsinian glaciation that created the many hills and 

glacial features still present today. As the glaciers began to melt around 13,000 years ago, sea 

level rose to cover the isostatically depressed coastal Lowland and the marine sediments of the 

Presumpscott Formation, depositing a sand, silt, and clay mixture (Thompson and Borns 1985). 

Other land features were created from either direct deposition by the ice or meltwater from the 

ice. Typical glacial features encountered in the project area include glacial till, glaciomarine 

sediments, glaciofluvial deposits, and moraines.

4.1.1.1 Surficial Geology

4.1.1.1.1 Waterway for LNG Marine Traffic

Offshore surficial geology includes recently deposited (Holocene) muds and sands within 

Passamaquoddy Bay that overlie 15 to 82 feet of well-stratified glaciomarine muds from the 

Presumpscott Formation. In some areas, there are layers of sand at the base of this formation. 

Beneath this stratum is an unsorted, unstratified till mixture of fine and coarse rock debris that 

unconformably overlies bedrock and varies considerably in thickness. Additional geotechnical 

investigations of the trestle and berthing dock area would be necessary to support the final design 

of the trestle foundation.

Other than activities associated with construction of the trestle and berthing dock, dredging or 

disturbance is not anticipated in the waterway for LNG marine traffic. No significant impacts on 

surficial geology would be expected along the waterway for LNG marine traffic from the 

increase in LNG traffic.

4.1.1.1.2 LNG Terminal

Along the offshore portion of the LNG terminal, surficial geologic conditions vary with distance 

from shore. Near the shoreline, the uppermost surficial materials are river bottom deposits, 

including sands and silts (1.0 to 13.5 feet thick). With increasing distance from shore, these 

materials transition to shallow marine clays (12 to 24 feet thick). Both the river bottom deposits 

and shallow marine deposits are underlain by marine clay (20 to 60 feet thick) with occasional 

marine sand (2.3 to 4.0 feet thick), which in turn are underlain by glacial till (7.0 to 20.5 feet 

thick) and bedrock.

The surface of the landside portion of the LNG terminal is characterized by a limited thickness 

(0.2 to 2.5 feet) of forest mat/topsoil consisting primarily of silty sand with roots and organic 

matter. Directly below this layer is the marine clay of the Presumpscott Formation, which varies 

in thickness from 2 to 79 feet and overlies a limited area of glacial till (0.3 to 4.9 feet thick). 

Sand and gravel were also encountered beneath the forest mat/topsoil stratum in some portions of 

the site. The material ranges in thickness from approximately 2.0 to 8.7 feet and consists of redbrown, well-graded sand with gravel that appears to be derived from the underlying bedrock.

The primary effect of construction on geology would consist of permanent disturbance to the 

existing topography within the construction footprint of the facility. To the greatest extent 

possible, areas disturbed during construction outside of the facility footprint would be finishgraded and restored as closely as possible to preconstruction contours during cleanup and 

restoration.
4-3 4.1 – Geologic Resources

4.1.1.1.3 Sendout Pipeline

The route of the sendout pipeline passes over a variety of glacially derived deposits. These 

deposits include glacial till, glaciomarine sediments, swamp marsh and bog deposits, and eskers. 

Approximately 17.0 miles (57.0 percent) of the pipeline corridor cross till deposits; 10.1 miles 

(33.9 percent) cross glaciomarine sediments; 2.1 miles (7.0 percent) cross swamp marsh and bog 

deposits; and 0.6 mile (2.0 percent) crosses esker deposits.

The primary effect of construction on surficial geology would consist of disturbances to the 

existing topography along the pipeline construction right-of-way. All areas disturbed during 

pipeline construction would be finish-graded and restored as closely as possible to 

preconstruction contours during cleanup and restoration. 

4.1.1.2 Bedrock Geology

Bedrock in the project area originated as sediments deposited in shallow, subsiding ocean basins 

and solidified into sedimentary rocks such as conglomerate, sandstone, pelite, and carbonate 

rocks. Minor amounts of ash and larger fragments derived from offshore volcanic islands also 

contributed material. These sedimentary rocks were later folded, faulted, and subjected to 

extreme pressure and temperatures during two major episodes of geologic plate movement and 

mountain building to metamorphose into slate, phyllite, schist, gneiss, quartzite, metavolcanic 

and calc-silicate rocks. During the last regional tectonic event, igneous rock such as granite, 

quartz monzonite, and monzodiorite intruded into the surrounding host rock. 

4.1.1.2.1 Waterway for LNG Marine Traffic

Bedrock along and underlying the LNG marine waterway generally consists of Devonian and 

Silurian age intrusive rock from the Eastport and Leighton Formations, respectively. Further to 

the north approaching the terminal site, the channel bedrock becomes a medium hard, fresh to 

moderately weathered sandstone, while adjacent to the terminal site a moderately hard to hard, 

fresh to moderately weathered, red conglomerate is found, similar to the materials found at the 

land-side terminal facilities. 

Bedrock along the waterway for LNG marine traffic would not be affected by construction or 

operation of the proposed project. No significant impacts on bedrock would be expected along 

the waterway for LNG marine traffic from the increase in LNG traffic.

4.1.1.2.2 LNG Terminal

Bedrock in the terminal area generally consists of moderately hard, fresh, coarse-grained 

conglomerate. Based on a preliminary geophysical survey performed by Downeast, bedrock is 

within 5 feet of the surface in some portions of the site. Generally, the upper 1 to 2 feet of 

bedrock is weathered and highly fractured. Downeast estimates approximately 170,000 cubic 

yards of rock would need to be removed to construct the foundations for the LNG storage tanks, 

transfer area spill containment basin, process area spill containment basin, vaporizer area spill 

containment basin, and the trestle abutment structure. Most of these structures are located in the 

central and eastern portions of the terminal site and the nearest area is approximately 500 feet 

from U.S. Route 1. The rock would be removed using a combination of excavating equipment 

and blasting. Rock generated from excavation for the LNG storage tanks and spill containment 
4.1 – Geologic Resources 4-4

basins would be processed to be used as structural fill beneath the proposed buildings, roadways, 

and other ancillary facilities.

Offshore surveys show the depth to the top of bedrock (relative to the ocean bottom) increased 

from west to east and ranged from 31.0 to 77.3 feet (elevation [El.] -52 to El. -133 feet). The top 

of rock was encountered at approximately El. -103 and El. -106 at the proposed locations of the 

northernmost and southernmost mooring dolphins, respectively. At the proposed location of the 

unloading platform, the top of rock is approximately 30 feet deeper (approximately El. -134). 

Blasting would not be required to construct the pier foundation elements, although as stated 

above, some blasting may be required to construct the trestle abutment structure onshore. 

Blasting activities would adhere to all local, state, and federal regulations applying to controlled 

blasting and blast vibration limits in regard to structures and underground utilities, including but 

not limited to Occupational Safety and Health Administration (OSHA) regulations (29 CFR 

§ 1910.109, Explosives and Blasting Agents). Local regulations require that a blasting permit be 

obtained on the municipal level as well as through Maine DEP. An activity-specific blasting 

plan would be prepared prior to any blasting. The construction contractor would follow 

applicable procedures and would be responsible for notifying officials, obtaining appropriate 

blasting permits or permission, and providing any necessary bond or insurance.

4.1.1.2.3 Sendout Pipeline

The proposed sendout pipeline route traverses the following bedrock formations:

• Sandstone and Conglomerate – A medium-grained, clastic sedimentary rock composed of 

abundant rounded or angular fragments of sand size, with or without a fine-grained 

matrix (silt or clay), and more or less firmly united by a cementing material. This is the 

same bedrock underlying the storage terminal and offshore facilities.

• Devonian-Ordovician Flume Ridge Formation – A variable mix of calcareous sandstones, 

siltstones, and slates.

• Devonian Granite – A plutonic rock (a large body of intrusive igneous rock) with quartz 

constituting 10 to 50 percent of the felsic components, and the alkali feldspar/total 

feldspar ratio generally restricted to the range of 65 to 90 percent.

• Devonian gabbro/diorite/ultramafic rocks - quartz diorite – A mixture of intrusive and 

plutonic rocks.

• Cookson Formation – A well-sorted sulfide quartzose sandstone. 

Along the sendout pipeline, the depth to bedrock varies from surface outcrops to greater than 

30 feet below ground surface (bgs). Approximately 8.86 miles (29.7 percent) of shallow bedrock 

are likely to be encountered; these intervals are summarized in table 4.1.1.2.3-1. In addition, 

1.45 miles (4.9 percent) of areas with unknown depth to bedrock are located along the sendout 

pipeline; these intervals are summarized in table 4.1.1.2.3-2. The majority of bedrock underlying 

the proposed pipeline is considered hard; therefore, areas of shallow bedrock would likely 

require blasting or other special construction techniques during pipeline installation.
4-5 4.1 – Geologic Resources

TABLE 4.1.1.2.3-1

Locations of Shallow Bedrock (Less Than 5 Feet Below Ground Surface)

Along the Proposed Downeast Pipeline

Milepost 

From

Milepost 

To

Length 

(miles) Formation / Rock Type

Depth to 

Bedrock 

(inches) a/

0 0.22 0.22 Sandstone and Conglomerate 10

0.29 0.55 0.26 Sandstone and Conglomerate 10

0.68 1.01 0.33 Sandstone and Conglomerate 10

1.31 1.89 0.58 Sandstone and Conglomerate 10 to 38

2.08 2.17 0.09 Sandstone and Conglomerate 10

2.3 3.12 0.82 Sandstone and Conglomerate; Devonian Granite 10 to 15

4.34 4.41 0.07 Devonian Granite 20

4.51 4.62 0.11 Devonian Granite 20

4.7 4.83 0.13 Devonian Granite 20

5.52 5.8 0.28 Devonian Granite 15

5.89 6.61 0.72 Devonian Granite 15 to 38

6.74 6.81 0.07 Devonian Granite 15

6.84 7.65 0.81 Devonian Granite 15

7.71 7.87 0.16 Devonian Granite 15

7.97 8.57 0.6 Devonian Granite; Devonian gabbro/diorite/ultramafic rocks - quartz diorite 15

8.66 9.44 0.78 Devonian gabbro/diorite/ultramafic rocks - quartz diorite 15

9.47 10.14 0.67 Devonian gabbro/diorite/ultramafic rocks - quartz diorite 15

10.14 10.19 0.05 Devonian gabbro/diorite/ultramafic rocks - quartz diorite 15

10.27 10.34 0.07 Devonian gabbro/diorite/ultramafic rocks - quartz diorite 15

10.44 10.46 0.02 Devonian gabbro/diorite/ultramafic rocks - quartz diorite 15

10.62 10.69 0.07 Devonian gabbro/diorite/ultramafic rocks - quartz diorite 15

10.72 10.92 0.2 Devonian gabbro/diorite/ultramafic rocks - quartz diorite 15

12.04 12.14 0.1 Devonian gabbro/diorite/ultramafic rocks - quartz diorite 15

12.36 12.75 0.39 Devonian gabbro/diorite/ultramafic rocks - quartz diorite; Devonian Granite 15

13.03 13.07 0.04 Devonian Granite 15

13.08 13.59 0.51 Devonian Granite 15 to 38

13.63 13.68 0.05 Devonian Granite 38

15.9 15.92 0.02 Devonian Granite 38

15.94 16 0.06 Devonian Granite 38

16.75 16.82 0.07 Devonian Granite 38

17.13 17.23 0.1 Devonian Granite 38

17.53 17.74 0.21 Devonian Granite 38

19.76 19.96 0.2 Cookson Formation – sulfidic quartzose sandstone 15

Total Length 8.86

a/ Depth to bedrock is the distance from the soil surface to the top of a bedrock layer, expressed as a shallowest depth of 

components whose composition in the given soil map unit is equal to or exceeds 15%.

Source: USDA 2006a. 
4.1 – Geologic Resources 4-6

Where consolidated rock (such as sandstone and conglomerate) is encountered during 

construction, Downeast’s preferred procedure would be to fracture and excavate the bedrock 

using standard construction equipment. During any excavation, the trench would be 

approximately 6 to 7 feet deep to provide a minimum of 3 feet of cover for the pipeline. 

However, if crystalline bedrock (such as granite or basalt) is encountered and cannot be easily 

removed by conventional excavation methods, blasting techniques would be utilized in 

compliance with state and federal regulations governing the use of explosives. Only the 

minimum explosive charge necessary to fracture bedrock and keep shot-rock from leaving the 

construction right-of-way would be utilized. The contractor would conduct pre-blasting 

evaluations of the rock, with landowner permission, to develop specific blasting operations and 

monitoring plans to limit stresses on existing pipelines, nearby domestic structures, water supply 

wells, or electrical transmission tower footings that are located near the project area. Peak 

particle acceleration velocities would be recorded to ensure operations are conducted within a 

safe limit.

TABLE 4.1.1.2.3-2

Locations of Unknown Depth to Bedrock Along the Proposed Downeast Pipeline a/

Milepost

From

Milepost

To

Length

(miles) Formation / Rock Type

13.59 13.63 0.04 Devonian Granite

13.68 13.73 0.05 Devonian Granite

14.17 14.23 0.06 Devonian Granite

14.3 14.81 0.51 Devonian Granite

14.98 15.21 0.23 Devonian Granite

15.26 15.55 0.29 Devonian Granite

20.95 21.01 0.06 Cookson Formation – sulfidic quartzose sandstone

22.12 22.16 0.04 Cookson Formation – sulfidic quartzose sandstone

25.42 25.52 0.1 Devonian-Ordovician Flume Ridge Formation

28.65 28.72 0.07 Devonian-Ordovician Flume Ridge Formation

Total Length 1.45

a/ There are some soil types for which depth to bedrock has not been characterized by USDA – NRCS. Along the proposed 

Downeast pipeline, these soils include: Marlow fine sandy loam, Buxton silt loam, pits, sand and gravel, Udorthents-Urban land 

complex, and water. Because depth to bedrock is not known, these soils may potentially overlie shallow bedrock.

Source: USDA 2006a.

Potential impacts from blasting on wells located within 150 feet of the project boundaries include 

decreased yields, decreased water quality (i.e., increased turbidity or odor), interference with 

well operation, or disruption of well function. According to Downeast, there are no public water 

supply wells located within 150 feet of the construction right-of-way in areas of shallow bedrock 

for the terminal and sendout pipeline. Therefore, Downeast does not anticipate any impacts on 

public drinking water wells due to blasting.

The sendout pipeline would cross the wellhead protection area (WPA) for the Baileyville Utility 

District (BUD) between approximately MP 25.4 and MP 25.6, and between approximately 

MP 28.6 and MP 28.7. At the first location, Wells #1 and #2 would be more than 150 feet north 
4-7 4.1 – Geologic Resources

of the pipeline right-of-way. Potential impacts of sendout pipeline construction and operation on 

the WPA are discussed in section 4.3.1.3. Construction and operation of the pipeline is not 

expected to have permanent effects to groundwater flow patterns or aquifers. 

Downeast has stated that it would not be able to identify private water supply wells until 

agreements with landowners to access land for this purpose are granted; therefore, we have 

recommended that Downeast file the location of all private wells and springs within 150 feet of 

construction activities prior to construction (see section 4.3.1.3). If any blasting is required 

within 150 feet of a water well, pre- and post-blasting well testing, with authorization from the 

owner, would be performed to ensure there is no loss of productivity and quality. In the unlikely 

event that such impacts would have occurred, Downeast would implement remedial actions to 

restore the well to its pre-blasting condition.

Disposal of rock and rock debris from trenching and blasting would be in areas approved by the 

individual landowners or land management agency in accordance with Downeast’s Plan, 

Procedures, and Soil Erosion and Sediment Control Guidelines, and regulatory requirements. 

Mixing of excavated rock material with backfill or soil would be minimized and rock would not 

be replaced in an excavation at an elevation higher than the original rock surface. Excess rock 

material would be windrowed along the right-of-way with the permission of the landowner. In 

sensitive areas such as cultivated land, the excess rock would be removed from the area. Should 

Downeast have to dispose of excess rock outside of the right-of-way, an approved landfill or 

alternative upland area would be utilized and the appropriate permits and clearances would be 

obtained. 

4.1.2 Mineral Resources

Mineral extraction activities in the project area generally consist of granite quarries, and sand 

and gravel operations. These operations are described below. 

4.1.2.1 Waterway for LNG Marine Traffic

No mineral resources were found along the waterway for LNG marine traffic; therefore, there 

would be no impacts on mineral resources from the LNG marine traffic.

4.1.2.2 LNG Terminal

There are no granite quarries or sand and gravel pits on the terminal site. No mineral resources 

were identified at or adjacent to the site. The nearest mineral resources are surface sand and 

gravel operations that are approximately 5.5 miles to the west-southwest of the facility.

4.1.2.3 Sendout Pipeline

The sendout pipeline does not traverse any mines, quarries, or gravel pits; however, at MP 23.4 

(Baileyville) and MP 24.4 (Princeton), three former borrow pits were identified in the vicinity of 

the pipeline route. They are located more than 0.5 mile from the proposed pipeline and are 

considered abandoned or in long disuse. The proposed pipeline would not impact these former 

borrow pits.
4.1 – Geologic Resources 4-8

In the event other mineral resources are identified, Downeast would negotiate with the affected 

landowners/operators as part of the right-of-way procurement process to obtain an easement 

agreement that governs excavation activities in the immediate vicinity of the permanent pipeline 

right-of-way and/or establish an adequate buffer zone between active excavation areas and the 

proposed pipeline. Losses or limitations on sand and gravel operations (current or future 

expansion) would be addressed during those easement negotiations. 

4.1.3 Paleontological Resources

Paleontological resources are the fossilized remains of prehistoric plants and animals, as well as 

the impressions left in rock or other materials as indirect evidence of the forms and activities of 

such organisms. A variety of geological processes, including erosion and sedimentation, 

mountain-building, deformation (folding and faulting), metamorphism, and igneous activity, 

have removed a large portion of Maine’s and coastal New Hampshire’s and Massachusetts’ 

fossil record (Marvinney 2006). The bedrock underlying the entire proposed project is 

conglomerate, metamorphic or intrusive in character, and has generally undergone sufficient heat 

and pressure to eliminate any fossils that may have been in the pre-metamorphic ancestral 

sedimentary rock. Therefore, it is not anticipated that paleontological resources would be 

encountered in any area impacted by the project.

4.1.4 Geologic Hazards

Geologic hazards potentially of greatest significance to the project include seismicity and 

faulting, soil liquefaction, slope failures/landslides, and ground subsidence.

4.1.4.1 Seismicity and Faulting

Hazards associated with seismicity include ground shaking, surface rupture of faults, and 

earthquake induced ground failures such as landslides and lateral spreading due to soil 

liquefaction.

Historic earthquake activity in the northeastern United States has primarily been limited to 

events of relatively small magnitude (magnitude less than 5). However, since 1638, at least 

14 earthquakes with magnitudes greater than 5 have been recorded in New England and 

southeast Canada (New Brunswick and Quebec). Prior to 1900, historically recorded 

earthquakes in Maine occurred mainly in the coastal zone in the Eastport and Penobscot Valley 

areas. Most earthquakes occurred to the southeast of the Norumbega Fault System. Modern and 

historical records indicate the areas of higher seismic activity in Maine include the 

Passamaquoddy Bay area of eastern Washington County; Dover-Foxcroft-Milo area of southern 

Piscataquis County; and in southwestern Maine, the Portland-Lewiston Region of Androscoggin 

and Cumberland Counties (Berry 2005).

The most concentrated time period of observed earthquakes occurred between approximately 

1870 and 1900 in the Passamaquoddy Bay area (Smith et al. 1989). The two most significant 

earthquakes that occurred near this time period are the Passamaquoddy Bay earthquake of 1869 

and the Eastport area earthquake of 1904. The Passamaquoddy Bay earthquake has been 

classified as intensity VII earthquake based on the Modified Mercalli Intensity (MMI) scale, and 

the magnitude estimated at 5.7 (Leblanc and Burke 1985). The Eastport area earthquake has 

been classified as an intensity VI earthquake on the MMI scale, and the magnitude has been 
4-9 4.1 – Geologic Resources

estimated at 5.9 (Leblanc and Burke 1985). According to seismic events based on data from the 

Weston Observatory and the Maine Geological Survey (MGS) from 1747 to 1992, there are a 

significant number of recorded earthquakes from Eastport to Calais and surrounding areas 

including Passamaquoddy Bay. With the exception of the earthquakes discussed above, the 

recorded earthquake magnitudes in this region range from less than 2 to 4.9 (Johnston and 

Anderson 1995).

4.1.4.1.1 LNG Terminal and Sendout Pipeline Facilities

The above historic activity indicates there is a low but steady rate of seismic activity in Maine 

where the LNG terminal and sendout pipeline would be located. Possible causes of earthquakes 

in the New England region include focusing of regional stresses at plutons and possible smallscale introduction of magma into plutons at depth (Krinitzsky et al. 1993). Ebel (1989) 

references post-glacial isostatic rebound and reactivation of ancient faults through tectonic plate 

motion as theories for Maine earthquakes. This persistent activity indicates evidence of crustal 

deformation. However, there is no evidence to associate recorded earthquake locations with an 

active fault zone based on known local or regional geologic features (Ebel 1989). 

Several major faults exist in the project region, including the Oak Bay Fault and the Norumbega 

Fault Zone. Review of the physiographic and historical data for the project area indicates no 

evidence for geologically recent movement along these faults. Consequently, the potential for 

seismicity associated with surficial fault displacement does not represent a significant risk to the 

proposed project. It is also significant to note that pipelines using modern arc-welding 

techniques have performed well in seismically active areas of the United States, including 

California (O’Rourke and Palmer 1996). 

Only large, abrupt ground displacements have caused serious impacts on pipeline facilities. Due 

to the very limited potential for large, seismically induced ground movements in the project area 

(Frankel et al. 2002), there is very little risk of earthquake-related impacts on the pipeline 

facilities. The seismic risk and design requirements for the LNG terminal are discussed below.

Geological Hazards, Site-Specific Geotechnical Investigations and Seismic Hazard Analyses

Haley & Aldrich (2007) conducted an initial geotechnical site investigation and probabilistic 

seismic hazard analysis for the proposed LNG terminal site and provided the results in reports 

dated June 2006 as part of the formal Downeast application. A supplemental geotechnical site 

investigation was completed in September 2007 based on Downeast’s subsequent rearrangement 

of the plant layout. The findings and conclusions regarding geological hazards, foundation 

design requirements, and seismic design are summarized below.

Foundation Design

The LNG storage tanks would be constructed on reinforced concrete mat foundations bearing 

directly on bedrock. It would be necessary to excavate up to 14 feet of rock for tank T-201A and 

up to 27 feet of rock for tank T-201B to construct the mat foundations. Borings completed in the 

area of tank T-201A revealed a zone of highly weathered and fractured rock that would require 

further investigation prior to detailed foundation design. Rock excavated for the tank 

foundations would be used to construct the shore-side rock barrier and storm water management 

systems.
4.1 – Geologic Resources 4-10

Downeast LNG’s facilities must be constructed to satisfy the design requirements of 49 CFR 

193, NFPA 59A-2001, 2006 International Building Code, and American Society of Civil 

Engineer (ASCE) 7-05. For seismic design, the facility would also be designed to satisfy the 

requirements of NFPA 59A-2006 and ASCE 7-05. Based on currently available information, the 

site is not likely to be subject to seismic soil liquefaction or lateral spreading, ground failure due 

to sinkholes, or landslides, although additional slope stability and bearing capacity analyses 

would be required in final design. 

Seismic Category I Input Ground Motions

Input Operating Basis Earthquake (OBE) and Safe Shutdown Earthquake (SSE) reference rock 

motions for Seismic Category I structures were determined from probabilistic seismic hazard 

maps developed by the USGS in 2002 for exceedance probabilities of 10 percent and 2 percent in 

50 years, respectively. These reference rock values were then adjusted using one-dimensional 

site response analysis techniques to account for soil amplification at the site. The 2 percent 

probability of exceedance in 50-year spectrum, corrected for the site soil column, is the SSE 

spectrum, but is also referred to as the Maximum Considered Earthquake (MCE) spectrum. The 

5 percent-damped horizontal SSE spectral acceleration values at peak ground acceleration (i.e., 

zero period), 0.2-second period, and 1.0-second period were determined as 0.15 g, 0.38 g and 

0.12 g, respectively. The same values for the OBE spectrum were determined as 0.04 g, 0.08 g 

and 0.02 g. The ground motions for Category I structures have been determined in a manner that 

satisfies the requirements of NFPA 59A-2006. 

Seismic Category II and III Input Ground Motions 

The USGS probabilistic seismic hazard maps at the 2 percent probability of exceedance in 

50 years form the basis of the MCE mapped values found in the 2006 IBC and ASCE 7-05. 

Based on the subsurface information collected to date, the site is underlain by relatively stiff 

overburden soils, generally consisting of up to 10 feet of dense to very dense granular soils 

(sand/gravel) and/or very stiff cohesive soils (silt/clay), which overlies bedrock. Downeast 

would locate all proposed Seismic Category II and III structures at or below current site grades, 

such that the foundation elements of the structures would bear directly on naturally-deposited, 

inorganic soils, and not on organic soils or man-placed, engineered fill. The Seismic Site Class 

has been determined for ancillary structures in accordance with Chapter 20 of ASCE 7-05. 

Based on the available data, Seismic Category II and III structures and components would be 

designed using a Site Class C profile (very dense soil and soft rock). 

The following design values would be used for MCE ground motion parameters: 

• Mapped Spectral Accelerations for Short Periods: SS = 0.319g 

• Mapped Spectral Accelerations for 1-Second Periods: S1 = 0.072g 

• Long-Period Transition Period: TL = 6 seconds 

• MCE Spectral Response Acceleration for Short Periods: SMS = 0.383g 

• MCE Spectral Response Acceleration for 1-Second Periods: SM1 = 0.122g 

Note that “g” refers to acceleration due to gravity.
4-11 4.1 – Geologic Resources

The following design values would be used for Design Earthquake (DE) ground motion 

parameters: 

• DE Spectral Response Acceleration for Short Periods: SDS = 0.255g 

• DE Spectral Response Acceleration for 1-Second Periods: SD1 = 0.081g 

Construction and operation of the project would not materially alter the geologic conditions of 

the project area, and the project would not affect mining of resources during construction or 

operation. Blasting is anticipated during construction of the project, but appropriate precautions 

would be taken to protect dwellings and water supplies. Based on Downeast’s Plan, Procedures, 

and Soil Erosion and Sediment Control Guidelines, and our recommended mitigation measures, 

we conclude that impacts on geological resources would be adequately minimized and would not 

be significant and the project would not be affected by any significant geologic hazards, 

including areas of seismic activity or subsidence.

The design of the facilities is currently at the Front End Engineering Design (FEED) level of 

completion. A feasible design has been proposed, and Downeast would conduct a significant 

amount of detailed design work if the project is authorized by the Commission. Information 

regarding the development of the final design would need to be reviewed by FERC staff in order 

to ensure that the final design addresses the requirements identified in the FEED. Therefore, 

we recommend that:

• Downeast should file the following information, stamped and sealed by the 

professional engineer-of-record, with the Secretary for review and written approval 

by the Director of OEP:

a) structure and foundation design drawings and calculations of the LNG tanks 

and other LNG import terminal facilities; 

b) seismic specifications used in conjunction with the procuring equipment; and

c) quality control procedures that will be used for design and construction.

In addition, Downeast should file, in its Implementation Plan, the schedule for 

producing this information.

4.1.4.2 Soil Liquefaction 

Soil liquefaction from severe ground shaking causes cohesionless soil to lose strength. This 

generally occurs in saturated soils when water completely fills the available pore space between 

soil particles. Soil liquefaction can result in surface settlement where the ground surface is flat 

or in lateral spreading where the ground surface is sloped. 

4.1.4.2.1 Waterway for LNG Marine Traffic

Soil liquefaction along the waterway for LNG marine traffic is considered to be minimal as finegrained, saturated soils prone to liquefaction are generally not found in the high energy water 

environment of the waterway. No significant impacts from soil liquefaction would be expected 

along the waterway for LNG marine traffic.
4.1 – Geologic Resources 4-12

4.1.4.2.2 LNG Terminal

Within the Downeast LNG terminal vicinity, geotechnical borings were made during the seismic 

investigation and soil boring logs reviewed. The overburden consists of stiff to hard clay and 

medium dense to very dense sand with a total thickness varying from 4.0 to 12.8 feet. Based on 

the dense nature of the soils present above the bedrock, grading of soil particles, the measured 

depth to the water table, and location in an area of low seismic risk, soil liquefaction is unlikely. 

Additionally, many of the critical onshore and offshore structures would be supported on 

bedrock.

4.1.4.2.3 Sendout Pipeline

Soils along the sendout pipeline route are similar to those in the LNG terminal area. Based on 

the nature of these soils and the location in an area of low seismic risk, soil liquefaction is 

unlikely. 

4.1.4.3 Subsidence

Ground subsidence is a lowering of the land-surface elevation that results from changes that take 

place underground. Common causes of land subsidence include dissolution of limestone in areas 

of karst terrain; collapse of underground mines; and pumping of water, oil, and gas from 

underground reservoirs. 

4.1.4.3.1 Waterway for LNG Marine Traffic

There is no active underground mining or pumping of oil and gas from underground reserves or 

large groundwater withdrawals from large water supplies along the waterway for LNG marine 

traffic. Consequently, subsidence due to underground mining or resource extraction is not likely 

to occur along the proposed LNG vessel transit route. No significant impacts from subsidence 

would be expected along the waterway for LNG marine traffic. Karst terrain is discussed below.

4.1.4.3.2 LNG Terminal 

There is no active underground mining or pumping of oil and gas from underground reserves or 

large groundwater withdrawals in the LNG terminal area. Consequently, subsidence due to 

underground mining or resource extraction is not likely to occur in the proposed LNG terminal. 

Karst terrain is discussed below. Acceptable settlement criteria for the storage tanks would be 

performed in the design phase based on site-specific geotechnical borings collected at the storage 

tank locations. Currently, the storage tanks are expected to be built on reinforced concrete mat 

foundations bearing directly on competent bedrock.

4.1.4.3.3 Sendout Pipeline

There is no active underground mining or pumping of oil and gas from underground reserves or 

large groundwater withdrawals from large water supplies along the sendout pipeline route. 

Consequently, subsidence due to underground mining or resource extraction is not likely to occur 

along the proposed sendout pipeline. Karst terrain is discussed below. 
4-13 4.1 – Geologic Resources

4.1.4.4 Karst Terrain

Karst terrain develops in areas that are underlain by carbonate rocks and evaporites. Weathering 

and erosion produce a high degree of rock solubility in karst topography. Characteristic 

landforms such as sinkholes and caves are formed from the dissolution of the rock. The potential 

for karst is greatest where surficial deposits are less than 30 feet in thickness and the underlying 

carbonate rocks occur at depths at or just above the water table. In some areas, karst features are 

known to exist at depths as great as 100 feet bgs. No karst terrain has been identified at the 

proposed Downeast LNG terminal site or along the pipeline route. 

Even though the project would not be considered susceptible to karst features and underground 

subsidence impacts, the project facilities would be designed and constructed to meet or exceed 

the federal safety standards set forth in 49 CFR Part 192. This would ensure integrity of the 

project facilities and minimize the potential for any pipe failures due to ground subsidence. 

Additionally, Downeast would conduct regular patrols of the sendout pipeline right-of-way 

during operations to identify conditions, including any areas of ground subsidence that might 

affect the safety or operation of the pipeline. Strict adherence to these standards and procedures 

would minimize the potential for any risk to the project posed by ground subsidence.

4.1.4.5 Landslides

A landslide is the perceptible downward sliding of soil, rock or a mixture of the two (American 

Geological Institute 1976) and can include a wide range of ground movement, such as rock falls, 

deep failure of slopes, and shallow debris flows. Although gravity's action on an over-steepened 

slope is the primary reason for a landslide, there are other contributing factors affecting the 

original slope stability (Wikipedia 2007).

4.1.4.5.1 Waterway for LNG Marine Traffic

Slides, flows, and falls are not anticipated to be of concern along the waterway for LNG marine 

traffic because these phenomena are mainly associated with steep slopes. This area is not 

considered to be susceptible to landslides. No significant impacts from landslides would be 

expected along the waterway for LNG marine traffic.

4.1.4.5.2 LNG Terminal

Slides, flows, and falls are not anticipated to be of concern to the proposed terminal because 

these phenomena are mainly associated with steep slopes. Slopes in the vicinity of the tanks are 

currently envisioned to be constructed no steeper than a 1.5H:1V. Based on the characteristics of 

the subsurface materials relative to landside potential, analysis of the 1.5H:1V slope indicates 

that this angle of repose would be stable. The LNG storage tanks are being designed to sit on 

concrete mats directly overlying competent bedrock and thus, would be stable. Therefore, the 

LNG terminal site is not considered to be susceptible to landslides.

4.1.4.5.3 Sendout Pipeline

Slides, flows, and falls are not anticipated to be of concern to the proposed sendout pipeline 

because these phenomena are mainly associated with steep slopes. The sendout pipeline route is 

not considered to be susceptible to landslides. 
4.1 – Geologic Resources 4-14

4.1.5 Flooding and Storm Surge

4.1.5.1 Waterway for LNG Marine Traffic

No tsunamis have been recorded in the Bay of Fundy or Passamaquoddy Bay (Whitford 2007), 

and the potential for a damaging tsunami to occur along the North Atlantic coast of New England 

is minimal for several reasons. The plate tectonic mechanisms associated with tsunami 

development in the Pacific are not present in the North Atlantic (Lander 1989; Slovinsky 2005). 

The continental shelf located off New England creates shallower waters that would dissipate the 

wave energy in a tsunami (Lander 1989). Moreover, the shallow waters off George’s Bank 

would likely reflect any tsunami-like wave back into the North Atlantic or break up the wave 

(Slovinsky 2005). The West Isles (including Campobello and Deer Island) also provide physical 

obstacles to large waves transiting out of the North Atlantic into the Bay of Fundy.

Flooding is not an issue along the waterway for LNG marine traffic as the area is tidally 

influenced and is by definition underwater. The long-term tidal record for Eastport was digitized 

and analyzed to estimate storm surge levels. The calculated extreme surge levels are only 

slightly higher than the highest astronomical tide levels and are calculated to be 4.04 feet above 

the highest recorded mean high water level. No significant impacts from flooding would be 

expected along the waterway for LNG marine traffic.

4.1.5.2 LNG Terminal

The land-side portion of the terminal area is outside both the 100-year and 500-year flood zones 

(Federal Emergency Management Agency [FEMA] 2006). The trestle abutment and pier 

structures would be located within the 100-year flood zone. The long-term tidal record was 

digitized and analyzed to estimate storm surge levels within the 100-year flood zone. The 

calculated extreme surge levels are only slightly higher than the highest astronomical tide levels 

and are calculated to be 4.04 feet above the highest recorded mean high water level at the site. 

All structures at the site would be built in accordance with applicable state and federal building 

codes to prevent or minimize damage from these flood events at the stated surge levels. 

Several commenters raised the question of long-term sea level rise since the last Ice Age or as a 

consequence of global warming. Depending on the rate of input of carbon dioxide, global 

climate models predict a change in sea level by the year 2100 between 1.6 and 11.5 feet above 

present levels. Most scientists accept the lower to mid-lower range of predicted levels (Kelley et 

al. 2005). The Intergovernmental Panel on Climate Change cites a prediction of 1.6-foot 

increase (Slovinsky and Dickson 2006) and the state of Maine is using a 2-foot increase in sea 

level over the next 100 years for unconsolidated materials in coastal dune projects (Slovinsky 

and Dickson 2006). The bedrock found at the LNG terminal site is more resistant to coastal 

erosion processes and wave action compared to unconsolidated materials found in dune systems. 

The current high water tide level is approximately 10 feet (NAVD 88) and the shoreline along 

the site is a vertical bluff approximately 20 feet above the high water line. All of the storage 

terminal structures would be located above elevation 50 feet. The lowest point of the pier is at 

the shoreline abutment, which is 9.2 feet above mean high water; therefore, the projected 2-foot 

rise would have no impact on any of the LNG terminal structures.
4-15 4.1 – Geologic Resources

4.1.5.3 Sendout Pipeline

Flash flooding is possible at stream crossings along the sendout pipeline. The sendout pipeline 

route would cross over FEMA’s 100-year flood zone in 14 locations and the 500-year flood zone 

in two additional locations (see table 4.1.5.3-1). Executive Order 11988 requires federal 

agencies to avoid to the extent possible the long and short-term adverse impacts associated with 

the occupancy and modification of flood plains and to avoid direct and indirect support of 

floodplain development wherever there is a practicable alternative. Because of its linear nature 

and defined starting and ending points, it is not possible for the Downeast sendout pipeline to 

entirely avoid crossing floodplains. However, because floodplains are associated with 

waterbodies and wetlands, Downeast has generally attempted to avoid crossings, and where 

unavoidable minimize the crossing length of floodplains to the extent possible. Where 

floodplains must be crossed, the pipeline would be installed below the ground surface, and the 

surface of the right-of-way restored and stabilized following construction which would minimize 

environmental impacts and modification of floodplains. The pipeline siting process and 

proposed measures to minimize environmental impacts and modification of floodplains that are 

crossed would meet the intent of Executive Order 11988.

The pipeline crossings of streams and rivers would be designed and protected to mitigate against 

damage due to high velocity flows and potential erosion due to seasonal and flash flooding.

TABLE 4.1.5.3-1

Flood Zone Determinations Along the Sendout Pipeline

Distance 

(mile)

Milepost

From

Milepost

To Community Designation

0.01 6.69 6.70 City of Calais 100-Year Floodplain

0.04 7.63 7.67 City of Calais 100-Year Floodplain

0.02 8.61 8.63 City of Calais 100-Year Floodplain

0.09 13.76 13.85 City of Calais 500-Year Floodplain

1.33 13.85 15.18 City of Calais 100-Year Floodplain

0.07 15.92 15.99 Baring Pit 100-Year Floodplain

0.08 16.04 16.12 Baring Pit 100-Year Floodplain

0.53 16.15 16.69 Baring Pit 100-Year Floodplain

0.17 16.88 17.05 Baring Pit 100-Year Floodplain

0.44 17.75 18.19 Baring Pit/Town of Baileyville 100-Year Floodplain

0.19 18.28 18.47 Town of Baileyville 100-Year Floodplain

0.02 21.30 21.32 Town of Baileyville 100-Year Floodplain

0.14 22.42 22.56 Town of Baileyville 100-Year Floodplain

0.15 23.20 23.36 Town of Baileyville 500-Year Floodplain

0.28 28.33 28.61 Town of Baileyville 100-Year Floodplain

0.12 28.70 28.82 Town of Baileyville 100-Year Floodplain

Source: Maine Office of GIS 1997.
4.2 – Soils and Sediments 4-16

4.2 SOILS AND SEDIMENTS

4.2.1 Soil Composition and Limitations

4.2.1.1 LNG Terminal

The offshore portion of the LNG terminal is primarily underlain by river bottom sands and silts 

close to shore and shallow marine clays farther from shore. The shoreline of the LNG terminal 

site consists of an approximately 20-foot-high “bluff” feature (near-vertical outcropping of 

bedrock). This feature extends from approximately 30 feet above mean sea level (MSL) down to 

about 10 feet above MSL, which corresponds to the estimated mean high water tide level at the 

site. The rocky shoreline at the LNG terminal is generally consistent with the steep, rocky 

shorelines common along the waterway for LNG marine traffic, as well as other portions of Mill 

Cove.

The 80-acre parcel of land on which the Downeast LNG terminal would be located is underlain 

by three primary soil types: Lamoine-Buxton Complex, derived from glaciomarine or 

glaciolacustrine deposits; Creasey-Abram Complex, derived from glacial till deposits; and 

Lamoine-Creasey-Scantic Complex, derived from glaciomarine, glaciolacustrine, or glacial till 

deposits. Construction and operation of the proposed LNG terminal would require about 

47 acres of land, located primarily on the southern portion of this parcel. The soils occurring 

within the footprint of the proposed terminal include only Creasey-Abram Complex and 

Lamoine-Creasey-Scantic Complex. The soil types associated with the storage tanks are 

Lamoine-Creasey-Scantic and Creasey-Abram; both storage tanks are predominately located 

within the Lamoine-Creasey-Scantic Complex. The administration building and its parking lot, 

control building, maintenance building and its parking lot, compressor/blower building, LNG 

vaporizer, and the spill containment basin are all located within the Lamoine-Creasey-Scantic 

Complex. The LNG transfer area, spill containment basin, and the trestle abutment structure are 

all located within the Creasey-Abram Complex. The remaining 33 acres of the 80-acre parcel of 

land, which include areas underlain by the Lamoine-Buxton Complex, would remain 

undisturbed. Table 4.2.1.1-1 provides a summary of soil characteristics and limitations 

associated with the LNG terminal footprint and off-site temporary terminal laydown areas. 

TABLE 4.2.1.1-1

Soil Types and Associated Limitations for the Downeast LNG Terminal and Associated Laydown Yards

Soil Type Acres

Affected

Drainage 

Classification

Farmland of

Statewide 

Importance

Hydric 

Soil

Revegetation 

Potential (Grass / 

Herbaceous)

High 

Compaction 

Potential

High 

Erosion 

Potential

LNG Terminal

Creasey-Abram Complex 19.7 Somewhat 

Excessively 

Drained

No No Fair No Yes

Lamoine-Creasey-Scantic 

Complex

26.9 Excessively 

Drained to 

Poorly Drained

Yes Yes Good Yes No

Laydown Yards

Laydown Yard A

Hermon-Monadnock-Skerry 

Complex

3.2 Somewhat 

Excessively 

Drained

No No Poor/Good No Yes
4-17 4.2 – Soils and Sediments

TABLE 4.2.1.1-1

Soil Types and Associated Limitations for the Downeast LNG Terminal and Associated Laydown Yards

Soil Type Acres

Affected

Drainage 

Classification

Farmland of

Statewide 

Importance

Hydric 

Soil

Revegetation 

Potential (Grass / 

Herbaceous)

High 

Compaction 

Potential

High 

Erosion 

Potential

Laydown Yard B

Lamoine-Creasey-Scantic 

Complex

2.2 Excessively 

Drained to 

Poorly Drained

Yes Yes Good Yes No

Laydown Yard C

Lamoine-Creasey-Scantic 

Complex

3.2 Excessively 

Drained to 

Poorly Drained

Yes Yes Good Yes No

Note: No prime farmland located at the Downeast LNG terminal.

4.2.1.2 Sendout Pipeline

Over 50 soil types would be crossed by the proposed sendout pipeline and associated pipeline 

components, the majority of which are derived from glacial till material with areas of 

glaciomarine, glaciofluvial, and glaciolacustrine material interspersed. The soil types that would 

be affected by the proposed sendout pipeline, the aboveground facilities, and their associated soil 

limitations are listed in Appendix L. 

Soil limitations identified along the proposed sendout pipeline route include shallow bedrock, 

hydric soils, poor revegetation potential (for herbaceous plants and grasses), high compaction 

potential, prime farmland (classified by the USDA NRCS), farmland of statewide importance 

(classified by the USDA NRCS), and high erosion potential. Table 4.2.1.2-1 provides the 

acreages of temporary and permanent impacts associated with each type of pipeline component 

on the various identified soil limitations. These data are also provided as percentages of the total 

area temporarily (258.6 acres) and permanently (141.5 acres) affected by the sendout pipeline 

and components.

Of the various pipeline components, only the one new access road (at MP 15.4), and one MLV 

site (at MP 17.17) are expected to cause permanent disturbances to soil and sediments. Although 

four new access roads would be associated with the sendout pipeline, three of these roads have 

existing road bases on which off-road vehicle access has been established for years. These roads 

overlay soil types that have been disturbed by additions of gravel and the compaction or removal 

of the native soil cover. Consequently, the bases for these roads do not fit into the standard soil 

classification; therefore, the upgrade of the road bases would not affect native soils and 

sediments either temporarily or permanently, except in areas where widening of the road bases 

may occur. The fourth access road, located at MP 15.4, would require clearing and grading for a 

new road base; therefore, it would have both temporary and permanent impacts on soil, including 

compaction.
4.2 

– Soils and Sediments

4-18

TABLE 4.2.1.2-1

Summary of Soil Limitations Along the Proposed Sendout Pipeline and Pipeline Components

Pipeline

Component

Impact

Type

Shallow 

Bedrock 

(< 60" bgs) e/

Hydric

Soil

Very Poor or 

Poor 

Revegetation 

Potential for 

Herbaceous f/

Very Poor or 

Poor 

Revegetation 

Potential for 

Grass g/

High

Compaction

Potential h/

Prime

Farmland

Farmland of 

Statewide 

Importance

High or 

Potentially 

High Erosion 

Potential

Acres of Impact

Pipeline Temporary a/ 67.4 65.88 8.83 148 89.26 7.24 38.89 115.51

Permanent b/ 43.85 39.95 5.24 95.2 54.6 4.38 23.86 75.19

ATWS Temporary a/ 2.93 4.49 0.48 6.74 5.6 0.27 3.47 5.44

Permanent b/ 0 0 0 0 0 0 0 0

ATWS HDD Pad Temporary a/ 1.58 1.41 0.11 3.3 3.59 0.32 3.58 3.95

Permanent b/ 0 0 0 0 0 0 0 0

Laydown Area Temporary a/ 5.04 4.98 0.8 10.39 9.16 0 8.65 9.71

Permanent b/ 0 0 0 0 0 0 0 0

New Access Road i/ Temporary a/ 0 0.07 0 0 0.3 0 0.53 0.23

Permanent b/ 0 0.07 0 0 0.3 0 0.53 0.23

Pipe Storage Area Temporary a/ 0 1.95 0 0 1.95 0 2.95 1.5

Permanent b/ 0 0 0 0 0 0 0 0

Valve Site j/ Temporary a/ 0.3 0 0 0 0 0.3 0 0

Permanent b/ 0.4 0 0 0 0 0.4 0 0

All Components Temporary a/ 77.25 78.78 10.22 168.43 109.86 8.13 58.07 136.34

Permanent b/ 44.25 40.02 5.24 95.2 54.9 4.78 24.39 75.42

Percentage of Total Pipeline Impacts

Pipeline Temporary c/ 26% 25% 3% 57% 35% 3% 15% 45%

Permanent d/ 31% 28% 4% 67% 39% 3% 17% 53%

ATWS Temporary c/ 1% 2% 0% 3% 2% 0% 1% 2%

Permanent d/ 0% 0% 0% 0% 0% 0% 0% 0%

HDD ATWS Temporary c/ 1% 1% 0% 1% 1% 0% 1% 2%

Permanent d/ 0% 0% 0% 0% 0% 0% 0% 0%

Laydown Area Temporary c/ 2% 2% 0% 4% 4% 0% 3% 4%

Permanent d/ 0% 0% 0% 0% 0% 0% 0% 0%
4.2 

– Soils and Sediments

4-19

TABLE 4.2.1.2-1

Summary of Soil Limitations Along the Proposed Sendout Pipeline and Pipeline Components

Pipeline

Component

Impact

Type

Shallow 

Bedrock 

(< 60" bgs) e/

Hydric

Soil

Very Poor or 

Poor 

Revegetation 

Potential for 

Herbaceous f/

Very Poor or 

Poor 

Revegetation 

Potential for 

Grass g/

High

Compaction

Potential h/

Prime

Farmland

Farmland of 

Statewide 

Importance

High or 

Potentially 

High Erosion 

Potential

New Access Road i/ Temporary c/ 0% 0% 0% 0% 0% 0% 0% 0%

Permanent d/ 0% 0% 0% 0% 0% 0% 0% 0%

Pipe Storage Area Temporary c/ 0% 1% 0% 0% 1% 0% 1% 1%

Permanent d/ 0% 0% 0% 0% 0% 0% 0% 0%

Valve Site j/ Temporary c/ 0% 0% 0% 0% 0% 0% 0% 0%

Permanent d/ 0% 0% 0% 0% 0% 0% 0% 0%

All Components Temporary c/ 30% 30% 4% 65% 42% 3% 22% 53%

Permanent d/ 31% 28% 4% 67% 39% 3% 17% 53%

a/ Temporary area includes cleared areas of the construction right-of-way and aboveground facilities that would be cleared during the construction of the project.

b/ Permanent area is a subset of Temporary area, and includes only those areas that will be permanently maintained for project operations.

c/ Temporary impacts percentage based on total temporary impacts of pipeline and pipeline components of 258.6 acres.

d/ Permanent impacts percentage based on total permanent impacts of pipeline and pipeline components of 141.5 acres.

e/ Shallow Bedrock areas do not include areas underlain by soils with unknown depth to bedrock.

f/ Very Poor or Poor Revegetation Potential for Herbaceous areas do not include areas underlain by soils with unknown revegetation potential for herbaceous or soils for which this 

limitation is not applicable.

g/ Very Poor or Poor Revegetation Potential for Grass areas do not include areas underlain by soils with unknown revegetation potential for grass or soils for which this limitation is 

not applicable.

h/ High Compaction Potential areas do not include areas underlain by soils with unknown compaction potential.

i/ Only the access road at MP 15.4 would be a newly created access road. All other access roads overlay disturbed soil types for which off-road vehicle access has been established 

for years. Although upgrade of these road bases may be required, the underlying soil types have been disturbed by additions of gravel and removal of the native soil cover and 

therefore do not fit into the standard soil classification. Upgrade of the road bases would not impact native soils and sediments either temporarily or permanently, except for in areas 

where widening of the road bases may occur.

j/ Only the valve site located at MP 17.17 of the sendout pipeline is accounted for in this table. Neither of the other two valve sites are located along the sendout pipeline: one is 

located within the footprint of the LNG terminal and the other is located within the footprint of the Baileyville Compressor Station. The valve site at MP 17.2 has a total area of 

0.5 acres; however, 0.2 acres of the site overlap the temporary pipeline right-of-way, and 0.1 acres overlap the permanent pipeline right-of-way. Because the impacts of these 

overlapping areas are already accounted for in the right-of-way areas of impact, they are omitted from the valve site impacts.

Source: USDA 2006a.
4.2 – Soils and Sediments 4-20

Of the three MLV sites associated with the project, only one would be located along the sendout 

pipeline (at MP 17.17). A valve station and pig receiving facility would be constructed at the 

site of the Baileyville Compressor Station. The other valve site and pig launching facility would 

be located within the footprint of the LNG terminal. The valve site at MP 17.17 would have a 

total permanent area of 0.5 acre; however, 0.2 acre of the site would overlap the temporary 

pipeline right-of-way, and 0.1 acre would overlap the permanent pipeline right-of-way. Because 

these overlapping areas are already accounted for in the right-of-way impacts, they are omitted 

from the valve site impacts. The valve station and pig receiving facility at MP 29.8 would affect 

0.5 acre during construction and 0.3 acre during operation. The compressor site is a disturbed 

area; consequently, the soils that would underlie the site do not fit into the standard soil 

classification. Therefore, the valve station and pigging facility would not impact any soils that 

are in an undisturbed, native condition. All other pipeline components would be temporary areas 

associated with construction of the project and would not be expected to cause permanent 

disturbances. 

To minimize or avoid adverse effects to soils, Downeast would adhere to the measures contained 

in its Plan and Soil Erosion and Sediment Control Guidelines. In addition, Downeast would 

develop a project-specific Stormwater Pollution Prevention Plan (SWPPP) as required by the 

CWA. This SWPPP would include the protocol for erosion and sediment control procedures for 

the proposed Downeast LNG Project. These procedures would be considered the BMPs that are 

based on Downeast’s Plan, Procedures, and Soil Erosion and Sediment Control Guidelines. We 

believe that Downeast’s use of these plans would meet the intent of the Maine Erosion and 

Sedimentation Control Law. Downeast would also be following the State of Maine’s BMPs for 

erosion and sedimentation control during construction (Maine DEP 2013). These guidelines are 

designed to minimize any impact on agricultural, residential, and wetland soils. Construction 

measures include postponing soil disturbances when soils are excessively wet and separating the 

topsoil layer from the subsoils when grading and trenching. Downeast has adopted the Soil 

Erosion and Sediment Control Guidelines from M&NE, which describe approved seeding 

mixtures to be used in order to reseed the areas affected by the pipeline construction. 

4.2.2 Prime Farmland 

Prime farmland, as defined by the USDA, is “land that has the best combination of physical and 

chemical characteristics for producing food, feed, forage, fiber, and oilseed crops, and is also 

available for these uses (the land could be cropland, pastureland, rangeland, forest land, or other 

land, but not developed land or water). The soils are of the highest quality and can economically 

produce sustained high yields of crops when treated and managed according to acceptable 

farming methods” (USDA 2007a). Soils that do not meet this criteria may be considered prime 

farmland if the limiting factor is mitigated (e.g., using artificial drainage or irrigation). Prime 

farmland soils characteristically have adequate natural moisture content; a specific soil 

temperature range; pH between 4.5 and 8.4 in the rooting zone; low susceptibility to flooding; 

low risk to wind and water erosion; minimum permeability rates; and low rock fragment content 

(USDA 2007a). Prime farmland can include land that possesses the above characteristics but is 

being used currently to produce livestock or timber.
4-21 4.2 – Soils and Sediments

Soils that nearly meet the USDA prime farmland criteria may be designated “farmland of 

statewide importance.” These are defined by the USDA as lands containing “nearly” prime 

farmland as determined by the state agency or agencies and contain similar criteria for 

classification as prime farmland. 

4.2.2.1 LNG Terminal 

The soils at the proposed location of the terminal and the laydown yards are not designated prime 

farmland. However, there are 32.3 acres of soil within the LNG terminal footprint and the 

laydown yards that are designated farmland of statewide importance. This area is not currently 

used for agriculture. Approximately 26.9 acres would be permanently affected by occupation by 

the terminal facilities and the remaining 5.4 acres would be temporarily disturbed during 

construction for the laydown yards. The laydown yards would be a short-term impact mitigated 

in accordance with the Downeast Plan, Procedures, and Soil Erosion and Sediment Control 

Guidelines, and would not affect the potential use of farmland of statewide importance for future 

agricultural purposes. Specific mitigation measures may include topsoil segregation and 

decompaction. We believe the unavoidable conversion of 32.3 acres of farmland of statewide 

importance as a result of operation of the proposed terminal would not be a significant impact.

4.2.2.2 Sendout Pipeline

The sendout pipeline right-of-way would temporarily affect approximately 7.24 acres of prime 

farmland and 38.89 acres of farmland of statewide importance, and would permanently affect 

approximately 4.38 acres of prime farmland and 23.86 acres of farmland of statewide 

importance. Additional temporary disturbances from pipeline construction would include 

approximately 0.27 acre of prime farmland and 3.47 acres of farmland of statewide importance 

for additional temporary workspace (ATWS); 0.32 acre of prime farmland and 3.58 acres of 

farmland of statewide importance for HDD ATWS; 8.65 acres of farmland of statewide 

importance for laydown areas; and 2.95 acres of farmland of statewide importance for pipe 

storage areas. The new access road at MP 15.4 would affect approximately 0.53 acre of 

farmland of statewide importance during construction and operation. The 0.5-acre valve site at 

MP 17.17 would affect approximately 0.3 acre of prime farmland during construction (0.2 acre 

would be affected by the construction right-of-way within the MLV footprint) and approximately 

0.4 acre of prime farmland during operation (0.1 acre would be affected by the permanent rightof-way within the MLV footprint) (USDA 2006a).

The areas of prime farmland and farmland of statewide importance crossed by the sendout 

pipeline and pipeline components are not active agricultural areas. With the exception of the 

access road at MP 15.4 and the valve station at MP 17.17, most impacts would be short-term and 

would not affect the potential use of prime farmland for future agricultural purposes. The 

implementation of the Downeast Plan, Procedures, and Soil Erosion and Sediment Control 

Guidelines would serve to minimize any temporary impacts on prime farmland or farmland of 

statewide importance. Mitigation measures may include topsoil segregation, temporary erosion 

controls such as silt fence, staked hay or straw bales, and sand bags, as necessary, soil 

decompaction, and revegetation. The valve station along with the permanent pipeline right-ofway at MP 17.17 and the access road at MP 15.4 would remove 0.5 acre of prime farmland and 

0.5 acre of farmland of statewide importance, respectively, from future agricultural use. Because 
4.2 – Soils and Sediments 4-22

this land is not actively farmed, we believe that the unavoidable conversion of farmland to 

developed land would not be a significant impact. 

4.2.3 Hydric Soils 

Hydric soils are defined as “soils that formed under conditions of saturation, flooding, or 

ponding long enough during the growing season to develop anaerobic conditions in the upper 

part” (USDA 2006b). These soils are typically associated with wetlands. Soils that are 

artificially drained or protected from flooding (e.g., by levees) are still considered hydric if the 

soil in its undisturbed state would meet the definition of a hydric soil. 

4.2.3.1 LNG Terminal 

Approximately 26.9 acres of hydric soils are found within the footprint of the terminal site and 

5.4 acres are found within the laydown yards. The area of hydric soil within the terminal 

footprint would be permanently affected by occupation by the terminal facilities. During 

construction of the project, loss of soil productivity due to compaction and damage to soil 

structure from heavy equipment are likely to occur. We believe the unavoidable conversion of 

26.9 acres of hydric soils as a result of operation of the proposed terminal would not be a 

significant impact. Effects to hydric soils in the laydown yards would be temporary, and may be 

mitigated using methods such as dry season construction and decompaction during restoration. 

We believe that Downeast’s implementation of these provisions, as well as the use of the 

Downeast Plan, Procedures, and Soil Erosion and Sediment Control Guidelines during 

construction and restoration would minimize impacts on hydric soils.

4.2.3.2 Sendout Pipeline

Approximately 65.88 acres of hydric soils would be located in the temporary pipeline right-ofway, 39.95 acres of which also would be located in the permanent right-of-way. Areas of hydric 

soils affected during construction also would include approximately 4.49 acres of ATWS, 

1.41 acres of HDD ATWS, 4.98 acres of laydown areas, and 1.95 acres of pipe storage areas. 

Approximately 0.07 acre of hydric soils would be affected by construction and operation of the 

new access road at MP 15.4. There would be no temporary or permanent impact on hydric soils 

by the valve site at MP 17.17 (USDA 2006a).

Hydric soils are generally poorly drained and would be expected to have high clay content with 

low permeability. These characteristics make hydric soils susceptible to compaction (as 

discussed below). Soils in residential and agricultural areas would be decompacted during 

restoration; therefore, land use would not be affected by soil compaction. In addition, high 

groundwater levels associated with hydric soils could create a buoyancy hazard for the pipeline. 

Special construction techniques, such as concrete coating and other weighting methods would be 

used to overcome buoyancy hazards during operation of the pipeline. Practices such as dry 

season construction and/or trench dewatering would typically be used. We believe that 

Downeast’s implementation of these provisions, as well as the use of the Downeast Plan, 

Procedures, and Soil Erosion and Sediment Control Guidelines during construction would 

minimize impacts on hydric soils. 
4-23 4.2 – Soils and Sediments

4.2.4 Erosion Potential 

Erosion is a continuing natural process that can be accelerated by human disturbance. Variables 

that may influence erosion potential include soil characteristics, climate, topography, vegetative 

cover, soil texture, surface roughness, percent slope, and length of slope. Water erosion typically 

occurs on loose, exposed soils, with a low permeability, on moderate to steep slopes. Wind 

erosion generally occurs in an arid climate with soils containing little vegetative growth and high 

wind conditions. 

Clearing, grading, and equipment movement over soils could accelerate the erosion process, and 

without adequate soil erosion BMPs, all construction practices could result in the discharge of 

eroded sediment to waterbodies and wetlands. Soil loss due to erosion could also reduce soil 

fertility and impair revegetation rates. 

4.2.4.1 LNG Terminal 

The shoreline at the LNG terminal consists of a steep, rocky bluff that extends down to the 

estimated mean high water tide level. The presence of this feature prevents sand deposition, and 

the only beach environment at the site is intertidal in nature. The terminal shoreline is therefore 

not considered prone to erosion.

Of the approximately 47 acres of land within the proposed terminal footprint, approximately 

19.7 acres of soil are classified as “potentially highly erodible.” Approximately 3.2 acres within 

the laydown yards are classified as “potentially highly erodible” soils. Construction operations 

such as clearing and grading would increase soil erosion potential. Downeast would implement 

their project-specific SWPPP and their Plan and Soil Erosion and Sediment Control Guidelines

to minimize erosion. Mitigation measures to minimize erosion include use of silt fence, slope 

breakers, and stormwater management controls. 

The shoreline at the LNG terminal is primarily comprised of rocky material and is not prone to 

erosion. Erosion of the shoreline at the LNG terminal is not expected to occur from vessel 

docking, as the vessels would be operating at low speeds during docking.

4.2.4.2 Sendout Pipeline

Along the sendout pipeline temporary right-of-way, approximately 115.51 acres of soils would 

have a high or potentially high erosion potential; the permanent right-of-way would have 

approximately 75.19 acres of soils with a high or potentially high erosion potential. Other 

temporary pipeline construction areas underlain by soils with a high or potentially high erosion 

hazard would include 5.44 acres of ATWS, 3.95 acres of HDD ATWS, 9.71 acres of laydown 

areas, and 1.5 acres of pipe storage areas. Construction and operation of the new access road at 

MP 15.4 would impact approximately 0.23 acre of soil with high or potentially high erosion 

potential. The valve site at MP 17.17 would not include any soils with this limitation 

(USDA 2006a).

Because Downeast would implement its Plan and Soil Erosion and Sediment Control Guidelines

for erosion and sedimentation control during construction, the adverse impacts from erosion 

would be minimal. During pipeline construction, Downeast would use erosion control structures 

and erosion control fabrics (as outlined in the Downeast Plan and Soil Erosion and Sediment 
4.2 – Soils and Sediments 4-24

Control Guidelines). The erosion control measures include the installation of slope breakers and 

sediment barriers such as silt fencing and hay bales, the use of mulch and erosion control fabrics, 

and restoration within 20 days of backfilling the trench. We conclude that implementation of 

these measures would minimize overall soil erosion that could result from construction of the 

project. 

4.2.5 Revegetation Potential 

Successful restoration and revegetation in areas that are temporarily disturbed during 

construction are important to maintain ecosystem productivity and to protect underlying soil 

from potential damage, such as erosion. Soils that have a potential for poor (or very poor) 

revegetation were determined by the USDA NRCS. The revegetation potential of each major 

soil type was rated according to its potential for producing domestic perennial grasses and 

herbaceous legumes. Soil properties that affect the growth of grasses and legumes include the 

topsoil thickness for the root zone, texture of the surface layer, available water capacity, wetness, 

surface stoniness, flood hazard, soil temperature, and slope. Examples of grasses and legumes 

are fescue, lovegrass, broomgrass, clover, alfalfa, bluegrass, switchgrass, timothy, and trefoil, all 

of which are typical varieties used for revegetation of disturbed areas. 

4.2.5.1 LNG Terminal 

All of the soils found at the terminal location are considered to have “good” to “fair” 

revegetation potential. The terminal land-based facilities will occupy approximately 47 acres 

during operation; this land will not be available for revegetation during the lifetime of the 

facility. Downeast would implement the requirements in its Plan and Soil Erosion and Sediment 

Control Guidelines for revegetation of disturbed areas outside the footprint of the project 

facilities, which include approximately 8.0 acres of laydown areas. These requirements include:

• fertilize and add soil pH modifiers in accordance with written recommendations obtained 

from the local soil conservation authority;

• prepare a seedbed in disturbed areas to a depth of 3 to 4 inches using appropriate 

equipment to provide a firm seedbed; and

• seed disturbed areas in accordance with written recommendations for seed mixes, rates, 

and dates obtained from the local soil conservation authority or as requested by the 

landowner or land management agency. 

Downeast would revegetate and restore disturbed areas using seed mixtures recommended by the 

NRCS. We conclude that if revegetation is conducted in accordance with these measures, areas 

disturbed by construction would be successfully revegetated. See section 4.4.2 of this EIS for 

further information on revegetation.

4.2.5.2 Sendout Pipeline

The temporary pipeline right-of-way would include approximately 8.83 acres of soils that are 

classified as having very poor or poor revegetation potential for herbaceous plants and 

approximately 148 acres of soils that are classified as having very poor or poor revegetation 

potential for grasses. The permanent pipeline right-of-way would include approximately 

5.24 acres of soils with very poor or poor revegetation potential for herbaceous plants and 
4-25 4.2 – Soils and Sediments

95.2 acres of soils with very poor or poor revegetation potential for grasses. Areas of soils with 

very poor or poor revegetation potential for herbaceous plants affected by temporary pipeline 

components would include approximately 0.48 acre of ATWS, 0.11 acre of HDD ATWS, and 

0.8 acre of laydown areas. Areas of soils with very poor or poor revegetation potential for 

grasses affected by temporary pipeline components would include approximately 6.74 acres of 

ATWS, 3.3 acres of HDD ATWS, and 10.39 acres of laydown areas. No areas with very poor or 

poor revegetation potential for either grasses or herbaceous plants would be located at pipe 

storage areas, the new access road at MP 15.4, or the valve site at MP 17.17 (USDA 2006a).

Downeast would implement the requirements in its Plan, Procedures, and Soil Erosion and 

Sediment Control Guidelines for revegetation of disturbed areas along the proposed sendout 

pipeline route. Downeast’s Plan, Procedures, and Soil Erosion and Sediment Control Guidelines

describe approved seeding mixtures to be used to reseed areas affected by pipeline construction. 

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

Inspections would be conducted after regrading, stabilization, and reseeding; at the beginning 

and latter parts of the first full growing season; and during the following four growing seasons. 

We conclude that if revegetation is conducted in accordance with the mitigation measures 

described in Downeast’s Plan and Soil Erosion and Sediment Control Guidelines, areas disturbed 

by construction along the sendout pipeline would be successfully revegetated. 

4.2.6 Compaction Potential 

Soil compaction modifies the structure and reduces the porosity and moisture-holding capacity of 

the soil. The degree of soil compaction during construction is dependent on moisture content 

and soil texture. Fine-textured soils with poor internal drainage are the most susceptible to 

compaction. Soils within the project areas were rated with high compaction potential values 

based on the following criteria:

• the soil has a surface horizon or soil texture of sandy, clay loam or finer;

• glaciomarine or glaciolacustrine parent materials; and

• drainage classifications of very poorly to somewhat poorly drained.

Construction equipment traveling over wet soils could lead to compaction of the soil structure, 

reduce pore space, increase runoff potential, and cause rutting. Compaction and rutting impacts 

would be more likely to occur when soils are moist or saturated. 

4.2.6.1 LNG Terminal

The Lamoine-Creasey-Scantic soils found at the terminal location are susceptible to compaction. 

This soil, comprising approximately 26.9 acres of the proposed site and 5.4 acres within laydown 

yards B and C, has glaciomarine or glaciolacustrine parent materials and is excessively drained 

to poorly drained. During construction of the project, loss of soil productivity due to compaction 

and damage to soil structure from heavy equipment are likely to occur. Wet periods during 

construction may also increase the potential for soil structural damage and compaction. These 

impacts would be minimal given that the site would be highly developed. Impacts on areas 

within the laydown yards would be minimized using methods such segregating topsoil, 

postponing soil disturbances when soils are excessively wet, and decompaction during 

restoration. These areas would be restored using the seeding and fertilizing requirements of 

Downeast’s Plan, Procedures, and Soil Erosion and Sediment Control Guidelines. 
4.2 – Soils and Sediments 4-26

4.2.6.2 Sendout Pipeline

The temporary right-of-way for the sendout pipeline would include approximately 89.26 acres of 

soils with high compaction potential, and the permanent right-of-way would include 

approximately 54.6 acres of soils with high compaction potential. Temporary construction areas 

underlain by soils with high compaction potential would consist of 5.6 acres of ATWS, 

3.59 acres of HDD ATWS, 9.16 acres of laydown areas, and 1.95 acres of pipe storage areas. 

The new access road at MP 15.4 would include 0.3 acre of high compaction potential soils, all of 

which would be affected during both construction and operation. The new valve site at 

MP 17.17 would not include any soils with high compaction potential (USDA 2006a).

As stated in Downeast’s Plan, Procedures, and Soil Erosion and Sediment Control Guidelines, 

compaction would be mitigated in residential and any agricultural areas crossed by the project. 

Downeast would consult with landowners regarding adequate mitigation and restoration 

measures for decompaction. Mitigation for soil compaction would include segregating topsoil, 

postponing soil disturbances when soils are excessively wet, and using deep tillage operations 

during right-of-way restoration using a paraplow or similar implement. We believe that use of 

these measures during construction would minimize soil compaction resulting from construction 

of the proposed project.

4.2.7 Contaminated Soils

Existing contaminated soils located within or in close proximity to areas proposed for 

construction and operation of the Downeast LNG terminal and pipeline present potential hazards 

to both the environment and human health. A review of existing federal and state databases was 

conducted to identify known hazardous waste sites that could be sources of soil contamination 

near the various project components.

In addition to existing contaminated soils, contamination from spills or leaks of fuels, lubricants, 

and coolant from construction equipment for the Downeast LNG Project could adversely affect 

soils. Downeast has prepared an SPCC Plan template that describes spill prevention techniques, 

spill handling and emergency notification procedures, and training requirements. Construction 

contractors would be required to develop project-specific plans based on Downeast’s template 

prior to construction in order to minimize potential contamination of soil resources from 

accidental spills of hazardous materials. We have reviewed the template and find it adequate.

4.2.7.1 LNG Terminal

EPA and Maine DEP records were searched to identify known contaminated soils within 

0.5 mile of the project. Based on the results of the database query, no sites associated with 

hazardous materials or solid wastes were identified within 0.5 mile of the terminal site. 

In order to minimize potential contamination of soil resources from accidental spills of 

hazardous materials during construction or operation of the LNG terminal, project-specific SPCC 

Plans based on Downeast’s SPCC Plan template would be prepared by construction contractors. 

These plans would provide detailed mitigation measures, including spill prevention techniques, 

spill handling, emergency notification procedures, and training requirements.
4-27 4.2 – Soils and Sediments

4.2.7.2 Sendout Pipeline

Along the sendout pipeline route, 16 records associated with the storage, potential release, or 

disposal of petroleum products or hazardous materials identified 13 sites that are located between 

0.25 and 0.5 mile from the pipeline centerline. An additional 15 records identified 15 sites 

within 0.25 mile of the pipeline centerline (see tables 4.2.7.2-1 and 4.2.7.2-2). There are no sites 

located within the sendout pipeline construction right-of-way. However, C and S Auto Body 

located on U.S. Route 1 in Princeton at MP 26.9 is within 500 feet of the sendout pipeline 

temporary right-of-way. This site is listed in table 4.2.7.2-1 as a Maine DEP Recordable 

Potential Affected Soils Area.

TABLE 4.2.7.2-1

EPA Recordable Potential Affected Soils Areas Within 0.25 and 0.50 Mile

of the Sendout Pipeline Route Centerline

EPA ID EDR Site Name a/ Address Town Approximate 

Milepost

Sites Within 

0.25 to 0.50 

Mile

Sites 

Within 

0.25 Mile

RCRA – Small Quantity Generators

S105404012 Irving Baileyville Big Stop b/ Houlton Road Baileyville 18.1 X

Leaking Underground Storage Tanks

S106792973 Engroff Residence Broadway Baileyville 18.4 X

S105404012 Irving Baileyville Big Stop b/ Houlton Road Baileyville 18.1 X

S104996501 Irving Big Stop Route 1 Baileyville 20.9 X

Registered Underground Storage Tanks

U003100743 U.S. Post Office Route 1 Woodland 18.7 X

S105404012 Irving Baileyville Big Stop b/ Houlton Road Baileyville 18.1 X

U002165581 Dead River Co. Middle Road Baileyville 18.8 X

U003099264 Bohanons Inc. Routes 1 & 9 Baileyville 18.1 X

Leaking Aboveground Storage Tanks

S106073293 Samantha Reynolds Route 1 Baileyville 21.9 X

S105111815 Harold Grant Washington Street Baileyville 18.8 X

S106403855 Tanya Osnoe Houlton Road Baileyville 18.7 X

S105002714 Pat Dow Main Street Baileyville 17.9 X

S105794268 Emma Hodgkins Maple Street Baileyville 18.2 X

ME Spills

S105404012 Irving Baileyville Big Stop b/ Houlton Road Baileyville 18.1 X

a/ Environmental Data Resources, Inc.

b/ All four of these records are assumed to be located at the same site.

Source: EDR 2006.

Downeast would implement a screening program during construction to identify unanticipated 

areas of potentially contaminated soil and groundwater. In the event that impacted soils are 

encountered, Downeast would notify the Maine DEP to assess necessary remedial actions, and to 

implement necessary worker health and safety considerations during construction. 

In order to minimize potential contamination of soil resources from accidental spills of 

hazardous materials during construction of the sendout pipeline, project-specific SPCC Plans 
4.2 – Soils and Sediments 4-28

based on Downeast’s SPCC Plan template would be prepared by construction contractors. These 

plans would provide detailed mitigation measures, including spill prevention techniques, spill 

handling, emergency notification procedures, and training requirements.

TABLE 4.2.7.2-2

Maine DEP Recordable Potential Affected Soils Areas Within 0.25 and 0.50 Mile

of the Sendout Pipeline Route Centerline

EGAD Reference 

Number a/ EGAD Site Name Address Town Approximate Milepost

Sites Within 

0.25 to 0.50 

Mile

Sites Within 

0.25 Mile

28978 Webster Country Store Route 1 & Ridge Road Robbinston 0.6 X

29682 Baring Plt Dump Old Route 1 Baring 17.2 X

27274 Baring Cemetery Assn Cemetery Road Baring 17.3 X

38243 Woodland Irving Mainway 32 Houlton Road Baileyville 17.9 X

28912 Don Scott Route 9 Baileyville 18.0 X

36461 Moores Auto Body Route 1 Baileyville 18.8 X

27272 Baileyville Town Site Off Route 1 Baileyville 20.4 X

32754 Secondary Lagoons Dump Road Baileyville 20.5 X

36462 Exxon Woodland Route 1 Baileyville 20.6 X

30782 Baileyville C&D Site Town Road Baileyville 20.7 X

27271 Baileyville DOT Route 1 Baileyville 20.8 X

36463 VL Tammaro Oil Co Inc. 647 Route 1 Baileyville 21.6 X

27270 Baileyville Dicenzo Site Route 1 Baileyville 20.8 X

36106 Bohanons Exxon Route 1 Woodland 21.9 X

32060 Scottway Oil Mtn. View Drive Baileyville 23.2 X

48501 Monan Pit Route 1 Baileyville 25.7 X

36464 C and S Auto Body Route 1 Princeton 26.9 X

a/ Maine DEP, Bureau of Land and Water Quality, Environmental and Groundwater Analysis Database.

Source: Maine DEP 2006a.

4.2.8 Contaminated Sediments

To determine if contaminated sediments are present in the area of the proposed pier, Downeast 

conducted a sediment sampling and analysis. Subtidal and intertidal sediments were sampled at 

13 locations within the area. The 13 sediment samples (including one duplicate) were collected 

from 12 site locations in and adjacent to Mill Cove. Sediment samples collected were analyzed 

for semivolatile polyaromatic hydrocarbons (PAHs), organics, total metals, and inorganics 

(polychlorinated dibenzo-p-dioxins [PCDDs or dioxins] and polychlorinated dibenzofurans 

[PCDFs or furans]). The chemical analyses of sediment were conducted following the Regional 

Implementation Manual for the Evaluation of Dredged Material Proposed for Disposal in New 

England Waters. 

The analytical results of the sediment analyses were compared to the NOAA Fisheries Screening 

Quick Reference Tables for marine sediment. The comparison standards are established for 

potential effects to biological organisms. Although the laboratory’s detection limits were higher 

than the most conservative screening criteria, several semivolatile organic compounds (SVOCs) 

were detected with concentrations no higher than 150 micrograms per kilogram (μg/kg), or parts 

per billion. 
4-29 4.2 – Soils and Sediments

Metals analyses determined that arsenic and nickel also exceeded the most conservative 

biological screening levels, and cobalt, manganese, and selenium concentrations exceeded 

slightly higher benchmarks. One dioxin and one furan compound were also detected, but 

concentrations were estimated lower than the lower calibration limit. 

Downeast conducted a geotechnical investigation of Passamaquoddy Bay along the proposed 

pier footprint in June and July 2006. Six borings were completed. In the two borings closest to 

shore, samples for chemical analysis were collected. These samples were composites from 

depths of 0 to 7 feet (1 boring), and 0 to 6 feet and 8 to 14 feet (1 boring) below the bay bottom. 

Analyses performed were for polychlorinated biphenyls (PCBs), pesticides, semivolatile PAHs,

and RCRA metals. PCBs, pesticides, and PAHs were not detected in any samples. Maximum 

total metals results were (in μg/kg): arsenic (4.4), cadmium (non-detect), chromium (21), copper 

(8.9), mercury (0.014), nickel (19), lead (8.9), and zinc (35). 

No dredging activity is proposed as part of the terminal construction process. Sediments may be 

disturbed during the installation of the pier pilings and due to propeller wash; however, the 

redistribution would be local and minor. Propeller wash due to normal operation of tugs and 

escort vessels would not be expected to increase turbidity in Passamaquoddy Bay because the 

sediments in this area appear to be cohesive, soft marine clays and because the depth of water at 

the pier along with the timing of LNG vessel and tug arrivals and departures at high tide would 

minimize the disturbance of the sediments. 

Some low-level sediment contamination was identified in the general area of the proposed pier 

construction activities. Downeast is not proposing to perform any dredging, trenching, or 

substrate-disturbing activity other than pile installation. In order to minimize the amount of 

sediment released into the water column, pile installation would be performed using a 

vibrohammer. Near shore, in the area of the proposed pier, this method would likely cause a 

small, localized resuspension of sand and sand/silt when the pile is first set in place; as driving 

continues, little sediment would be expected to be released. Further from shore, the marine clays 

in the area near the end of the pier and at the mooring dolphins are more cohesive and would not 

be expected to be displaced. Therefore, although some low-level sediment contamination was 

identified in the general area of the proposed pier, it is not expected that pile driving with a 

vibrohammer would result in the resuspension of these sediments. Construction vessels may 

create minor amounts of sediment suspension due to propeller wash, but given the tidal 

fluctuations and the deep water in this area, this disturbance would be minor and temporary. In 

addition, the use of over-top construction methods in shallow waters and jack-up barges in 

deeper waters would minimize construction vessel activity that could result in the resuspension 

of sediments. Therefore, because of the use of these construction methods, including pile 

installation by vibrohammer, we have determined that construction and operation of the 

proposed project would not result in any significant impacts on water quality within Mill Cove, 

the St. Croix River, or Passamaquoddy Bay. 

Conclusions

With the implementation of the BMPs associated with Downeast’s Plan, Procedures, Soil 

Erosion and Sediment Control Guidelines, as discussed in more detail above, we believe that 

impact on soils or sediments from construction and operation of the proposed project would be 

minimal.
4.3 – Water Resources 4-30

4.3 WATER RESOURCES

4.3.1 Groundwater

4.3.1.1 Regional Groundwater Quality and Quantity

Aquifers in the area of the proposed LNG terminal site and pipeline route in Washington County, 

Maine consist of a surficial aquifer system and a consolidated bedrock system. The surficial 

aquifer system consists of glacial deposits of sand, gravel, and glacial till that were laid down 

during several advances and retreats of continental glaciers that encroached from the north or 

northwest. The glacial stage between the most recent advance, which took place about 

21,000 years ago, and final retreat, which occurred about 12,000 years ago, is termed 

Wisconsinan. During this stage, ice covered all of the project area. The glacial ice and 

meltwater derived from the ice laid down several characteristic deposits. Till, which consists of 

unsorted and unstratified material ranging in size from clay to boulders, was deposited directly 

from the ice and is present under much of the proposed pipeline route. Meltwater laid down 

outwash, which consists mostly of stratified deposits of sand and gravel; ice-contact deposits, 

which consist primarily of poorly stratified sand and gravel; and near the coast, glacial-marine 

deposits, which consist of mostly clay, silt, and fine sand.

The bedrock aquifers are typically crystalline-rock aquifers that consist of almost insoluble 

igneous and metamorphic rock. These aquifers are characterized by shallow fracture systems 

that store and transmit water. The quantity of water yielded is dependent on the size and quantity 

of fractures; yields can vary from several to hundreds of gpm. Median total dissolved solids 

concentrations in water from these aquifers is low and typically ranges from 110 to 

150 milligrams per liter. Water in crystalline-rock aquifers is similar in quality to water in 

aquifers of the surficial aquifer system. Locally, excessive concentrations of iron, manganese, 

and sulfate are present. Large concentrations of radon, a radioactive gas that is a decay product 

of the uranium minerals present in granite and some metamorphic rocks, have been reported in 

water from the crystalline-rock aquifers in all of the New England states except Vermont. The 

susceptibility of the crystalline-rock aquifers to contamination from the land surface is greatest 

where they are exposed at the land surface. 

The crystalline bedrock aquifer is a confined aquifer composed of a variable complex of igneous 

and metamorphic rock. Well depths typically range between 20 and 800 feet and well yields are 

typically between 2 and 10 gpm in Maine. Elevated levels of iron, manganese, and radon gas are 

present in some areas in Maine. 

EPA-designated sole source aquifers are those that contribute more than 50 percent of the 

drinking water to a specific area and for which there are no reasonably available alternative 

sources of water should the aquifer become contaminated. There are no sole source aquifers in 

the project vicinity (EPA 2008). 

4.3.1.2 LNG Terminal

Groundwater Quality

Downeast assessed the groundwater resources at the proposed LNG terminal site. Several test 

borings were completed, monitoring wells installed, and a deep bedrock well installed as a 
4-31 4.3 – Water Resources

potential drinking water source. Surficial deposits ranged from 5 to 30 feet thick, depth to 

groundwater ranged from 3 to 15.5 feet below the ground surface, and the bedrock at the site is 

reported to be a coarse grained conglomerate. Groundwater samples were collected from two 

monitoring wells and the deep bedrock well. Samples were analyzed using accepted EPA 

methods for volatile organic compounds (VOCs), SVOCs, RCRA 8 metals, herbicides, 

pesticides, PCBs, and the drinking water quality-specific parameters nitrates/nitrites, total 

Kjeldahl nitrogen (TKN), ammonia, sodium, chloride, pH, and conductivity. The chemical 

testing results were compared to Maine Maximum Exposure Guidelines (MEGs) and EPA 

Maximum Contaminant Levels (MCLs), which are used as drinking water standards by the 

Maine Department of Health and Human Services, Division of Environmental Health, Drinking 

Water Program (DWP). Detected concentrations in samples from the two monitoring wells were 

below all MEGs and MCLs. The sample from the deep bedrock well contained sodium and 

antimony at concentrations above the MEG. Future sampling will determine if treatment would 

be required by the Maine DWP as part of their regulating this well as a public drinking water 

supply.

Based on a review of public water supply well information obtained from the Maine Office of 

Geographic Information Services (Maine GIS), Downeast identified no public water supply wells 

or related wellhead protection areas within 150 feet of the proposed construction area of the 

LNG terminal facility (Maine Office of GIS 2006a). Downeast completed searches of federal 

and state databases to identify sites that potentially have groundwater contamination within 

0.5 mile of the proposed LNG terminal facility. No potentially contaminated groundwater sites 

were identified for the LNG terminal facility in any database searched. 

Impacts and Mitigation

Minor amounts of groundwater would be used during construction of the LNG terminal for 

miscellaneous construction purposes (e.g., dust suppression). In addition, some dewatering may 

be necessary during construction at the proposed LNG terminal site, since groundwater was 

found as shallow as 3 feet below the ground surface. However, relatively small volumes would 

be expected and effects to the overall groundwater system would be small and temporary. 

Bedrock was also encountered at depths as shallow as 5 feet in borings conducted at the terminal 

site, and therefore, blasting may be required in some areas. See section 4.1 of this EIS for more 

detailed discussion on blasting at the LNG terminal location. Blasting could cause areas of 

increased turbidity in groundwater near the blast area. These impacts would be expected to be 

short-term and localized in both lateral and vertical extent. No long-term impacts on 

groundwater quality would be expected. In addition, there are no wells in this area that could 

potentially be affected.

During operations, the LNG terminal would require a potable water source with a continuous 

freshwater flow rate of approximately 0.6 to 1.2 gpm, with a maximum daily usage of 

990 gallons. Based upon sampling and analysis of monitoring wells, it appears that an adequate 

and acceptable water supply exists in the bedrock beneath the LNG terminal. A potential water 

supply well that Downeast has installed at the terminal could be an adequate potable water 

source, if permitted by the state, with a stable yield of 7.5 gpm. Groundwater would also be used 

to initially fill the vaporizers prior to SCV system startup. Approximately 20,200 gallons of 

water would be required. Downeast has stated that water from the on-site wells, commercial 

distributors, or a combination of both would provide the initial water volume for startup of the 
4.3 – Water Resources 4-32

SCV units. For major maintenance work requiring the water from an SCV unit to be drained, 

water from the in-service vaporizers would be used to fill empty vaporizer water baths. The 

Downeast LNG terminal would utilize an on-site wastewater disposal system for wastewater 

generated by the employee sanitary facilities. Because there is no public sewer system in the 

proposed terminal area, two subsurface wastewater disposal systems would be required (one 

each for the Administration and Operations buildings). Downeast would construct and operate 

these systems in accordance with the state regulations specific to subsurface wastewater disposal. 

Bathroom facilities associated with the pier control building would be discharged into an 

approved wastewater disposal holding tank whose contents would be disposed of at a stateapproved septic disposal facility. 

The greatest potential for impacts on groundwater would be an accidental release of a hazardous 

substance, such as fuels, lubricants, and coolants, during construction or operation. Spills or 

leaks of hazardous liquids could contaminate groundwater and affect users of the aquifer. This 

type of impact could be avoided or minimized by restricting the location of refueling or storage 

facilities and by requiring immediate cleanup of spills. Downeast’s Plan, Procedures, and Soil 

Erosion and Sediment Control Guidelines include the preparation and implementation of Spill 

Prevention and Response Procedures that meet state and federal requirements. Downeast has 

developed a SPCC Plan template, which it would provide to all construction subcontractors who 

would be required to develop project-specific SPCC Plans that would be implemented during 

construction of the facilities. These SPCC Plans would address potential spills of fuel, 

lubricants, and other hazardous materials and describe spill prevention practices, spill handling 

and emergency notification procedures, and training requirements. They would also describe 

mitigation measures, including containment and cleanup, to minimize potential impacts should a 

spill occur. We have reviewed Downeast’s SPCC Plan template and find it adequate. 

Implementation of Downeast’s proposed measures would minimize the potential for impact on 

groundwater.

4.3.1.3 Sendout Pipeline

Public Water Supply and Wells

The sendout pipeline route crosses designated significant sand and gravel aquifers from MP 13.8 

to MP 14.1, MP 25.4 to MP 25.5, and MP 28.4 to MP 29.0 (see figure 4.3-1). Significant sand 

and gravel aquifers are areas designated and mapped by the MGS as consisting of significant 

sand and gravel deposits that have the potential to supply a properly constructed well with a yield 

of at least 10 gpm. 

Maine GIS data show that one WPA, the Baileyville WPA, would be traversed by the proposed 

sendout pipeline route between approximately MP 25.4 and MP 25.6, and between 

approximately MP 28.6 and MP 28.7 (see figure 4.3-2). The Baileyville WPA is a wellhead 

protection zone associated with two public water supply wells utilized by a community public 

water system in Baileyville (Maine GIS 2006a). The Maine DWP establishes WPAs around 

designated public water supply wells to protect groundwater quality in the vicinity of the well 

from adverse environmental impacts through restrictions of various operations and land uses 

within the designated area. The Maine DWP WPAs range from 300 to 2,500 feet in radius 

depending on the classification of the system and the number of people served.
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P:\Downeast-3253\Team Information\GIS

Figure 4.3-1

Downeast LNG Project

Significant Sand and Gravel Aquifers

in the Vicinity of the Sendout Pipeline Route

Legend

Mile Post

Sendout Pipeline Right-of-Way

Sand & Gravel Aquifer

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Figure 4.3-2

Downeast LNG Project

Public Water Supply Wells and

Wellhead Protection Areas

Legend

Well

Mile Post

Sendout Pipeline Right-of-Way

Water Source Protection Area

0 1 0.5

4-34 
4-35 4.3 – Water Resources

The two wells operated by the BUD are designated Well #1 (Maine Well ID 90100201), the 

southern-most well located closer to the sendout pipeline route, and Well #2 (Maine Well ID 

90100202) located to the northeast of Well #1; however, neither of these wells are within 

150 feet of the proposed sendout pipeline route (see figure 4.3-2). Both Well #1 and Well #2 are 

shallow gravel packed wells installed in sand and gravel deposits that do not extend into the 

underlying bedrock. Well #1 was drilled in 1963 to a depth of 72 feet below ground surface and 

has a yield that varies from 5 to 50 gpm. Well #2 was drilled in 1995 to a depth of 63 feet below 

ground surface and has a yield of 750 gpm (BUD 2006). BUD indicated that Well #1 has been 

used only on occasion as a backup water source since the installation of Well #2.

As shown on figure 4.3-2, the Baileyville WPA also includes a “finger” trending north-northwest 

of the well’s radial protection zone that encompasses an important part of the aquifer. This area 

is hydrologically connected to the radial protection zone and is the area that supplies much of the 

water to the Baileyville wells. 

Downeast has identified 18 private homes within 50 feet of the proposed sendout pipeline 

permanent right-of-way in areas where public water supplies are not available. Downeast states 

that it is coordinating with landowners to collect and record the locations of private water supply 

wells within 150 feet of the limits of construction. With authorization from the well owner, 

Downeast would evaluate individual private wells within 150 feet of the pipeline route and test 

the well’s water quality before and after construction. 

Groundwater Quality

Downeast completed searches of federal and state databases to identify sites that potentially have 

groundwater contamination within 0.5 mile of the proposed sendout pipeline route. Lists of the 

identified sites, locations, and approximate milepost along the proposed pipeline route for each 

database search are shown on tables 4.2.7.2-1 and 4.2.7.2-2. Sources of potential groundwater 

impacts associated with the listed sites include leaking petroleum storage tanks, auto body 

facilities, injection sites, surface spills, a landfill, and salt storage facilities. 

Downeast performed a field survey of the proposed pipeline route to observe the identified sites 

and assess the potential of encountering contaminated conditions during construction of the 

proposed pipeline. With the exception of the Irving Big Stop at MP 18.1, the Baileyville Town 

Site at MP 20.4, and the Secondary Lagoons Site at MP 20.5, the identified potential 

contaminated areas appear to be at locations that would be considered hydraulically 

downgradient from the pipeline route and/or at distances that would not likely impact subsurface 

conditions beneath the pipeline alignment. Although the Irving Big Stop appears upgradient of 

the pipeline route, no evidence of potential impacts, including stressed vegetation, were observed 

in an adjacent wetland area between the pipeline route and the Irving facility and no groundwater 

remediation systems were observed in the vicinity of the Irving Big Stop.

The Baileyville Town Site includes the Baileyville landfill facility and related secondary leachate 

lagoons that are upgradient of the pipeline route. Based on topographic and geologic conditions 

in this area, pipeline construction activities may not encounter groundwater and potential 

remedial actions associated with impacted groundwater and sediments would not be required. 

Downeast would perform subsurface explorations within the pipeline right-of-way in the vicinity 

of both the Irving Big Stop and the Baileyville Town Site to assess potential contamination that 

may be encountered during pipeline construction activities in these areas. Downeast would 
4.3 – Water Resources 4-36

contact Maine DEP and landowners to determine whether impacted soils or groundwater may be 

present in the area of construction since it is possible that contaminated soils or groundwater 

could be encountered. In the event that unanticipated areas of contamination are encountered, 

Downeast would, in consultation with Maine DEP, implement the appropriate remedial actions. 

State and local officials have expressed concern about a contaminated site that was not identified 

by Downeast because of its location outside the 0.5 mile zone. The BUD and the Maine Center 

for Disease Control and Prevention have expressed concern over the potential relationship of the 

proposed pipeline between MP 25.4 and MP 25.5 and an abandoned special waste landfill 

located approximately 0.75 mile south of the proposed alignment. A significant sand and gravel 

aquifer is present in this area. This landfill is hydraulically downgradient of the proposed 

alignment. The specific concern expressed is that the proposed HDD here could alter 

groundwater flow patterns and potentially cause contaminated groundwater associated with the 

landfill to migrate north towards the Baileyville WPA. Although the installation of the pipeline 

would affect groundwater flow in the immediate area around the pipeline (in areas beneath the 

water table, the flow would be diverted around the pipeline), the overall groundwater flow 

direction in the area would not be affected. Thus, because of the groundwater flow direction in 

this area, and the distance between the abandoned landfill and the proposed pipeline, we believe 

that the installation and presence of the pipeline in this area would not cause a threat to the WPA.

Impacts and Mitigation

In general, construction and operation of the proposed pipeline would have little or no adverse 

effects to groundwater resources. Blasting could potentially occur in areas of shallow bedrock 

along the proposed sendout pipeline route (see section 4.1 for details regarding blasting). Prior 

to the start of blasting work, Downeast would perform a pre-blast conditions survey of all 

existing structures and conditions in the vicinity, including all water supply wells within 150 feet 

of a blasting area. The pre-blast surveys would include locating the well, documenting the 

current condition of the well, determining the well yield, and performing analytical testing of the 

drinking water. Downeast states that before completion of the pre-blast surveys, it would 

develop a specific procedure for recording, processing, and responding to well damage claims 

that arise during construction. Downeast would conduct a follow-up round of testing, including 

well yield and analytical testing, for wells for which claims are filed. The results of the followup tests would be compared with the pre-blast test results to help assess potential damage to the 

well. We agree with this general approach, but would require follow-up testing regardless of 

whether a claim were filed, because impacts on yield and water quality may not be immediately 

discernible to the well owner. Because Downeast has not completed surveying the entire

pipeline route for private wells, we recommend that:

• Prior to construction of the pipeline facilities, Downeast should file with the 

Secretary the location by milepost of all private wells and springs within 150 feet of 

construction activities. Downeast should conduct, with the well owner's permission, 

pre- and post-construction monitoring of well yield and water quality for these 

wells. In the event a water well or system is damaged as a result of construction, 

Downeast should arrange for a temporary source of potable water, if required, and 

provide for the repair of the well or replacement of the water supply. 
4-37 4.3 – Water Resources

In addition, we believe that Downeast should be responsible for any water system that it damages 

and cannot repair to pre-construction yield or quality. Therefore, we recommend that:

• Within 30 days of placing the pipeline facilities in service, Downeast should file a 

report with the Secretary discussing whether any complaints were received 

concerning well yield or water quality of the private wells and springs within 150 

feet of construction activities and how each complaint was resolved.

If shallow groundwater is encountered during excavations along the pipeline route, it may be 

necessary to dewater during construction. Trench dewatering operations would be brief, 

typically lasting several days or less. Potential impacts on the groundwater would include minor 

fluctuations in groundwater levels and/or increased turbidity within the aquifer adjacent to the 

activity. Because of the relatively small amount of water removed, the short duration of the 

activity, and the local discharge of the water, groundwater levels would quickly recover after 

pumping stops. Downeast would follow its Plan, Procedures, and Soil Erosion and Sediment 

Control Guidelines that provide guidance on the location of dewatering structures so that there 

would be no deposition of sediments into wetlands and waterbodies, and no impacts on cultural 

resources or habitat for sensitive species. We believe that effects of dewatering on groundwater 

would be localized, temporary, and insignificant.

During pipeline construction activities, it is possible that HDD boreholes could penetrate local 

shallow aquifers. However, these activities are not expected to impact groundwater conditions 

other than in the immediate vicinity of the borehole, where bentonite drilling mud could result in 

localized alteration of aquifer hydraulic properties. Temporary dewatering activities that may 

occur on the St. Croix River HDD would be localized, passive dewatering to keep any entry/exit 

HDD trench and work area dry for worker safety during construction, should it be necessary. 

Where the pipeline would be installed below the groundwater table, the groundwater levels 

would stabilize back to equilibrium conditions around the pipeline immediately upon completion 

of construction activities. The construction and operation of the pipeline is not expected to 

have permanent effects to groundwater flow patterns or aquifers. Additionally, we have 

recommended that wells within 150 feet of construction areas be monitored to evaluate water 

quality, which would detect any localized changes that might occur in response to the HDD 

activities. 

The greatest potential for impacts on groundwater would be an accidental release of a hazardous 

substance, such as fuels, lubricants, and coolants, during construction or operation. Spills or 

leaks of hazardous liquids could contaminate groundwater and affect users of the aquifer. This 

type of impact could be avoided or minimized by restricting the location of refueling or storage 

facilities and by requiring immediate cleanup of spills. Downeast’s Plan, Procedures, and Soil 

Erosion and Sediment Control Guidelines include the preparation and implementation of Spill 

Prevention and Response Procedures that meet state and federal requirements. Downeast has 

developed a SPCC Plan template, which it would provide to all construction subcontractors who 

would be required to develop project-specific SPCC Plans that would be implemented during 

construction of the facilities. These SPCC Plans would address potential spills of fuel, 

lubricants, and other hazardous materials and describe spill prevention practices, spill handling 

and emergency notification procedures, and training requirements. They would also describe 

mitigation measures, including containment and cleanup, to minimize potential impacts should a 

spill occur. We have reviewed Downeast’s SPCC Plan template and find it adequate. 
4.3 – Water Resources 4-38

Downeast has made a commitment to take special care in maintaining good housekeeping and 

spill prevention and control practices during pipeline installation and maintenance in areas 

overlying the significant sand and gravel aquifers from MP 13.8 to MP 14.0, MP 25.4 to MP 

25.5, and MP 28.4 to MP 29.0, and particularly for the proposed crossing of the Baileyville WPA 

between MP 25.4 and 25.6, and between MP 28.6 and MP 28.7. Based on these assurances, in a 

letter dated August 8, 2008 to Gardner Rolfe of the BUD, Andrew L. Tolman, Assistant Director 

of the Maine CDC Drinking Water Program, indicated that the “current pipeline alignment does 

not appear to pose a significant threat to the public water supply.” 

4.3.2 Surface Water 

4.3.2.1 LNG Terminal

Offshore Construction

The proposed LNG terminal pier would be located in Mill Cove slightly south of the confluence 

of Passamaquoddy Bay and St. Croix River. The outlet of Passamaquoddy Bay exchanges water 

with the Bay of Fundy (see figure 4.3-3). This general area is known for its extreme tidal range 

and swift currents. These conditions cause the coastal waters of the area to be very well mixed,

thereby allowing any minor changes in water temperature or sediment load to be quickly 

dispersed.

The waters of Passamaquoddy Bay and the St. Croix River/Mill Cove are classified by the state 

of Maine as SB. A Class SB designation in the state of Maine is the second highest water 

classification in terms of overall water quality. Class SB waters must be of such quality that they 

are suitable for the designated uses of recreation in and on the water, fishing, aquaculture, 

propagation and harvesting of shellfish, industrial process and cooling water supply, 

hydroelectric power generation, navigation, and as habitat for fish and other estuarine and marine 

life. The habitat under this classification is characterized as unimpaired.

Construction of the Downeast LNG terminal pier could adversely affect surface water quality in 

Mill Cove, the St. Croix River, and Passamaquoddy Bay during the construction period. The 

primary impacts on these surface waters from construction of the project would be from turbidity 

increases around pier support pilings during pier construction, stormwater runoff, and accidental 

spills or leaks of hazardous materials. No in-water dredging is proposed.

Construction of the pier would likely result in minor increases in suspended solids in the water 

column in the vicinity of pile-driving activities. However, based on our previous consultations 

with resource agencies and information obtained from other pile-driving projects (Balloch 2007),

we believe that pile driving does not typically result in the release of a substantial amount of 

sediment into the water column. In addition, for the types of sediments found in the area of the 

proposed pier near the shore (sand and sand/silt), a small, localized release would occur when the 

pile is first set in place, but as driving continues, little sediment would be expected to be 

released. The marine clays found farther offshore in the area near the end of the pier and at 

the mooring dolphins would also not be expected to be displaced as they are cohesive. 
Figure 4.3-3 

Downeast LNG Project

Passamaquoddy Bay and Fundy Isles

4-39
4.3 – Water Resources 4-40

Although some low-level sediment contamination was identified in the general area of the 

proposed pier, it is not expected that pile driving would result in the resuspension of these 

sediments, and therefore, would not result in any significant impacts on water quality within Mill 

Cove, the St. Croix River, or Passamaquoddy Bay. Section 4.2.8 of this EIS discusses the results 

of sediment sampling and geotechnical investigation in the area of the proposed pier. 

During rock socket drilling activities, drill cuttings would also be produced and released into the 

water column; however, it is unlikely that these heavy coarse drill cuttings would become 

suspended and contribute measurably to the levels of total suspended solids. Additionally, the 

currents and substantial water turnover near the project area from the extreme tides would aid in 

dispersing any suspended materials. 

Marine construction vessels operating near the shoreline could also result in the suspension of 

some sediments via propeller wash. However, these impacts would be limited to the 

construction time frame and therefore would be temporary. In addition, the use of over-top 

construction methods in shallow waters and jack-up barges in deeper waters would minimize 

construction vessel activity that could result in the resuspension of sediments. In deeper waters 

where support vessels would be required for construction, the under keel depth would average 

25 feet.

Vessels working to construct the offshore portions of the LNG terminal require the use of fuel 

and other lubricants to support vessel and equipment operation; as a result, there is potential for 

the inadvertent release of fuel to the waters of Mill Cove and Passamaquoddy Bay. To prevent 

and/or minimize impacts associated with accidental spills or releases during construction, all 

contractors are required to comply with state and federal (Coast Guard) regulations related to 

fuel handling and spills in offshore areas. In accordance with 33 CFR Part 151.29, each oil 

tanker of 150 gross tons and above and each other ship of 400 gross tons and above, operated 

under the authority of a country other than the U.S. that is party to MARPOL 73/78, shall, while 

in navigable waters of the U.S. or while at a port or other terminal under the jurisdiction of the 

U.S., carry on board a shipboard oil pollution emergency plan (SOPEP) approved by its flag 

state. This plan shall meet the requirements set forth in 33 CFR Part 151.26 and 33 CFR Part 

156.20. Additionally, the Maine DEP requires that it be notified in the event of any discharge of 

oil in or next to waters of the state. 

For smaller vessels that are not required to have an SOPEP, the volumes of fuel potentially 

involved are expected to be on the order of tens of gallons. Implementation of standard spill 

response techniques for spills of this size should minimize adverse impacts on the water quality 

of Mill Cove and Passamaquoddy Bay. Such impacts would be expected to be short-term in 

nature, as quantities of spilled fuel not able to be collected would likely be minor and would be 

dispersed and diluted by wind and wave action. However, because there are no procedures 

specified for spills from smaller vessels that could occur in the waters of Mill Cove and 

Passamaquoddy Bay during construction of the marine terminal, we recommend that:

• Prior to construction of the LNG terminal facilities, Downeast develop a Marine 

SPCC Plan to include procedures that would be implemented should spills of oil, 

gas, lubricants, or other hazardous materials occur during construction and 

operation of the marine terminal. In addition to addressing emergency spill 

response and cleanup procedures, this plan should include a description of general 
4-41 4.3 – Water Resources

spill prevention measures such as material handling practices, personnel training, 

and inspection. Downeast shall file the Marine SPCC Plan with the Secretary for 

review and written approval by the Director of OEP. 

Onshore Construction

The proposed onshore portion of the Downeast LNG terminal is located along the southern 

shores of Mill Cove within the Robbinston watershed. The only mapped surface waterbody at

the proposed Downeast LNG terminal site is a small Maine DEP jurisdictional stream that flows 

from a culvert under U.S. Route 1 to the northeast, where it discharges into Mill Cove. 

Downeast states that the stream is approximately 5 to 7 feet wide with well-defined banks. Also 

present near the southeastern boundary of the proposed terminal site is a swale draining a 

wetland that discharges to Passamaquoddy Bay.

During site preparation and construction at the LNG terminal site, disturbed soils would be 

exposed to erosion. To minimize erosion impacts on surface waters, Downeast would comply 

with the Maine Stormwater Management Law’s requirement for preparing a Construction 

General Permit for stormwater discharges during construction. In addition, the Maine Erosion 

and Sedimentation Control Law requires preparation and implementation of an Erosion and 

Sedimentation Control Plan. We believe that Downeast’s use of its Plan, Procedures, and Soil 

Erosion and Sediment Control Guidelines during onshore construction would meet the intent of

the Maine Erosion and Sedimentation Control Law and would minimize impacts from erosion on 

surface waters during construction.

In the event of an accidental spill of oil, gas, lubricants, or other hazardous materials during 

construction or operation, Downeast would follow the measures outlined in the project-specific 

SPCC Plans to be prepared by each subcontractor. 

Prior to being placed into service, the proposed LNG storage tanks and sendout pipeline would 

be hydrostatically tested to ensure structural integrity. However, because of the length of time 

required to construct the LNG storage tank, Downeast anticipates that its hydrostatic testing 

would not occur until over three years after this EIS is published. Hydrostatic testing procedures 

for the LNG storage tanks are discussed below; procedures for testing the pipeline are discussed 

in section 4.3.2.2.

Once construction is completed, the LNG storage tanks would be hydrostatically tested, in 

accordance with API Standard 620, Appendix Q.8 (see section 2.3.1.3). 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 also be used to test the second tank. 

Downeast states that although a combination of sources may be used (water from the on-site 

deep well, water trucked in from a municipal or industrial supply, or Passamaquoddy Bay water), 

the principle source of test water would likely be from Passamaquoddy Bay. The use of 

saltwater would have no effect to the tank or tank components that would come into contact with 

the saltwater. However, because the same water would be used to test both tanks, water may 

need to be retained in the first tank for approximately one month, although the duration will be 

kept to a minimum. As a result, chemicals and/or biocides may need to be added to the water in 

the storage tank for corrosion control and to inhibit biological growth. The contents of the tank 

would be tested to determine whether or not treatment would be required and to determine the 
4.3 – Water Resources 4-42

amount and type of chemical and/or biocide that would need to be added. Once transferred to 

the second tank, the water would be held for at least 48 hours for inspection. 

After testing, the tanks would be cleaned with fresh water and dried. Pumps in the tank would 

control the discharge rate of the test water. Test water would be discharged into Passamaquoddy 

Bay using a pipeline fitted with an aeration type energy dissipater to allow the test water to be 

sprayed into Passamaquoddy Bay to prevent potential erosion and scouring of the bottom 

sediments. The state of Maine has assumed the NPDES program from the federal government, 

and issues its permits through the Maine DEP. Hydrostatic test waters that would be discharged 

into waters of the state would require a permit under the Maine PDES, as regulated by the CWA. 

The discharge rate would be in compliance with that established in the hydrostatic test water 

Maine PDES permit. Prior to discharge, all test water would be analyzed for chemical 

composition as determined in the Maine PDES permit. If no chemicals or biocides are used in 

the hydrostatic test water, Maine DEP has indicated that a total suspended solids analysis would 

be the only analysis required. 

Operation

As proposed, the pier would have more than adequate water depth for the LNG vessels and as 

this is currently not a depositional area, it appears that maintenance dredging would not be 

necessary. Thus no impacts from dredging would be expected. Propeller wash from tugs and/or 

LNG vessels equipped with thrusters would not be expected to increase turbidity in 

Passamaquoddy Bay because the sediments in this area appear to be cohesive, soft marine clays

(see section 4.5.2.2). In addition, the shoreline adjacent to the pier would include erosion 

protection (e.g., articulated concrete blocks) placed on slopes to stabilize the shoreline and 

prevent erosion from wave action and propeller wash from the LNG vessels. 

Prior to operating the LNG terminal, Downeast would need to apply for a Multisector General 

Permit concerning management of stormwater from the LNG terminal facilities. As part of this 

requirement, a SWPPP would also be prepared to comply with Maine DEP and EPA 

requirements concerning stormwater runoff due to the impervious surfaces at the LNG facility. 

The state of Maine has assumed the NPDES program from the federal government, therefore 

stormwater discharges would be regulated by the Maine DEP PDES program. Stormwater 

discharges would be directed to the Maine PDES permitted discharge points. This plan would 

also list prevention and response procedures in the event of an accidental spill of oil, gas, 

lubricants, or other hazardous materials. 

Downeast would design its LNG terminal to account for an accidental spill of LNG during 

operation of the facility, and prevent the LNG from entering Passamaquoddy Bay. The LNG 

facilities would include safety and hazard detection systems, LNG containment and process 

sumps, and associated LNG spill collection system. 

The SCV technology that would be used to process the LNG produces excess water at a rate of 

85 gpm when the LNG terminal is operating at normal sendout capacity, and up to 109 gpm 

during peak capacity. This equates to a 24-hour discharge of between 122,400 and 

156,960 gallons. During the vaporization process, this excess water would be acidic, but would 

not be contaminated with any foreign substances. Downeast would be required to neutralize the 

excess water by adding sodium hydroxide to the SCV water bath prior to its final discharge. 
4-43 4.3 – Water Resources

Downeast proposes to use recovered SCV water to supply its firewater system and sell surplus 

SCV water (not used on-site) to an independent party yet to be identified for off-site use. 

Downeast states that it is in discussions with several such parties and is confident that a buyer for 

this water would be contracted. Therefore, we recommend that:

• Prior to construction of the LNG terminal facilities, Downeast should file with the 

Secretary a final plan for the discharge of the excess SCV water, for the review and 

written approval of the Director of OEP. The discharge plan should include 

discharge location, rate and frequency of discharge, copies of applicable permit 

applications, and all measures to be used to mitigate environmental impacts at the 

discharge location. 

As with other large tank ships, LNG vessels would take on some ballast water to maintain vessel 

trim and stability, and keep the vessel’s hull within acceptable stress levels as they offload their 

cargo and depart the LNG terminal. The amount of ballast water required by each LNG vessel 

would vary according to its size and the weather conditions. Downeast states that, although the 

LNG terminal berth and offloading facility would have the potential to handle future vessels of 

220,000 m3, the largest vessel that would be accommodated at the import facility would be a 

165,000 m3 LNG vessel. Such a vessel would require about 17.11 million gallons of water, 

which would be obtained in Passamaquoddy Bay and transported out of the waterway. This 

quantity is estimated to be about 0.0003 percent of the quantity of water that flows in and out of 

Passamaquoddy Bay during one tidal cycle. This would constitute a minor impact on water 

resources of Passamaquoddy Bay. Impacts on ichthyoplankton and zooplankton species from 

LNG vessel water withdrawals are discussed in detail in section 4.5.2.2 of this EIS.

Although ballast water intake by the LNG vessel would occur during offloading of the LNG, no 

release of ballast water would occur within the navigable waters of the United States. Any 

limited discharge of ballast water that should occur would be conducted in accordance with the 

Coast Guard’s mandatory ballast water management program (33 CFR 151).

The presence of the pier support structures underwater would alter the local hydrodynamic 

regime of Passamaquoddy Bay to a minor degree. In the areas immediately surrounding the 

support structures, current patterns would be affected, an increase in localized turbulence in the 

water column would occur, and bottom sediment scouring or deposition patterns immediately 

adjacent to the structures could change. We do not believe that these changes would cause any 

noticeable negative impact on the water resources of Passamaquoddy Bay.

Other potential impacts on water resources involve the uptake of water from Passamaquoddy 

Bay for emergency firewater pumps. The primary source of water for the firewater system 

would be water recovered from SCVs. However, backup firewater would be provided from 

emergency firewater pumps that would be installed on the pier and would use water from 

Passamaquoddy Bay. The backup firewater system would also be used at any time that an LNG 

storage tank deluge system is in operation. These pumps would draw water from 

Passamaquoddy Bay and would be capable of supplying water directly to the pier, to the LNG 

storage tank deluge, and to the firewater storage tank to provide emergency makeup for the 

firewater system. One of each of the seven emergency firewater pumps would be tested for one 

hour once a week at a rate of 3,000 gpm for a total of 180,000 gallons/week. This water would 

be sprayed back into Passamaquoddy Bay; this activity would constitute a negligible impact on 
4.3 – Water Resources 4-44

water resources of Passamaquoddy Bay. Impacts on ichthyoplankton and zooplankton species 

from LNG vessel water withdrawals are discussed in detail in section 4.5.2.2.

LNG vessels would also require water withdrawals and discharges while at the port for vessel

operations. The majority of this water would consist of engine cooling water that is recirculated 

or cycled through a heat exchanger before being discharged back to Passamaquoddy Bay. 

Downeast has provided information indicating that a 165,000 m3 LNG vessel would require a 

maximum of about 55.5 million gallons of water over a 21-hour period to support engine cooling 

while at the pier (a maximum average rate of 540 gallons per second). The temperature of this 

water at the point of discharge would be elevated by 5 to 10°F in comparison to the receiving 

waters of Passamaquoddy Bay. However, Cornell Mixing Zone Expert System (CORMIX)

modeling conducted by Downeast indicates that the discharge plume associated with engine 

cooling would be relatively minor, with the change in temperature reduced to approximately 

1°C, or less, warmer than ambient conditions within 15 to 30 meters of the point of discharge, at

ambient current speeds of 0.5 m/s and 0.05 m/s, respectively (see Appendix O). Due to the 

comparatively small volume of this water in relation to the flow of Passamaquoddy Bay 

(estimated to be about 0.001 percent of the quantity of water that flows in and out of 

Passamaquoddy Bay during one tidal cycle), and the swift currents that would cause rapid 

mixing, we believe that there would be no discernable impact on the water quality of 

Passamaquoddy Bay from cooling water discharge activities.

Another use of Passamaquoddy Bay water could be reverse osmosis (RO) desalination that 

would produce fresh water for hoteling. The RO process waste product is concentrated brine that 

would be discharged to Passamaquoddy Bay. Given the results of the CORMIX modeling and 

the flow rate of Passamaquoddy Bay, we expect that the brine would mix rapidly with 

Passamaquoddy Bay waters with no discernible impact on the water quality of Passamaquoddy 

Bay.

4.3.2.2 Sendout Pipeline

The proposed sendout pipeline would cross 22 surface waterbodies. Of these, 14 would be 

minor crossings (less than 10 feet in width), 6 intermediate (between 10 and 100 feet wide), and 

2 major (greater than 100 feet wide). The pipeline right-of-way occurs within the Coastal 

Washington and Hancock drainage area and the St. Croix River drainage area. Streams in these 

areas vary in substrate type, substrate particle size, channel width, flow regime, and depth. 

Depths are generally less than 10 feet and stream bottoms are a combination of woody debris and 

rocks generally no larger than 12 inches in diameter. Canopy closures over the streams ranged 

from zero to 100 percent, and Downeast states that the average canopy closure was 52 percent.

No waterbody segments that would be crossed by the pipeline are included on the list of 

impaired waterbodies under Section 303(d) of the CWA; however, Downeast states that all fresh 

waters in Maine are considered impaired by atmospheric deposition of mercury. There are no 

public surface water intakes for drinking water systems within 3 miles of the pipeline right-ofway.

Under Maine Statute Title 12, Chapter 200, Section 403, the Legislature granted special 

protection for Outstanding River Segments by declaring that “certain rivers, because of their 

unparalleled natural and recreational values, provide irreplaceable social and economic benefits 
4-45 4.3 – Water Resources

to the people in their existing state.” There are no Outstanding River Segments proposed to be 

crossed by the Downeast pipeline. 

The National Rivers Inventory (NRI) is a list of rivers that contain values and resources that the 

National Wild and Scenic Rivers Act is designed to protect and enhance. The NRI lists “... river 

segments in the United States that are believed to possess one or more outstandingly remarkable 

values judged to be of more than local or regional significance” (NPS 2008). No NRI designated 

waterbodies would be crossed by the proposed pipeline.

None of the streams affected by the construction or operation of the Downeast pipeline are listed 

under the National Wild and Scenic Rivers Act (16 U.S.C. §1276) or are listed for potential 

designation by the National Park Service. 

A list of the waterbodies crossed by the proposed sendout pipeline is included in table 4.3.2.2-1 

and shows the location by milepost, waterbody name, state water quality classification, 

waterbody width/crossing length, crossing method, stream type, and fishery type.

Activities that could affect surface waters include clearing, grading, trenching, blasting, 

backfilling, and right-of-way maintenance. These activities could result in increased turbidity 

and sedimentation, decreased oxygen levels, increased stream temperatures, release of chemical 

and nutrient pollutants from sediments, and accidental release of chemical contaminants such as 

fuels and lubricants. Downeast states that because of their limited width and depth, most streams 

would likely be crossed using conventional backhoe-type equipment and dry open-trench 

techniques specified in Downeast’s Plan, Procedures, and Soil Erosion and Sediment Guidelines. 

The dam and pump method is a dry-crossing technique that uses pumps to isolate water from the 

construction work area. This method is the preferred waterbody crossing technique to be 

employed by Downeast. Use of dam and pump crossing methods in flowing streams would 

reduce exposure of waterbodies to erosion and sedimentation, and thus reduce the overall impact 

on the waterbody. Downeast expects that most in-stream work within minor waterbodies would 

be completed within 24 to 48 hours. Trench spoils would be stored at least 10 feet from the 

water’s edge and would have erosion and sedimentation controls installed. Stream banks would 

be stabilized and temporary sedimentation barriers installed across the right-of-way within 

24 hours of completing in-stream construction. Therefore, most impacts would be temporary 

and suspended sediment concentrations and turbidity levels would be expected to return to 

preconstruction levels soon after construction in each stream was completed.

Because of the presence of known or suspected sites where soil and/or groundwater 

contamination may be present in the vicinity of the proposed pipeline route, it is possible that 

Downeast would encounter contaminated sediments in the waterbodies proposed to be crossed. 

Downeast has acknowledged this, and has stated that it would work with landowners to aid in 

identifying whether contaminated sediments may be present, develop construction procedures 

concerning contaminated sediments, and that it would notify Maine DEP if contaminated 

sediments were encountered. 

As shown on table 4.3.2.2-1, Downeast proposes to cross 9 of the 22 waterbodies using the HDD 

crossing method. The HDD method involves boring a pilot hole beneath the waterbody to the 

opposite bank and then enlarging the hole with one or more passes of a reamer until the hole is 

the necessary diameter. A prefabricated pipe segment is then pulled through the hole to 

complete the crossing. A successful drill generally results in no impact on the waterbody being 
4.3 – Water Resources 4-46

TABLE 4.3.2.2-1

Waterbodies Crossed by the Pipeline Route

Town MP Waterbody

Water Quality 

Classification 

a/

Width/Crossing 

Length

(linear ft) b/

Crossing

Method

Stream

Type

Fishery

Type c/

Robbinston 0.8 Eastern Stream B 25 / 25 Dam and Pump Perennial Cold-water

Robbinston 2.0 Unnamed stream B 4 / 4 Dam and Pump Intermittent Warm-water

Robbinston 4.3 Unnamed stream (outlet of 

Keene Lake)

B 9 /1,165 HDD Perennial Cold-water

Calais 6.7 Flowed Land Ponds B 12 / 141 HDD Perennial Cold-water

Calais 7.7 Unnamed stream (inlet to 

Flowed Land Ponds)

A 7 / 7 Dam and Pump Perennial Cold-water

Calais 8.6 Tributary of Beaver Brook 

(upstream of Flowed Land 

Ponds)

A 10 / 2,629 HDD Perennial Cold-water

Calais 12.3 Unnamed stream A 3 / 3 Dam and Pump Intermittent Warm-water

Calais 14.1-14.2 Magurrewock Stream 

Outlet

A 528 / 792 HDD Perennial Cold-water

Calais/ Baring 14.2-15.3 St. Croix River C 3,000 / 5,829 HDD Major river Cold-water

Baring 15.6 Unnamed stream A 3 / 3 Dam and Pump Intermittent Warm-water

Baring 15.6 Unnamed stream A 3 / 3 Dam and Pump Intermittent Warm-water

Baring 16.9 Conic Stream A 3 / 3 Dam and Pump Perennial Warm-water

Baring 17.2 Unnamed stream A 3 / 3 Dam and Pump Intermittent Warm-water

Baring 17.6 Unnamed stream, (tributary 

of St. Croix River)

A 3 / 3 Dam and Pump Perennial Warm-water

Baring 17.8 Unnamed stream, (tributary 

of St. Croix River)

A 8 / 1,227 HDD Perennial Warm-water

Baileyville 18.1 Unnamed stream, (tributary 

of St. Croix River)

A 4 / 1,227 HDD Perennial Cold-water

Baileyville 18.4 Stony Brook A 18 / 18 Dam and Pump Perennial Cold-water

Baileyville 21.3 Wapsaconhagen Brook A 37 / 37 Dam and Pump Perennial Cold-water

Baileyville 22.5 Unnamed stream (tributary 

of Wapsaconhagen Brook)

A 4 / 4 Dam and Pump Perennial Warm-water

Baileyville 25.2 Anderson Brook A 15 / 2,622 HDD Perennial Cold-water

Baileyville 25.8 (3 

crossings) Unnamed stream A 4 / 4, 4 / 4, 4 / 4 Dam and Pump Intermittent Cold-water

Baileyville 28.9 Headwater tributary to 

Anderson Brook

A 8 / 1,000 HDD Intermittent Cold-water

a/ State Designation - Based on Title 38 MRSA §465

A - 2nd highest classification. Must be of such quality that they are suitable for the designated uses of drinking water after disinfection; 

fishing; agriculture; recreation in and on the water; industrial process and cooling water supply; hydroelectric power generation, except 

as prohibited under Title 12, section 403; navigation; and as habitat for fish and other aquatic life. The habitat must be characterized as 

natural.

B - 3rd highest classification. Must be of such quality that they are suitable for the designated uses of drinking water supply after 

treatment; fishing; agriculture; recreation in and on the water; industrial process and cooling water supply; hydroelectric power 

generation, except as prohibited under Title 12, section 403; navigation; and as habitat for fish and other aquatic life. The habitat must 

be characterized as unimpaired.

C - 4th highest classification. Must be of such quality that they are suitable for the designated uses of drinking water supply after 

treatment; fishing; agriculture; recreation in and on the water; industrial process and cooling water supply; hydroelectric power 

generation, except as prohibited under Title 12, section 403; navigation; and as a habitat for fish and other aquatic life.

b/ Waterbody width determined from field measurements and aerial photograph interpretation.

c/ Fishery types were assigned based on habitat functionality observed during field assessment of proposed Pipeline crossings. Fishery 

habitat suitability assigned to waterbodies not sampled in the field were based on aerial photograph interpretation and MDIF&W fish 

stocking records.

HDD = Horizontal directional drill
4-47 4.3 – Water Resources

crossed and avoids disturbance to riparian vegetation between HDD entry and exit locations. 

For this reason, HDD is considered to be a preferred crossing method for major waterbodies, 

especially those that are sensitive or for areas where there are sensitive environmental issues. 

Downeast proposes to use HDD for a total of 26,030 feet of pipeline installation to avoid 

sensitive waterbodies and habitats such as vernal pools and wetlands. However, HDD is not 

technically feasible in some types of geologic environments such as glacial till, and it requires 

larger staging areas than other stream crossing methods. Downeast would need to conduct sitespecific geotechnical investigations at all proposed HDD crossings to determine the feasibility of 

completing directional drills in these areas.

While the HDD method is often the preferred method for installing pipelines across sensitive 

resources, it is not without some environmental risk. An inadvertent release of drilling mud 

could enter the waterbody being crossed or the HDD installation could fail due to unfavorable 

geologic conditions and/or equipment failure.

The HDD method involves the circulation of a drilling mud to remove cuttings, stabilize the bore 

hole, and cool and lubricate the drill bit. Drilling mud is composed primarily of naturally 

occurring materials, such as water and bentonite clay, and a small percentage of other additives. 

During the drilling process, drilling mud can enter waterbodies through coarse, unconsolidated 

formations, such as sand and gravel, or through fractured rock formations. When an inadvertent 

release of drilling mud returns to the surface or enters a waterbody, it is referred to as a “fracout.” A small release of drilling mud would likely dissipate and would not be detrimental to 

water quality, vegetation, fish, or wildlife. However, in larger quantities, the release of drilling 

mud into a waterbody could affect fisheries and vegetation; although impacts would likely be 

less than those associated with an open-cut crossing.

In the event of a frac-out incident that is accessible, Downeast has indicated that it would take 

the following appropriate measures:

• contain the location with straw bales such that the drilling fluid cannot migrate across the 

ground surface;

• excavate a small sump pit at the location and provide a means for the fluid to be returned 

to either the drilling operations or a disposal site (i.e., pump through a hose or into a 

tanker); and

• continue drilling operations and continue maintaining the integrity of the containment 

measures and monitoring the fluid returns as to ensure that no surface migration occurs. 

Should the inadvertent release of drilling fluid occur at a location that is inaccessible or along the 

bed of a waterbody and into the water, the following appropriate procedures would be followed:

• ensure that all reasonable measures have been taken to re-establish fluid circulation, such 

as reducing fluid pressure during pilot hole drilling or vary drilling fluid properties in 

order to reduce frictional drag and pressure;
4.3 – Water Resources 4-48

• continue drilling with the minimum amount of drilling fluid as required to penetrate the 

formation and successfully install the pipe; or

• if the amount of the release exceeds that which can be suitably contained with hand 

placed containment barriers, small collection sumps would be used for fluid removal and 

recycling. 

Appendix E has been updated to include site-specific construction diagrams for each proposed 

HDD crossing showing the location of mud pits, pipe assembly areas, and all areas to be 

disturbed or cleared for construction. Downeast would conduct preconstruction geotechnical 

evaluations to ensure that HDD drilling operations as proposed are feasible. Downeast has also 

stated that it would prepare and submit contingency plans prior to construction

In the event that an HDD is unsuccessful and the HDD crossing has to be abandoned, the HDD 

pilot hole would be filled with an environmentally safe fluid (typically a mixture of bentonite 

clay and water) that would match the consistency of the surrounding subsurface. Downeast has 

indicated that as a final contingency, the pipeline would be installed using a traditional trenched 

crossing. 

Downeast would obtain a Section 10 permit from the COE for work in navigable waterways and 

a Section 404 permit for placement of dredged or fill material into all waters of the United States, 

including wetlands. Downeast would also obtain an associated Section 401 Water Quality 

Certification from Maine DEP. A wastewater discharge permit would also be obtained from the 

state. The application to Maine DEP for a 401 Water Quality Certification was withdrawn by 

Downeast in November 2007; Downeast will resubmit its request following issuance of the final 

EIS. If any waterbody or wetland crossing plans are revised, Downeast would file the amended 

plans with the Secretary for review and written approval by the Director of OEP.

One of the largest HDD crossings proposed by Downeast is the 6,621-foot crossing of the 

St. Croix River and Magurrewock Stream Outlet between MP 14.1 and MP 15.3. The FWS, 

Maine DMR, Bureau of Indian Affairs (BIA), St. Croix International Waterway Commission, 

and the Passamaquoddy Tribe have expressed concerns about this crossing because of its 

proximity to the Moosehorn NWR boundary and Canadian border, the length of time to complete 

the HDD installation, the effects of noise and vibration on fish and wildlife, and impacts on tribal 

rights to the St. Croix River and islands within the St. Croix River.

Downeast has estimated that the HDD would take approximately 75 to 90 days to complete. 

This estimate is based on drilling 24 hours per day, with some reductions to 12 hours per day, to 

improve the likelihood of completing a successful drill and reducing the number of days that 

drilling would be required. The HDD is expected to occur between June and August; however, 

Downeast would coordinate with the Maine DMR to establish a construction schedule to avoid 

impacts on spawning fish. Because the HDD would be a minimum of 60 feet below the river 

bed, there should be minimal if any noise or vibration impacts on aquatic resources. Noise 

impacts from aboveground drilling operations at the entry and exit points are discussed in 

section 4.11.2.
4-49 4.3 – Water Resources

The centerline path of the proposed St. Croix River HDD is, at its nearest points, 150 feet away 

from the Moosehorn NWR and 120 feet away from the Canadian border. The nearest point to 

Moosehorn NWR is at MP 15.1, where the boundary of the NWR is on the south side of the 

Maine Central Railroad right-of-way. The nearest point to Canada is at MP 14.5, where both the 

drill path and the border are in the St. Croix River. Impacts on the Moosehorn NWR and Canada 

would be avoided. All of the HDD except the last 500 feet is north of the Maine Central 

Railroad, which forms a barrier to the Moosehorn NWR to the south. The last 500 feet are west 

of the Moosehorn NWR boundary, and the HDD exit point is 900 feet west of the NWR 

boundary. The area where the drill path gets closest to the Canadian border is approximately 

0.4 mile from the drill entry. Therefore, the drill would be very deep below the river, where an 

event, such as a release of drilling mud, reaching the surface would be very unlikely. 

The only dewatering would be localized passive dewatering to keep any entry/exit HDD trench 

and work area dry for worker safety. Otherwise, the pipeline would be installed “in the wet” or 

within the groundwater table. In the locations where the pipeline is installed below the 

groundwater table, the groundwater levels are expected to stabilize back to equilibrium 

conditions around the pipeline immediately upon completion of construction. The construction 

and operation of the pipeline would not affect groundwater or surface water flows in the area of 

drilling and would not disrupt migration of spawning fish.

Water quality would be protected during HDD operations adjacent to the St. Croix River by 

adherence to Downeast’s Plan, Procedures, and Soil Erosion and Sediment Control Guidelines 

and its contractors’ SPCC Plans based on the SPCC Plan template. All construction materials, 

fuels, and lubricants would be kept at least 100 feet away from the shoreline, and refueling of 

construction equipment would be conducted in upland areas 100 feet or more from the shore. 

The tailings and mud from the drilling activity would be pumped into temporary storage tanks 

and hauled to an approved disposal site.

We do not believe that the HDD would have any significant impact on any tribal rights to the use 

of the St. Croix River or the islands in the river at this location. Downeast has indicated that it 

has addressed the Passamaquoddy Tribe’s concerns by designing the HDD path in a manner that 

avoids all islands in the St. Croix River, avoids encroachment on any designated Indian trust 

lands, and avoids disturbance to the river’s ecosystem during construction and operation.

Downeast has provided us with information on successful direction drill projects of this length 

on other gas pipeline projects, and while we believe that HDD would avoid or minimize the 

significant impacts associated with this river crossing, we are concerned about the feasibility of 

the crossing. Downeast has evaluated the available geotechnical information relative to the 

subsurface conditions in the St. Croix River. Based on recent test borings for the international 

border crossing project, which is just north of the proposed HDD alignment, the subsurface 

conditions at the St. Croix HDD are expected to consist of stiff marine clay over dense glacial till 

and bedrock. Rock at the site is expected to consist of fresh schist/quartzite and granite, with top 

of rock likely ranging between 15 and 25 feet below ground surface. Due to the relatively 

shallow depth to rock and the length of the drill, the majority of the crossing is anticipated to be 

drilled in rock.
4.3 – Water Resources 4-50

According to Downeast and based on the available subsurface information and the relatively stiff 

nature of the soil/rock profile at the site, an HDD crossing at this location is technically feasible 

and the subsurface conditions are considered to be favorable for this type of construction. In 

addition, the M&NE pipeline crossing of the St. Croix River at Baileyville was completed using 

HDD in similar subsurface conditions. Downeast has indicated that it would file a geotechnical 

feasibility assessment of the HDD location prior to requesting authorization to commence 

construction of its terminal or pipeline facilities and that the St. Croix HDD would be the first 

portion of the sendout pipeline constructed. Construction drawing Number DOW-E-HDD-15.0 

Rev. No. A, included in Appendix E of this EIS, shows the St. Croix HDD location of mud pits, 

pipe assembly areas, and all areas to be disturbed or cleared for construction. FERC staff would

review all supplemental information when filed, and would consult with resource agencies as 

appropriate during that review. However, to ensure that the HDD plan for the St. Croix River 

adequately addresses aquatic resources, we recommend that:

• Prior to construction of the pipeline facilities, Downeast should consult with NOAA 

Fisheries on the proposed St. Croix HDD plan and file with the Secretary copies of 

NOAA Fisheries comments on the St. Croix HDD plan.

Downeast’s informal discussions with relevant resource agencies have indicated that the 

agencies are not comfortable with the potential environmental impacts of an open-cut crossing of 

the St. Croix River and thus would not support this construction method. Accordingly, 

Downeast is not proposing an open-cut crossing procedure as a contingency plan for the St. 

Croix River crossing. Prior to commencing the proposed HDD, Downeast would submit a 

geotechnical and environmental report for an alternate route inland of the proposed St. Croix 

HDD location for review and approval of the Director of OEP and relevant federal and state 

agencies. This alternate route would cross U.S. Route 1 and proceed to the Calais Industrial 

Track Railroad right-of-way owned by Pan Am Railways. The route would then travel along the 

southeast side of the railroad right-of-way between the St. Croix River and the Moosehorn NWR 

and continue on the railroad right-of-way to just beyond the city of Calais border near Baring, at 

which point the route would diverge south to the U.S. Route 1 right-of-way (see construction 

drawing Number DOW-E-HDD-15.0 Rev. No. A in Appendix E of this EIS). If the proposed 

St. Croix HDD fails, Downeast would need additional FERC approval before proceeding with 

any alternate HDD alignment.

The COE has requested that we include in this EIS an analysis of alternate crossing methods to 

the dam and pump method that Downeast proposes for the majority of the waterbody crossings 

to determine if there are practicable alternatives that would not require placement of fill in the 

waterways. The three alternatives that we are aware of that could be used that would not require 

excavation and temporary placement of fill within a waterway are a pipe bore, HDD, and the 

direct-pipe lay technique.

A pipe bore is the technique used to cross major roads, highways, and railroads. In a pipe bore, a 

pit would be excavated on both sides of the streambed to the elevation of the bottom of the 

pipeline bore with a width sufficient for the pipeline and casing to be pulled through. This 

technique is not typically used at stream crossings because of the need to excavate large pits on 

both sides of the streambed, creating more disturbances adjacent to the stream crossing. It would 

also have the potential for water intrusion into the pits requiring trench dewatering and 
4-51 4.3 – Water Resources

discharge. For these reasons, we do not believe this is a practicable alternative to the methods 

proposed by Downeast.

The HDD technique is described in detail above. While it does prevent filling the stream, there 

are constructability, environmental, and economic issues that may not make it a reasonable or 

practicable alternative for all waterbody crossings.

Site constraints dictate whether HDD is the appropriate method to use. For HDD to be viable, 

stream subsurface geotechnical properties must be appropriate to conduct HDD.

HDD also requires extensive staging areas on both sides of the stream to set up the drilling 

equipment, mud pits, and a pipe assembly area. In many instances, we feel the additional 

clearing and the extensive mobilization could create more adverse environmental impacts than 

the dam and pump method proposed by Downeast.

In addition, HDD is a costlier technique due to the price of equipment, the setup and breakdown 

time and expense, the risk of setback or failure, and the relative paucity of trained operators. 

HDD generally is used to cross environmentally sensitive rivers or other habitats where the 

environmental effects of other crossing methods cannot be mitigated through other means. For 

these reasons, we do not believe that HDD is a practicable alternative for all the stream crossings 

along the sendout pipeline route. As discussed above, the dam and pump technique reduces the 

exposure of the waterbodies to erosion and sedimentation, and for most of the crossings can be 

accomplished within 24 to 48 hours.

In response to past concerns raised by federal, state, and local agencies regarding the potential 

impact of construction of pipeline projects in general, we developed our Procedures to provide 

guidelines for an acceptable level of protection for wetlands and waterbodies affected by pipeline 

projects. Our Procedures include requirements for pre-construction planning, environmental 

inspection, construction methods, sediment and erosion control, restoration, and postconstruction maintenance. It includes provisions to handle stormwater and protection of 

waterbodies and wetlands from accidental spills of fuels or hazardous materials. Downeast has 

adopted our Procedures as part of its Plan, Procedures, and Soil Erosion and Sediment Control 

Guidelines. We believe that using the measures detailed in our Procedures and applicable 

permits would minimize both short- and long-term impacts on water resources. 

Lubricant, hydraulic fluid, and fuel spills from refueling construction equipment, fuel storage, or 

equipment failure in or near a waterbody could flow or migrate to the waterbody and 

immediately affect aquatic resources and contaminate the waterbody downstream of the release 

point. Downeast would follow the measures outlined in the project-specific SPCC Plans 

prepared by its contractors to minimize the potential impacts of spills of hazardous materials 

during construction in waterbodies. 

Prior to being placed into service, the sendout pipeline would be hydrostatically tested to DOT 

standards, as listed in 49 CFR 192. The sendout pipeline (or sendout pipeline segments) would 

be pressurized to the design test pressure and the pressure would be maintained for a minimum 

of eight hours. If during the test period any leaks are detected, the leaks would be repaired and 

the test section re-pressurized until the DOT specifications are met.
4.3 – Water Resources 4-52

Downeast would prepare a Hydrostatic Testing Plan to address the methods of water withdrawal 

and discharge. Approximately 6.1 million gallons of water would be required for hydrostatic 

testing of the entire 29.8-mile, 30-inch-diameter sendout pipeline. Downeast has stated that the 

sendout pipeline may be tested in more than one segment, allowing for reuse of some of the 

water and lowering the quantity needed. The water volume necessary would be dependent on the 

length of the segments tested. Downeast has identified the BUD as the source of hydrostatic test

water through a direct connection to the fire hydrant system. 

Downeast has indicated that the hydrostatic test water would be discharged to an unnamed creek 

at MP 17.5 or to the BUD sewer system at a rate of 1,400 to 2,800 gpm. Discharge of 

hydrostatic test water used to test the integrity of oil and gas facilities requires permitting from 

the Maine DEP. In addition, hydrostatic test waters that fall under the jurisdiction of the Maine 

DEP and that would be discharged into waters of the state would require a permit under the 

Maine PDES, as regulated by the CWA. The appropriate Section 401 Water Quality 

Certification and Section 404 permit must also be obtained prior to discharge of hydrostatic test 

water into surface waterbodies. 

Operations 

Operation of aboveground facilities associated with the proposed sendout pipeline, such as pig 

launchers and receivers, are not expected to affect water resources. Operational activities with 

the potential to impact water quality would be limited to maintenance of the permanent right-ofway and repair of the pipeline. To minimize impacts on water quality and riparian vegetation, 

Downeast would allow a riparian buffer at least 25 feet wide, as measured from the waterbody’s 

mean high water mark, to permanently revegetate with native plant species across the entire 

right-of-way after construction is completed. However, trees greater than 15 feet tall, or deeprooted shrubs that could damage the pipeline’s protective coating, obscure periodic surveillance, 

or interfere with potential repairs, would not be allowed to grow within 15 feet of the pipeline. 

The frequency of the vegetation maintenance would depend upon the vegetation growth rate. 

This could lead to minor increases in stream temperature in these localized areas, but would not 

be expected to cause significant temperature increases farther downstream.

The Passamaquoddy Tribe expressed concern about operational impacts of the pipeline on the 

St. Croix River ecosystem, specifically potential changes to water temperature. Downeast has 

indicated that the sendout pipeline carries natural gas (not cryogenic gas) that is at a temperature 

of 41°F, which is near the ambient ground temperature of 45 to 55°F. The pipeline also would 

be located at least 10 feet below the bottom of the St. Croix River. Therefore, operation of the 

pipeline would have no temperature impact on the river ecosystem.

Because the sendout pipeline would be installed at a sufficient depth below the beds of 

waterbodies, exposure of the sendout pipeline is not expected. In the event that a pipeline 

anomaly (i.e., corrosion, dent, or rupture) is detected during routine inspections, pipeline 

excavation or replacement could be required within a waterbody. Impacts from these 

maintenance activities would be expected to be similar to those described for construction and 

would be subject to additional state and federal permitting. Therefore, operation of the project 

should not have a significant impact on water resources. 
4-53 4.4 – Wetlands and Vegetation

4.4 WETLANDS AND VEGETATION

This section describes the plant species and vegetative communities within the project area, 

construction and operational impacts on vegetative communities that would result from the 

project, and measures that would be taken to avoid, minimize, and mitigate for impacts on these 

communities. This section also covers photosynthesizing marine organisms such as 

phytoplankton and algae. The project has been designed to avoid significant impacts, and 

minimize and mitigate for unavoidable impacts on vegetation. Downeast would provide 

environmental training to construction and operations personnel, and EIs would monitor and 

enforce compliance with environmental permit conditions during construction and operations. 

4.4.1 Wetlands

Wetlands are areas inundated or saturated by surface water or groundwater at a frequency and 

duration sufficient to support, and that under normal circumstances do support, a prevalence of 

vegetation typically adapted for life in saturated soil conditions (33 CFR Part 328.3[b]). The 

Downeast LNG Project would cross coastal and freshwater wetlands, which are both regulated 

by the COE and Maine DEP under such regulations as the CWA, the Rivers and Harbors Act, 

and the Maine Natural Resources Protection Act (NRPA). Downeast submitted the NRPA and 

CWA Individual Permit applications in December 2006. The COE determined the applications 

under Section 10 of the Rivers and Harbors Act and under Section 404 of the CWA to be 

incomplete. The applications are not currently active for processing pending additional 

information to be submitted by Downeast. The application to Maine DEP for a 401 Water 

Quality Certificate under the NRPA was withdrawn by Downeast in November 2007; it will be 

resubmitted following issuance of the final EIS. The COE has noted that wetland delineations to 

support the revised permit applications must be performed according to the 1987 Corps of 

Engineers Wetland Delineation Manual (COE 1987) as well as the COE’s 2012 Regional 

Supplement. 

Coastal wetlands, as defined by Maine DEP, include estuarine intertidal and subtidal wetlands, 

which support vegetation tolerant of saline water. Intertidal wetlands are transitional vegetated 

areas along the shoreline that are periodically flooded by the tide. Subtidal habitats have 

substrates that are continuously flooded by tidal water. Vegetation commonly found in coastal 

wetlands consists of various seagrass species. Macroalgae, such as kelp species, are also 

commonly found in coastal wetlands. See section 4.4.2 for additional discussion of subtidal 

vegetation.

Freshwater wetlands found within the Downeast LNG Project area include riverine and 

palustrine habitats. Riverine wetland systems are supplied by waters from adjacent rivers or 

streams, while palustrine wetlands are supplied by precipitation, either as a surface or 

groundwater source. Freshwater wetlands in the project area can be generally classified as 

emergent, scrub-shrub, or forested. Emergent wetlands consist of erect, rooted, herbaceous 

plants that persist for most of the growing season. Scrub-shrub wetlands include areas 

dominated by woody vegetation less than 20 feet tall and are vegetated with true shrubs, young 

trees, and trees or shrubs that are small or stunted because of environmental conditions. 

Palustrine forested wetlands contain woody vegetation that is 20 feet or taller (Cowardin 

et al. 1979). 
4.4 – Wetlands and Vegetation 4-54

Wetland presence within the Downeast LNG Project boundaries was determined by the review 

of maps and field surveys using methods approved by the COE (COE 1987). The following 

sections describe the location of wetlands; potential impacts caused by construction and 

operation of project facilities (waterway for LNG marine traffic, LNG terminal, pier, and sendout 

pipeline); and mitigation for unavoidable wetland disturbance. 

Vernal pools are shallow depressions that usually contain water for only part of the year and are 

often associated with forested wetlands. Vernal pools serve as essential breeding habitat for 

certain species of wildlife, including salamanders and frogs. Jurisdiction for vernal pools falls 

under both Maine DEP and COE regulations. As of September 2007, SVP habitat is protected 

by law under the NRPA. Accordingly, Maine DEP adopted Section 9 of Chapter 335, which 

provides SVP identification criteria and habitat management standards. Vernal pools that occur 

within COE-jurisdictional wetlands are reviewed under COE regulations. Vernal pools outside 

wetland boundaries or those deemed significant are reviewed under Maine DEP regulations. 

Vernal pools are considered “significant” by Maine DEP if they have a high habitat value, either 

because (1) a state-listed threatened or endangered species uses it to complete a critical part of its 

life history, or (2) there is a notable abundance of specific wildlife, such as blue-spotted 

salamander, wood frog, or fairy shrimp. SVP habitat includes the vernal pool itself and the area 

within a 250-foot radius of the spring or fall high water mark of the pool, which is considered 

critical terrestrial habitat. 

Identification of vernal pools and SVPs within the terminal and sendout pipeline boundaries was 

completed in spring 2007 for the original pipeline alignment. Surveys for vernal pools along the 

rerouted segment of the pipeline were conducted in summer 2007. Assessment of SVP status

was conducted in spring 2008. Results of the surveys are discussed in sections 4.4.1.2 

and 4.4.1.3. 

4.4.1.1 Waterway for LNG Marine Traffic

There would be no impacts on freshwater wetlands as a result of normal LNG transit. Marine

vegetation, including eelgrass, is discussed in section 4.4.2.

The Canadian Government prepared a study of anticipated impacts on Canadian lands resulting 

from LNG development in Passamaquoddy Bay, including wetland resources in the area of 

Grand Manan, Head Harbour Passage, Passamaquoddy Bay, and the St. Croix River near 

St. Andrews, New Brunswick. The study identified 30 freshwater wetlands greater than 

24.7 acres in the lower St. Croix watershed. Eleven environmentally significant areas were 

identified from the New Brunswick Department of the Environment and Local Government and 

the Atlantic Canada Conservation Data Center databases. These areas are on Campobello Island 

(three areas), Grand Manan (two areas), and various public lands (six areas), and were listed as 

having special significance for wetlands and/or plants. The study concluded that the most likely 

potential effect to these wetland habitats from LNG development would be the accidental release 

of contaminants within the marine waterway from vessels transiting between the LNG port and 

the open ocean. We believe these impacts are not likely to occur as vessels transiting to the LNG 

terminal must comply with the Coast Guard regulations or they would not be granted access to 

the waterway.
4-55 4.4 – Wetlands and Vegetation

4.4.1.2 LNG Terminal

Wetland presence at the proposed terminal location was determined by field surveys (underwater 

and terrestrial) and aerial photo interpretation conducted in 2005. Freshwater wetlands that are 

regulated by the Maine DEP and the COE were delineated at the terminal site in September 

2005. At the proposed location of the pier, approximately 5.91 acres of subtidal wetland10 and 

0.7 acre of intertidal wetland11 are present in the area where the pier would be located. Subtidal 

coastal wetlands support kelp of the species Laminaria (Mann 1973; Sebens 1986). Most of 

these macroalgae species are associated with hard structures or substrates, which are limited in 

the Downeast LNG Project area and therefore, large populations of macroalgae are limited as 

well. Intertidal areas of Passamoquoddy Bay support a variety of brown algae such as knotted 

wrack (Ascophyllum spp.), rockweed (Fuscus spp.), and bladderwrack (Fuscus spp.). Other 

species of macroalgae found in protected tidal pools or areas with high tidal and wave action, 

such as sea lettuce (Ulva lactuca), Irish moss (Chondrus crispus), and kelp (Alaria esculenta), 

are not found at the LNG terminal site. 

Beyond the coastal area, two freshwater wetlands were identified at the location of the proposed 

LNG terminal (see figure 4.4-1). These wetlands offer several important functions, including 

water storage, flood attenuation, groundwater recharge and discharge, water quality 

improvement, and wildlife habitat. Wetland 1 is a mix of forested and scrub-shrub vegetation. 

This wetland community bisects the LNG terminal site from an outlet to Passamaquoddy Bay 

near the northeastern boundary of the site, trending south and southeast across the site. Much of 

this wetland has been disturbed by historical agriculture use and timber harvest; however, the 

portions of the forested wetland that were not recently harvested are characterized by a wellestablished canopy, a relatively sparse shrub layer, and a sparse herbaceous layer. In general, a 

bryophyte layer composed of Sphagnum moss covers much of the ground in these relatively 

undisturbed areas. The harvested portions of the wetland are characterized by either dense shrub 

regeneration or relatively open areas with a well-developed herbaceous layer. The portion of the 

wetland that was in agricultural use until the 1960s is now a mix of dense shrub growth and 

relatively open wet meadow. Speckled alder (Alnus incana), choke cherry (Prunus virginiana), 

meadowsweet (Spiraea alba var. latifolia), and Virginia rose (Rosa cf virginiana) dominate the 

dense scrub-shrub area, whereas the wet meadow is characterized by herbaceous species such as 

foxtail (Alopecurus sp.), a sedge (Scirpus microcarpus), awl-fruited sedge (Carex stipata), 

tussock sedge (C. stricta), soft rush (Juncus effusus), flat-topped white aster (Doellingeria 

umbellata), bristly aster (Symphyotrichum puniceum), Canada goldenrod (Solidago canadensis), 

and woodland horsetail (Equisetum sylvaticum).

 10 Wetland is classified by the FWS as an estuarine, subtidal, unconsolidated bottom, subtidal wetland. The FWS 

classification code for this type of wetland is E1UBL.

11 A portion of this wetland consisting of 0.11 acre is classified by the FWS as an estuarine, intertidal, 

unconsolidated shore, sand, regularly flooded wetland (FWS classification code E2US2N) and 0.58 acre of this 

wetland is classified by the FWS as an estuarine, intertidal, unconsolidated shore, aquatic bed, algal, regularly 

flooded wetland (FWS classification code of E2AB1N).
Figure 4.4-1 

Downeast LNG Project

LNG Terminal Wetlands

4-56
4-57 4.4 – Wetlands and Vegetation

Wetland 2 is a forested wetland in the southwestern corner of the site that extends south beyond 

the terminal property boundaries. As with Wetland 1, a portion of the overstory of this wetland 

was removed during timber harvesting. This wetland receives surface water flow from two 

culverts under U.S. Route 1, as well as groundwater discharge from hillside seeps. The 

overstory of Wetland 2 is comprised of white spruce (Picea glauca), balsam fir (Abies 

balsamea), northern white cedar (Thuja occidentalis), and yellow birch (Betula alleghaniensis). 

Shrub species documented include speckled alder, pussy willow (Salix discolor), long-beaked 

willow (Salix bebbiana), meadowsweet, Virginia rose, red raspberry (Rubus idaeus), gray birch 

(Betula populifolia), quaking aspen (Populus tremuloides), green ash (Fraxinus pennsylvanica), 

larch (Larix laricina), northern white cedar, red maple (Acer rubrum), witherod (Viburnum 

nudum), and mountain holly (Nemopanthus mucronatus). Herbaceous species include flattopped white aster, calico aster (Symphyotrichum lateriflorum), bristly aster, rough-stemmed 

goldenrod (Solidago rugosa), wild strawberry (Fragaria virginiana), red raspberry, dwarf 

raspberry (Rubus pubescens), fowl mannagrass (Glyceria striata), bluejoint (Calamagrostis 

canadensis), sedges (C. flava, C. intumescens, C. scabrata), wool-grass (Scirpus cyperinus), 

woodland horsetail, soft rush, sensitive fern (Onoclea sensibilis), cinnamon fern (Osmunda 

cinnamomea), and crested wood fern (Dryopteris cristata). A dense mat of Sphagnum moss 

dominates much of the forested wetland floor. Table 4.4.1.2-1 shows the acreage of disturbance 

for each wetland crossed.

TABLE 4.4.1.2-1

Summary of Wetlands Affected by Construction and Operation

Wetland 

No. Facility Approx. Milepost Wetland Classes Permanent Impacts (acres) a/

Construction 

Impacts 

(acres) b/

Terminal PFO/PSS 9.00 9.00

Terminal E1UBL/E2US2N/E2AB1N 0.10 0.10

Total 9.10 9.10

1 Pipeline 0.04 PSS 0.01 0.12

2 Pipeline 0.39 PFO 0.22 0.46

3 Pipeline 0.64 PSS 0.08 0.15

4 Pipeline 0.80 PFO/Stream 0.03 0.05

5 Pipeline 1.02 PSS/PFO 0.37 0.63

13 Pipeline 1.95 PFO 0.05 0.07

14 Pipeline 2.02 PFO/ STREAM 0.06 0.15

15 Pipeline 2.10 PFO/PEM 0.17 0.32

16 Pipeline 2.16 PFO 0.04 0.05

17 Pipeline 2.25 PFO 0.01 0.01

18 Pipeline 2.54 PFO 0.51 1.02

18-1 Pipeline 2.73 PFO 0.03 0.06

21-1 Pipeline 3.32 PSS 0.03 0.03

21-2 Pipeline 3.40 PSS 0.10 0.13

25 Pipeline 4.15 PEM/PSS/PFO/Stream 0.05 0.08

6-36 Pipeline 4.44 PFO/PEM 0.00 0.04

26 Pipeline 4.60 PFO/Stream 0.03 0.05
4.4 – Wetlands and Vegetation 4-58

TABLE 4.4.1.2-1

Summary of Wetlands Affected by Construction and Operation

Wetland 

No. Facility Approx. Milepost Wetland Classes Permanent Impacts (acres) a/

Construction 

Impacts 

(acres) b/

27-1 Pipeline 4.68 PFO 0.04 0.08

27-2 Pipeline 4.82 PFO 0.01 0.08

28 Pipeline 4.90 PFO 0.12 0.20

28-1 Pipeline 4.95 PFO 0.00 0.02

28-2 Pipeline 5.01 PFO 0.03 0.03

6-39 Pipeline 5.06 PSS 0.05 0.06

32 Pipeline 5.65 PUB 0.00 0.01

33 Pipeline 6.00 PFO/PSS 0.20 0.38

34 Pipeline 6.13 PFO 0.35 0.63

35 Pipeline 6.37 PFO 0.00 0.00

36 Pipeline 6.62 PFO 0.25 0.51

37 Pipeline 7.64 PEM/PSS/PFO/ STREAM 0.15 0.27

38 Pipeline 7.82 PFO/PSS 0.00 0.00

39 Pipeline 7.87 PFO/PSS 0.04 0.09

40 Pipeline 8.03 PFO/PSS 0.09 0.17

48-1 Pipeline 9.85 PFO 0.04 0.06

50 Pipeline 10.29 PFO 0.12 0.17

6-6 Pipeline 12.31 PFO 0.00 0.00

6-9 Pipeline 12.97 PSS1 0.06 0.11

6-10 Pipeline 13.01 PFO, PSS1, PEM 0.14 0.29

6-11 Pipeline 13.89 PSS1+4, PEM1 0.70 1.14

6-12 Pipeline 14.06 PFO1 0.01 0.01

6-13 Pipeline 15.33 PFO4+2 0.02 0.04

6-14 Pipeline 15.37 PFO4 0.01 0.02

6-15 Pipeline 15.40 PEM1 0.01 0.02

6-16 Pipeline 15.42 PSS1 0.00 0.00

6-17 Pipeline 15.49 PSS1, PFO4 0.00 0.01

6-18 Pipeline 15.53 PSS1 0.00 0.01

6-19 Pipeline 15.56 PFO1 0.00 0.03

6-20 Pipeline 15.78 PFO1 0.03 0.06

6-21 Pipeline 15.85 PFO1 0.08 0.14

6-22 Pipeline 15.94 PFO 0.01 0.08

6-23 Pipeline 16.04 PFO1 0.10 0.29

6-41 Pipeline 16.11 PFO 0.00 0.01

6-42 Pipeline 16.36 PSS 0.73 1.46

6-25 Pipeline 16.46 PFO1, PSS1, PEM 0.46 0.90

6-26 Pipeline 16.66 PFO1, PSS1 0.29 0.48

6-27 Pipeline 16.87 PFO4, PSS1 0.00 0.00
4-59 4.4 – Wetlands and Vegetation

TABLE 4.4.1.2-1

Summary of Wetlands Affected by Construction and Operation

Wetland 

No. Facility Approx. Milepost Wetland Classes Permanent Impacts (acres) a/

Construction 

Impacts 

(acres) b/

6-43 Pipeline 16.93 PFO 0.01 0.07

6-44 Pipeline 17.01 PSS 0.00 0.00

6-28 Pipeline 17.04 PSS1, PEM1 0.01 0.03

6-29 Pipeline 17.10 PSS1 0.11 0.13

6-30 Pipeline 17.23 PFO4, PSS1, R2SB3 0.11 0.22

6-31 Pipeline 17.41 PFO4, PSS1 0.13 0.25

6-32 Pipeline 17.49 PSS1, PFO4 0.00 0.01

6-33 Pipeline 17.55 PFO1, R2SB3 0.02 0.02

6-34 Pipeline 17.65 PSS1, PEM1 0.04 0.04

95 Pipeline 17.70 PEM/PSS/PFO 0.03 0.04

98 Pipeline 18.23 PFO 0.04 0.04

99 Pipeline 18.26 PFO/PEM/PSS 0.02 0.05

100 Pipeline 18.37 PEM/PSS/PFO/ STREAM 0.15 0.25

101 Pipeline 18.45 PEM 0.00 0.00

102 Pipeline 18.52 PFO 0.10 0.15

103 Pipeline 18.58 PFO/PSS/PEM 0.03 0.07

104 Pipeline 18.73 PFO/PEM 0.04 0.06

105 Pipeline 18.79 PEM 0.00 0.00

106 Pipeline 18.81 PFO/PSS 0.04 0.04

107 Pipeline 18.82 PEM/PSS/PFO 0.00 0.00

108 Pipeline 18.84 PEM 0.02 0.03

109 Pipeline 19.02 PFO/PEM 0.11 0.21

110 Pipeline 19.11 PEM/PFO 0.04 0.11

111 Pipeline 19.21 PEM 0.00 0.01

112 Pipeline 19.52 PEM/PFO 0.05 0.09

113 Pipeline 19.60 PFO/PSS/PEM 0.15 0.24

114 Pipeline 19.67 PEM/PSS 0.08 0.17

115 Pipeline 20.04 PEM 0.00 0.01

116 Pipeline 20.14 PEM 0.02 0.15

117 Pipeline 20.60 PEM 0.00 0.00

118 Pipeline 20.63 PEM 0.08 0.15

119 Pipeline 20.73 PEM/PFO 0.48 0.92

120 Pipeline 21.05 PFO 0.01 0.02

121 Pipeline 21.17 PEM 0.00 0.01

122 Pipeline 21.23 PEM/PFO 0.04 0.08

125 Pipeline 21.52 PEM 0.00 0.00

126 Pipeline 21.55 PEM 0.00 0.00

127 Pipeline 21.78 PSS/PEM/PFO 0.02 0.02
4.4 – Wetlands and Vegetation 4-60

TABLE 4.4.1.2-1

Summary of Wetlands Affected by Construction and Operation

Wetland 

No. Facility Approx. Milepost Wetland Classes Permanent Impacts (acres) a/

Construction 

Impacts 

(acres) b/

128 Pipeline 21.91 PSS 0.00 0.00

129 Pipeline 22.11 PFO/PSS 0.06 0.07

130 Pipeline 22.14 PEM/PSS 0.07 0.17

131 Pipeline 22.19 PEM/PFO 0.02 0.06

132 Pipeline 22.22 PEM 0.00 0.00

133 Pipeline 22.39 PEM/PSS/PFO/STREAM 0.58 1.06

134 Pipeline 22.80 PFO 0.01 0.02

135 Pipeline 23.07 PFO 0.06 0.08

136 Pipeline 23.47 PEM/PFO 0.38 0.70

137 Pipeline 23.75 PFO 0.04 0.04

139 Pipeline 24.43 PSS/PUB 0.13 0.13

140 Pipeline 24.59 PEM/PFO 0.55 1.04

141 Pipeline 24.96 PSS/PFO 0.04 0.09

144 Pipeline 25.57 PSS/PFO 0.09 0.17

145 Pipeline 25.65 PFO/ STREAM 0.09 0.14

146 Pipeline 25.84 PSS/PFO/STREAM 1.00 1.70

147 Pipeline 26.05 PFO/PSS 0.07 0.11

148 Pipeline 26.14 PSS/PFO 0.37 0.66

149 Pipeline 26.28 PFO 0.00 0.00

150 Pipeline 26.30 PFO/PSS 0.06 0.08

Total 11.74 21.59

Access Roads 0.00 0.14

Staging Areas c/ 0.00 3.30

Total 0.00 3.44

Project Total 20.84 34.14

E1UBL – Estuarine Subtidal Unconsolidated Bottom

E2US2N – Estuarine Intertidal Unconsolidated Shore Sand Regularly Flooded

E2AB1N – Estuarine Intertidal Aquatic Bed Algal Regularly Flooded

PEM – Palustrine emergent

PFO – Palustrine forested

PSS – Palustrine scrub-shrub

PUB – Palustrine unconsolidated bottom

STREAM – Indicates stream also present

a/ Operational impacts are based on maintenance of a 30-foot-wide permanent right-of-way. This includes a 10-foot-wide strip 

(centered over the pipeline) that would be permanently maintained as herbaceous wetland during operation of the project. In 

addition, trees within 15 feet of the pipeline greater than 15 feet in height may be selectively cut and removed from the permanent 

right-of-way.

b/ Construction impacts for the pipeline are based on a 55- to 75-foot-wide right-of-way

c/ Includes ATWS, HDD ATWS, pipe laydown, and pipe storage areas.

Wetlands 1 and 2 offer several important functions and values. According to Attachment 12 of 

Downeast’s NRPA Tier 3 Application, Wetland 1 provides eight functions, three of which are 

principal. The principal functions of Wetland 1 are floodwater alteration, sediment/toxicant 
4-61 4.4 – Wetlands and Vegetation

reduction, and wildlife habitat. The secondary functions of Wetland 1 include groundwater 

discharge, fish habitat, nutrient removal, production export, and sediment/shoreline stabilization. 

Wetland 2 provides five functions, two of which are principal. The principal functions of 

Wetland 2 are floodwater alteration and wildlife habitat. The secondary functions of Wetland 2 

are sediment/toxicant retention, nutrient removal, and sediment/shoreline stabilization. Neither 

wetland is notable for its wetland values, such as recreation, education, heritage value, visual 

quality, or endangered species habitat.

As described above, three coastal wetlands were identified in the location of the proposed pier 

structure (two intertidal and one tidal), totaling 6.6 acres. The direct impact on these habitats 

(about 0.1 acre) would be the surface area of solely the pier pilings themselves.

Construction methods for the pier are discussed in section 2.0 of this EIS. A combination of 

land-based and marine-based equipment would be used. Construction activities that could affect 

wetlands in the area include the installation of the pilings by vibration and drilling. Isolated 

areas would also be disturbed by barges anchoring during construction. No dredging activity is 

proposed. Temporary effects associated with these activities include sediment suspension and 

redistribution, turbidity plumes, and vegetation mortality. The use of land-based equipment in 

the nearshore, shallow waters would prevent significant suspension of sediments due to anchors 

and propeller wash. Vegetation in this area is sparse, and expected to rapidly re-colonize the 

disturbed areas. Additionally, the pier structure would provide habitat for rooted algae species 

and add functional complexity to this system. 

Permanent adverse effects to wetlands include shading and potentially altered hydrodynamic 

processes in the vicinity of the pier. Shading would be minimal due to the open nature of the 

pier pilings and the height above mean high water (18.8 feet). Temporary shading impacts 

would also occur periodically while LNG vessels are docked at the pier. Placement of support 

structures in areas of flow can result in altered hydrodynamic processes (Harbeneau and Holley 

2001; Dyhouse et al. 2003). Local current patterns could be influenced by the effect of the pier 

pilings deflecting flow or lowering its velocity, potentially resulting in the alteration of the area’s 

normal sediment deposition pattern. Potential consequences could include shifts in the 

distributions of benthic fauna requiring specific grain-size classes. In an effort to minimize the 

potential for these risks, Downeast would continue its efforts to reduce the total area of 

submerged pier structure and/or design the pier to minimize impacts on the bay hydrodynamics.

Two freshwater wetlands, totaling 9.0 acres, are within the boundaries of the proposed terminal. 

These wetlands are characterized above. Downeast would attempt to minimize the impacts on 

these wetlands during the facility design. However, given the location of the wetlands and the 

need to design the facility to meet various building and safety codes, there is no practicable way 

to avoid disturbing these wetlands during construction and operation of this facility. Therefore, 

for the purpose of impact assessment, it has been assumed that all 9.0 acres would be 

permanently altered by clearing, grading, and filling. Downeast has stated that wetland soils 

would be stockpiled on-site and, where feasible, utilized to recreate wetlands disturbed during 

construction. Any unused stockpiles of wetland soils would be hauled off-site or used, if needed, 

for nearby wetland mitigation projects.

To mitigate for the unavoidable wetland alterations associated with the proposed terminal, 

Downeast is proposing a combination of preservation, enhancement, and restoration at off-site 
4.4 – Wetlands and Vegetation 4-62

locations. Downeast and its consultants have met with the COE to discuss the jurisdictional 

determination of wetlands affected by project construction. Upon finalization of this 

jurisdictional determination and verification of vernal pools of special significance along the 

amended pipeline right-of-way, Downeast has stated that it would submit a revised mitigation 

and compensation plan to the regulatory agencies. The COE and Maine DEP are responsible for 

determining the areal extent necessary to satisfy compensation of the anticipated impacts on 

wetlands along with lost functions and values. However, Maine DEP generally provides the 

following compensation ratios: restoration – 1:1; enhancement – 1:1; and preservation – 8:1 

(310 CMR 5C(5)). The COE acknowledges these ratios, but in many circumstances has required 

more mitigation than that required by Maine DEP. The 2008 COE/EPA mitigation rule would 

apply to the proposed project.12 The COE New England Division also has mitigation guidance 

specific to the region, and the COE and Maine DEP have developed an In Lieu Fee program that 

can be used as compensatory mitigation for unavoidable impacts on wetland resources. The 

EPA expressed concern regarding the impact of active recreational vehicle trails on the functions 

and values of mitigation parcels, in addition to the potential need to improve stream crossings to 

reduce impacts on wildlife habitat. The Maine DIFW also noted the need to better define the 

existing roads and trails on the mitigation sites before plans are finalized. These issues will be 

addressed during the COE’s, EPA’s, and Maine DEP’s review of the mitigation and 

compensation plan.

Compensation for direct impact on 0.11 acre of coastal wetlands would include enhancement of 

two coastal wetlands in Addison, Maine. The hydrology of these wetlands has been altered by 

adjacent roads and dikes, thus reducing the efficacy of tidal flooding and flushing. Downeast 

proposes to restore hydrology to these locations by excavating cuts into the dikes and replacing 

an undersized culvert. These modifications would restore natural hydrologic regimes to 

approximately 3.8 acres of saltmarsh and freshwater wetlands.

Downeast proposes to compensate for direct impact on 9.0 acres of inland wetland by 

establishing conservation easements for preservation of approximately 157 acres of wetlands and 

wetland buffer habitat near Calais, Maine. The 157 acres would include approximately 27 acres 

of wetlands and 35 acres of inland waterfowl and wading bird habitat. The remaining upland 

areas border high-value wetlands. Preservation of these areas would protect floodwater 

alteration, water quality, and wildlife habitat. The proposed compensation exceeds the Maine 

DEP required compensation ratio for preservation. Revised maps of these areas would be 

provided upon completion of mitigation and compensation planning with the COE, Maine 

DIFW, and Maine DEP.

In order to ensure that adequate wetlands compensation is provided to the satisfaction of the 

relevant agencies, we recommend that:

• Downeast should continue consultation with the COE, EPA, and the Maine DIFW 

and DEP to finalize its wetland mitigation and compensation plan. Downeast should 

file the final plan with the Secretary, along with agency comments and applicable 

approvals, prior to construction of the pipeline or LNG terminal facilities.

 12 Final Mitigation Rule for the Department of Defense, Department of the Army, Corps of Engineers, 33 CFR Parts 

325 and 332; and U.S. Environmental Protection Agency, 40 CFR Part 230, Subpart J: Compensatory Mitigation for 

Losses of Aquatic Resources, effective June 8, 2008.
4-63 4.4 – Wetlands and Vegetation

In addition to the measures required by our Procedures, Downeast would be required to comply 

with wetland permit conditions set forth by the COE and Maine DEP. As part of its review of 

the project, the COE would evaluate whether practicable alternatives have been evaluated to 

avoid wetland impacts on the maximum extent possible. Downeast also would comply with all 

rules and regulations pursuant to the CZMA of 1972, the CWA, and the Maine PDES Program 

for LNG terminal facilities installation and operation to avoid and minimize impacts on marine 

and shoreland environments. We believe that with implementation of the measures proposed by 

Downeast, including use of our Procedures, compensatory mitigation for permanent wetland 

impacts, and compliance with applicable regulations, impact on wetlands from construction and 

operation of the LNG terminal would not be significant.

No vernal pools, or state-listed sensitive species associated with vernal pool habitat, were 

identified at the LNG terminal location. 

4.4.1.3 Sendout Pipeline

Wetlands along the sendout pipeline route were delineated in July and August 2006, and 

September 2007, where landowner access was granted. In areas where property access was not 

granted, wetlands were identified through aerial photo interpretation. The location (by milepost) 

and character of each wetland crossed by the sendout pipeline are listed in table 4.4.1.2-1 along 

with the approximate acreage of wetland disturbance during project construction and operation. 

Forested wetlands along the sendout pipeline are typically dominated by needle-leaved evergreen 

trees, balsam fir, red spruce (Picea rubens), northern white cedar, and larch, with subdominant 

broad-leaved deciduous hardwoods, paper birch (Betula papyrifera), red maple, and quaking 

aspen. Characteristic understory vegetation includes beaked hazelnut (Corylus cornuta), 

mountain holly, cinnamon fern, evergreen wood fern (Dryopteris intermedia), swamp dewberry 

(Rubus hispidus), 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 (C. scoparia), and rattlesnake mannagrass (Glyceria 

canadensis). Emergent wetlands are characterized by rushes (Scirpus spp.), sedges (C. spp.), and 

broad-leaved cat-tail (Typha latifolia).

Potential vernal pools were identified during field surveys in 2006 and 2007 for the pipeline 

alignment. Field verification of vernal pools and SVPs occurred in spring of 2007 for vernal 

pools identified in 2006, and in spring of 2008 for vernal pools identified in 2007. Downeast 

identified 43 vernal pools, of which 10 were determined to meet the criteria listed in Maine DEP 

Rules Chapter 335 Section 9 to be classified as SVP as a result of the 2007 and 2008 spring 

surveys (table 4.4.1.3-1). Implications related to wildlife use of vernal pool habitat are discussed 

further in section 4.5.1.3 of this EIS.

Effects within the 250-foot buffer zone for each pool are shown in table 4.4.1.3-1. Under the 

Maine NRPA review standards, an applicant must maintain a minimum of 75 percent of the 

critical terrestrial habitat surrounding SVPs (as defined by the NRPA, Chapter 335, Section 9) as 

unfragmented forest with at least a partially closed canopy of overstory trees. According to the 

Maine DEP, impacts on the vernal pool depression and failure to meet these criteria would 

require compensatory mitigation. Downeast would maintain more than 75 percent of the upland 

forest habitat within the 250-foot buffer surrounding each SVP. 
4.4 – Wetlands and Vegetation 4-64

TABLE 4.4.1.3-1

Vernal Pool Locations and Loss of Forested Land (acres) Associated with the Sendout Pipeline

Appr. 

MP

Vernal 

Pool ID

250' Buffer 500' Buffer 750' Buffer

Impact 

(acres)

Total 

Area 

(acres)

Percent 

of Buffer 

Impacted

Impact 

(acres)

Total 

Area 

(acres)

Percent 

of Buffer 

Impacted

Impact 

(acres)

Total 

Area 

(acres)

Percent 

of Buffer 

Impacted

1.1 6 0 4.3 0% 0.4 17.0 3% 1.0 38.8 3%

1.2 7 0 3.8 0% 0.3 15.9 2% 0.8 38.1 2%

1.2 8 a/ 0 4.3 0% 0 16.8 0% 0.4 39.8 1%

3.2 21S a/ 0 5.8 0% 0.7 20.3 4% 2.0 43.7 5%

3.2 21N a/ 0 6.2 0% 0.6 20.2 3% 1.8 43.9 4%

3.7 23 a/ 0 5.4 0% 1.1 19.5 6% 2.3 40.3 6%

4.9 20CF 0.8 5.3 14% 1.6 19.7 8% 2.5 43.0 6%

4.9 28 0 4.9 0% 1.2 18.9 6% 2.2 41.7 5%

4.9 05BK 0 4.6 0% 1.2 18.2 6% 2.1 40.7 5%

4.9 06BK 0.1 4.6 3% 1.3 18.2 7% 2.2 38.4 6%

9.0 44 0 5.2 0% 1.1 19.3 6% 2.6 42.0 6%

9.3 46 a/ 0 4.1 0% 0.8 18.0 5% 2.0 41.4 5%

9.5 48 0 4.3 0% 1.2 17.6 7% 2.5 39.4 6%

9.7 17EA 0.7 4.9 15% 1.5 18.7 8% 2.1 41.3 5%

12.0 11EA 0 4.8 0% 0 18.2 0% 0 40.8 0%

12.0 01BK 0 5.1 0% 0 18.9 0% 0 41.9 0%

12.0 02BK 0 5.1 0% 0 18.8 0% 0 41.7 0%

12.0 03BK 0 4.7 0% 0 18.2 0% 0 40.4 0%

12.0 04BK 0 4.9 0% 0 18.5 0% 0 41.5 0%

12.1 12EA a/ 0 6.5 0% 0.1 21.6 0% 0.7 45.7 1%

12.8 13EA 0 4.7 0% 0.8 18.4 4% 1.8 40.8 4%

13.0 14EA a/ 0.7 6.1 11% 1.2 20.7 6% 2.1 44.0 5%

13.0 15EA a/ 0.7 5.1 14% 1.4 16.8 9% 2.2 42.2 5%

13.0 16EA 0.9 4.6 19% 2.0 16.2 13% 2.8 36.1 8%

15.2 01EA 0 4.8 0% 2.0 14.1 14% 4.6 28.4 16%

15.3 02EA 0.5 4.8 10% 4.6 18.3 25% 7.3 38.9 19%

15.3 03EA 1.5 6.1 25% 4.4 20.8 21% 8.0 42.2 19%

15.3 04EA 1.4 7.9 17% 3.6 24.4 15% 7.3 47.2 16%

15.3 05EA 1.1 5.2 20% 3.7 19.1 19% 6.6 40.8 16%

15.3 06EA 1.3 6.6 20% 2.7 20.7 13% 6.7 41.0 16%

15.3 07EA 1.3 5.2 25% 2.5 17.1 15% 3.9 36.5 11%

15.3 08EA 0 5.9 0% 0 19.6 0% 1.3 37.2 4%

15.3 09EA 1.0 4.6 23% 2.3 18.0 13% 5.1 39.1 13%

15.4 10EA 0.9 5.1 19% 4.2 18.5 23% 6.2 36.4 17%

15.4 07BK 0.7 5.1 14% 4.2 18.4 23% 6.6 39.9 17%

17.0 18EA 0 2.6 0% 0.9 10.7 9% 1.9 23.1 8%

17.1 19EA 0 3.2 0% 0.9 12.5 7% 1.8 29.9 6%

24.4 138 0 2.4 0% 0.1 13.5 1% 0.1 31.6 0%

27.2 164W 0 1.6 0% 0 11.9 0% 0 30.4 0%

27.2 164E 0 2.1 0% 0 11.8 0% 0 31.1 0%

29.2 174 a/ 0 5.6 0% 0.6 18.1 3% 1.2 40.7 3%

29.6 178 0.9 2.7 33% 1.3 13.6 10% 1.6 33.7 5%

29.8 179 a/ 0 5.5 0% 0.5 14.9 3% 0.8 34.4 2%

a/ denotes SVP

To minimize impacts on vernal pools, Downeast would use the guidelines approved by FERC, 

the COE, and the State of Maine for the M&NE Phase II Pipeline Project (Soil Erosion and 

Sediment Controls Guidelines). Additionally, Downeast would follow the Best Management 

Practices, Conserving Pool-Breeding Amphibians in Residential and Commercial Developments 

in the Northeastern United States (Calhoun and Klemens 2002) for development of site-specific 

construction activity and restoration plans. Restoration of the areas would include replication of 

the vernal pool depression using the same soils excavated, as well as replanting as much of the 
4-65 4.4 – Wetlands and Vegetation

upland habitat buffer as possible while maintaining access to the right-of-way. The right-of-way 

width would be reduced to 55 feet through vernal pool areas. The duration of disturbance would 

be short-term, generally 24 to 48 hours. Sedimentation of the vernal pool areas would be 

minimized through use of erosion control devices. Maine DEP guidance for construction and 

mitigation for vernal pool disturbance includes:

• no disturbance within the vernal pool depression;

• maintain a minimum of 75 percent of the critical terrestrial habitat as unfragmented forest 

with at least a partly closed canopy of overstory trees to provide shade, deep litter, and 

woody debris;

• maintain or restore forest corridors connecting wetlands and SVPs;

• minimize forest floor disturbance; and 

• maintain native understory vegetation and downed woody debris. 

When considering the extended upland buffer from 250 to 500 feet from the pool, the relative 

amount of upland buffer affected by the project ranges between 0.22 and 9.68 percent, with an 

average of 4.84 percent project-wide. Effects within the area 250 feet to 500 feet from each pool 

and within the area 500 feet to 750 feet from each pool are shown in table 4.4.1.3-1. Maine 

DIFW has recommended to Maine DEP that if Downeast avoids and minimizes disturbance to 

less than 15 percent of the upland SVP habitat from 250 feet to 500 feet from the SVP, it has 

adequately minimized and avoided impacts on SVPs. 

Field investigations and NWI mapping determined that approximately 26.6 acres of wetland 

would be affected during construction of the pipeline, of which approximately 14.2 acres would 

be permanently affected during operation. Table 4.4.1.2-1 shows the acreage of wetland impact 

due to the construction and operation of the terminal, pipeline, storage yards, workspaces, and 

access roads. 

Wetlands offer several important functions, including water storage; flood attenuation; 

groundwater recharge and discharge; nutrient cycling; shoreline erosion control; water quality 

improvement by filtering out sediments and particles suspended in runoff water; breeding, 

nesting, and feeding habitat for a myriad of fish and wildlife species; habitat for numerous tree 

and plant species; and atmospheric maintenance by storing carbon instead of releasing it to the 

atmosphere as carbon dioxide. Some of the values of wetlands are providing sites for hunting, 

fishing, and trapping, and opportunities for recreation and aesthetic appreciation. Impacts from 

pipeline construction would be primarily temporary. Downeast would restore wetlands along the 

pipeline right-of-way to their original grade and hydrology; therefore, Downeast has not 

performed a detailed analysis of the functions and values of these wetlands. Downeast continues 

to consult with the COE and Maine DEP about project impacts on wetlands, mitigation 

measures, restoration, and post-construction monitoring, as described below. Downeast would 

provide a detailed assessment of wetland functions and values if required by the COE and/or 

Maine DEP. 

To avoid or minimize impacts on wetlands, Downeast proposes to cross several wetlands using 

HDD technology; however, conventional trenching methods would be used to cross the majority 

of wetlands. Construction activities that would affect wetlands include vegetation clearing, 

grading, soil or sediment disturbance, and alteration of the local hydrology. Operational 

activities that would affect wetlands include periodic vegetation maintenance.
4.4 – Wetlands and Vegetation 4-66

Vegetation clearing increases the volume and speed of precipitation that reaches the ground 

surface, thus increasing erosion potential. Lost vegetation also reduces the amount of water that 

is evapotranspired, resulting in higher water volumes in surface soils or in runoff streams. Most 

areas of cleared vegetation would be allowed to revegetate upon completion of construction; 

however, portions of the right-of-way would be periodically cut during operational maintenance. 

As shown on table 4.4.1.2-1, 27 acres of wetlands with forested area would be cleared during 

pipeline construction (including the right-of-way and associated work areas), of which 12.4 acres 

would be permanently converted to scrub-shrub/emergent wetland habitat during operations. 

Grading activity would likely alter the existing surface water movement and distribution. Soil 

disturbance could disrupt a wetland’s capacity to convey surface water flow, retain flood waters, 

and control erosion. Failure to properly segregate topsoil over the pipeline trench line could 

result in the mixing of topsoil with the subsoil, which could affect the success of postconstruction reestablishment and natural recruitment of native wetland vegetation. Rutting of 

soils from construction equipment could result in soil mixing, which could also affect success of 

post-construction restoration. Trenching during pipeline installation could penetrate impervious 

soil layers, drain perched water tables, and result in drier soil conditions that could inhibit the 

reestablishment of wetland vegetation. Disturbed soil in the trench could act as a conduit for 

subsurface water, effectively draining wetland water sources. Uncontrolled surface runoff from 

adjacent disturbed upland areas could transfer silt and sediment into off right-of-way wetlands. 

In order to minimize or avoid many of these potential adverse effects, Downeast would 

implement its Plan, Procedures, and Soil Erosion and Sediment Control Guidelines. These plans 

would include the following measures, among others, to minimize impact on wetlands: 

• Hazardous materials, chemicals, fuels, and lubricating oils would not be stored within a 

wetland or within 100 feet of a wetland boundary.

• Concrete coating activities would not be performed within 100 feet of a wetland, unless 

the location is an existing industrial site designated for such use.

• All extra workspaces would be at least 50 feet from the wetland boundary.

• Construction equipment operating within wetland boundaries would be limited to that 

equipment necessary for clearing, excavation, pipe installation, backfilling, and 

restoration activities. All nonessential equipment would use upland access roads to the 

maximum extent practicable.

• Equipment operating within saturated wetlands would be low-ground-weight equipment 

or would operate from prefabricated construction mats. 

• Temporary erosion and sediment control measures would be installed immediately after 

the initial disturbance of wetland soils and would be inspected and maintained regularly 

until final stabilization.

• Sediment controls would be installed across the construction right-of-way, as needed, 

within wetlands to contain trench spoil.

• Vegetation would be cut at ground level, leaving existing root systems in place to 

promote regrowth. Stumps would be removed from the trench line; stumps may be 

removed from the working side of the right-of-way if removal is required for safety 

concerns.
4-67 4.4 – Wetlands and Vegetation

• The uppermost 12 inches of wetland topsoil would be segregated from the underlying 

subsoil in areas disturbed by trenching, except in areas with standing water or saturated 

soils, or where no topsoil layer is evident.

• Vegetation maintenance would not be conducted over the full width of the permanent 

right-of-way in wetlands. Shrubs and trees with roots that could compromise the 

integrity of pipeline coating may be selectively removed within 15 feet of the pipeline.

• Monitoring the success of wetland revegetation annually until wetland revegetation is 

successful.

Downeast would use a 55- to 65-foot-wide construction right-of-way in all of the wetlands 

crossed by the sendout pipeline. Any temporary timber matting used for wetland crossings that 

remains in the wetlands after construction would be considered a quantifiable discharge of 

dredged or fill materials that is subject to COE jurisdiction, unless it is within the footprint of 

impact (the right-of-way) already calculated. Downeast has stated that timber matting for the 

proposed sendout pipeline would be contained within the approved limits of the construction 

right-of-way and removed when access to the wetland is no longer required. The wetland would 

be restored to original grade and character. 

The cleanup and final restoration phase is critical for mitigating long-term wetland impacts. 

During initial restoration, stored topsoil would be replaced over the trenchline, and wetland 

contours and drainage patterns would be restored approximately to original conditions. Surface 

rock and boulders removed from the trenchline during construction that are not replaced during 

backfill would be windrowed in upland areas or hauled off-site. Permanent slope breakers would 

be constructed to replace temporary erosion control devices in areas of sloped terrain. Once 

restoration of the substrate is complete, the right-of-way would be seeded with an annual 

ryegrass at a rate of 40 pounds per acre. This method, recommended by FERC and the NRCS 

for the M&NE Phase II and Phase IV filings, has been shown to effectively stabilize a site and 

serve as a nursery crop as the indigenous wetland vegetation reestablishes itself through natural 

succession. 

A majority of the impacts on wetlands resulting from construction and operation of the proposed 

sendout pipeline facilities would be temporary. The COE and Maine DEP would require 

Downeast to provide mitigation for the temporary impacts associated with the sendout pipeline 

installation. The COE indicated in its July 2009 comment letter on the draft EIS that its position 

on mitigation for temporary impacts on linear projects has changed. Because it is likely to take 

several years for the right-of-way to revegetate, during this interim period, there would be a 

temporal loss of wetland habitat, functions, and values. Therefore, the COE would require that

this temporary impact be addressed as part of the overall mitigation package. Downeast would 

conduct post-construction monitoring of all wetlands affected by construction to assess the 

condition of vegetation and the success of restoration until wetland revegetation is successful. 

Wetland revegetation shall be considered successful if the following criteria are met: the affected 

wetland satisfies the current federal definition for a wetland; vegetation is at least 80 percent of 

either the cover documented for the wetland prior to construction, or at least 80 percent of the 

cover in adjacent undisturbed wetland areas; if natural rather than active revegetation was used, 

the plant species composition is consistent with early successional wetland plant communities in 

that ecoregion; and invasive species and noxious weeds are absent, unless they are abundant in 

adjacent undisturbed wetland areas.
4.4 – Wetlands and Vegetation 4-68

Temporary staging areas along the sendout pipeline route would be primarily in upland habitat, 

with some unavoidable exceptions. The ATWS at MP 15.6 is one such exception; it must be 

within a wetland at a turn in the alignment to properly construct the bend in the pipeline and push 

it under the railroad bed. In order to minimize any temporary impacts on wetlands from the 

staging areas, Downeast would implement its Plan, Procedures, and Soil Erosion and Sediment 

Control Guidelines. In the event wetlands are encountered along those portions of the route that 

were not field delineated, Downeast would attempt to relocate the staging area out of wetlands.

All but one access road to be used for the construction of the sendout pipeline would consist of 

existing skidder roads previously constructed for timbering activities. Small, localized sections 

of these skidder roads may need to be widened; however, Downeast has stated that the access 

road improvements would not permanently impact any wetlands. Downeast has indicated that 

the existing skidder road between MP 5.2 and MP 6.2 already has affected wetland hydrology in 

the area by bifurcating the wetland complexes at MP 6.0 and MP 6.2. For this reason, the 

pipeline alignment has been sited north of the access road where there are sufficient wetland 

soils for restoration of wetland functions and values in the area.

We received comments from the COE in regards to Downeast’s wetland construction 

procedures. The COE recommends that all wetland flagging be done no more than one to two 

months prior to construction and then re-inspected to ensure flagging is still in place. Any 

wetlands near staging areas and access roads should be reflagged prior to construction to ensure 

avoidance. We note that our Procedures require that wetland flagging be visible during 

construction. The COE also expressed concern for the processing of stones in the right-of-way, 

noting that they have required them to be replaced in wetlands during previous pipeline 

construction projects in the region. In addition, the COE generally recommends a minimum of 

five years of post-construction monitoring for projects of this nature. We note that the COE may 

require these specific mitigation measures as conditions of its Section 404 authorization.

We conclude that with implementation of the measures proposed by Downeast for pipeline 

construction and right-of-way restoration, which includes measures to avoid and minimize 

wetland impacts, as well as compliance with applicable regulations, impacts on wetlands from 

construction and operation of the sendout pipeline would not be significant.

FERC has also received several comments on the potential impacts of the Downeast LNG 

Project on the Moosehorn NWR, including federal and state agencies, wildlife advocacy groups, 

and individual citizens. In response, Downeast has rerouted the pipeline such that it completely 

avoids the Moosehorn NWR. 

4.4.2 Vegetation 

4.4.2.1 Waterway for LNG Marine Traffic

Marine Vegetation

Marine and nearshore ecosystems support a variety of vegetation and photosynthesizing marine 

organisms such as phytoplankton, algae, and seagrasses. These organisms are primary producers 

and play an integral role in the health and integrity of this ecosystem. The majority of the 

intertidal zone is a mosaic of gravelly sand of varying grade sizes, fucoid-dominated ledge, and 

fairly homogenous pebbly gravel pavement that support little rooted vegetation. 
4-69 4.4 – Wetlands and Vegetation

Phytoplankton are microscopic photosynthesizing organisms that drift at or near the surface of 

the ocean. Phytoplankton exhibit seasonal density fluctuations, and regional studies show that 

phytoplankton peak in biomass annually in mid to late summer. Phytoplankton biomass growth 

is limited in the Project area by the interaction of light and water temperature, unlike most 

marine environments where nutrient availability limits phytoplankton growth. Section 4.5.2.2 of 

this EIS provides more detail on the function of phytoplankton in the zooplankton community. 

There would be no impact on marine vegetation from normal LNG vessel transit.

Terrestrial Vegetation

Island and shoreline vegetation along the waterway for LNG marine traffic is generally described 

as wooded with ledge rock outcrops. Dominant tree species include red spruce (Picea rubens), 

white spruce (Picea glauca), balsam fir (Abies balsamea), larch (Larix laricina), paper birch 

(Betula papyrifera), and red maple (Acer rubrum). Northern cedar (Thurja occidentalis) bogs 

are common. Normal LNG transit operations would have no adverse impact on these habitats. 

Unique or Invasive Plant Communities

Seagrass beds, including eelgrass (Zostera marina) and widgeongrass (Ruppia maritime), found 

along coastal Maine waters provide valuable ecological functions, such as sediment stabilization, 

nutrient production and transport, and wildlife habitat. These grasses have exhibited a reduction 

in distribution throughout much of their range, and are therefore of significant concern. 

Eelgrass is a keystone species in shallow estuarine and coastal marine habitats that provides high 

value tidal waterfowl and wading bird habitat. Eelgrass is federally protected under the CWA, 

which requires that eelgrass in certain areas that is destroyed by human activity be replaced or 

restored because of its role as essential fish habitat in the mid-Atlantic. Eelgrass beds are 

considered significant wildlife habitat by the Maine DIFW, with beds greater than 25 acres 

providing high value, and beds greater than or equal to 2.5 acres providing moderate value. 

4.4.2.2 LNG Terminal 

Marine Vegetation

Algal species found within the intertidal areas of the terminal site are primarily comprised of 

brown algae and rockweeds such as bladderwrack (Fuscus sp.) and knotted wrack (Ascophyllum 

spp.). Most of these algae species favor hard submerged structures and surfaces that are sparse 

in the terminal area. 

Construction activities that may affect marine vegetation include sediment disturbance due to 

piling installation and the anchoring of barges. These activities would cause vegetation mortality 

in the immediate area of the activity, and would also cause some sediments to be suspended in 

the water column. Suspended sediments may cause a temporary and localized reduction in 

phytoplankton productivity due to reduced light penetration. During the construction and 

operation of the terminal, marine water withdrawals for hydrostatic testing, fire suppression 

systems testing, and ship ballast and hoteling may also have short-term and localized impacts on 

phytoplankton. The phytoplankton within the area of the terminal are not unique and any 

mortality caused by temporary impacts would likely be replaced through tidal action from the

larger phytoplankton population within the Passamaquoddy Bay. Additional discussion of 

entrainment and impingement impacts on aquatic species is provided in section 4.5.2 of this EIS. 
4.4 – Wetlands and Vegetation 4-70

Temporary disturbance of bottom sediments may also release nutrients into the water column, 

which could cause an increase in phytoplankton production. The loss of light penetration due to 

increased turbidity and the potential release of increased nutrients due to disturbance are 

anticipated to be further dissipated through strong tidal exchange and tidal currents throughout 

the Passamaquoddy Bay. 

Development of the pier and berthing facility would result in the permanent loss of a small 

quantity of algae as a result of pile installation and shading; however, the footprint of the pilings 

is relatively small, and the height and orientation of the pier would create a very limited shadow 

effect. The pilings of the pier would provide increased surface areas suitable for supporting 

shade-tolerant algae species. Although the increased shading beneath the pier and berthing 

facilities may cause a transition of algae species from shade-intolerant species to shade-tolerant 

species, no significant net loss of algal biomass is anticipated.

Eelgrass mapping completed by the Maine DMR in 2010 identified eelgrass within Mill Cove 

that was not present during previous mapping efforts in the 1990s (see figure 4.4-2). The 

proposed pier would cross about 350 feet of mapped eelgrass. In this area eelgrass could be 

directly impacted by placement of piles, temporary disturbance of bottom sediments during pile 

installation, and from shading during Project operation. Eelgrass is federally protected under the 

CWA and permanent impacts may require replacement or restoration of an equal area of eelgrass 

habitat. The actual area of impact would need to be determined based on a site-specific survey to 

verify the presence and extent of eelgrass in the area of the proposed pier. Therefore, we 

recommend that:

• Prior to construction of the LNG terminal facilities, Downeast should conduct 

project-specific eelgrass mapping within Mill Cove to determine the presence and 

extent of eelgrass within areas that could be affected by the Project within Mill 

Cove. Results of the eelgrass mapping should be incorporated into compensatory 

mitigation planning, as needed. Downeast should file the results of the eelgrass 

mapping, and any resulting mitigation plan for potential impacts on eelgrass,

including records of consultation with Maine DMR and NOAA Fisheries regarding 

mitigation, with the Secretary for review and written approval by the Director of 

OEP.

Terrestrial Vegetation

The dominant ecosystem on the 80-acre terminal site consists of forested upland habitats 

exhibiting varying degrees of age and composition due to past anthropogenic disturbances such 

as timber harvesting and agriculture. Agricultural fields abandoned since the 1960s are present 

in the northern section of the site, and are still relatively open though they are transitioning into 

wooded uplands and forested/scrub-shrub habitats through the process of natural succession. 

Remnant fencing, household dumps, and apple trees (Malus sylvestris) are still present in this 

area. The remainder of the site consists of forested/scrub-shrub wetlands (wetland vegetation 

communities are discussed in section 4.4.1). 
Document Path: P:\Downeast-3253\Team Information\GIS\Spatial\MXD\20140227_Eel_Grass_Locations.mxd

Legend

Eel Grass (2010)*

Figure 4.4-2

0 250 500 1,000

Feet

Downeast LNG Project

LNG Terminal Plot Plan

and Approximate Eel Grass Locations

*Maine Office of GIS/Maine DMR

4-71
4.4 – Wetlands and Vegetation 4-72

Upland forests in the northeastern portion of the site are characterized as an Aspen-Birch 

Woodland Forest Complex (Gawler and Cutko 2004). Deciduous tree species are prevalent, 

including paper birch, red maple, big-toothed aspen (Populus grandidentata), and choke cherry 

(Prunus virginiana). The shrub layer is dominated by such species as beaked hazelnut (Corylus 

cornuta), alternate-leaved dogwood (Cornus alterniflora), yellow birch (Betula alleghaniensis), 

red spruce, and choke cherry. The herbaceous layer is dominated by bunchberry (Cornus 

canadensis), wild sarsaparilla (Aralia nudicaulis), common speedwell (Veronica officinalis), 

lowbush blueberry (Vaccinium angustifolium), trailing arbutus (Epigaea repens), hawkweed 

(Hieracium sp.), and interrupted fern (Osmunda claytoniana). 

Upland forests in the southeastern portion of the terminal site are characterized as spruce fir 

forest (Gawler and Cutko 2004). Dominant tree species include white spruce and red spruce. 

The shrub layer is dominated by such species as balsam fir (Abies balsamea), green alder (Alnus 

viridis), red spruce, paper birch, and yellow birch. A sparse herbaceous layer is present, 

dominated by such vegetation as Canada mayflower (Maianthemum canadense), twinflower 

(Linnaea borealis), wild sarsaparilla, bunchberry, and spruce and balsam fir seedlings. 

Approximately 47 acres of the 80-acre LNG terminal site would be developed, including the 

aforementioned 9 acres of wetland and 38 acres of forest; an additional 8 acres of grassland 

would be temporarily disturbed during construction for use as ATWS. Within the terminal, 

vegetation would be cleared and mulched on-site and used as a temporary erosion control filter 

berm. Any remaining wood products would be either hauled off-site and sold as mulch or 

biomass, or placed in fill areas on the site where structural soil support is not needed. Downeast 

proposed to leave the remaining portion of the site, approximately 33 acres, undeveloped as a 

buffer. However, Downeast did not account for the forested areas in its hazard analyses. 

Therefore, in section 4.12.5, we have recommended that Downeast certify that all trees would be 

removed from the area between the vapor fences and the shoreline or demonstrate that the 

spacing of the trees, and any vegetation management plan, would prevent congested areas that 

could produce offsite overpressures above 1 psi. Given that recommendation, there is a 

possibility that the forested area visible in this figure would not be present after construction.

Three off-site staging areas would be used during construction, temporarily disturbing 

approximately 8.0 acres of developed land and grassland. These sites would be in previously 

disturbed areas and would not require substantial clearing. Once construction is completed, 

these areas would be revegetated. Impact on terrestrial vegetation from construction and 

operation of the LNG terminal would include permanent conversion of 47 acres of vegetation to 

a developed site.

Unique or Invasive Plant Communities

Correspondence with Maine Natural Areas Program (Maine NAP 2006) indicates that no rare 

plant species or communities are present at the site of the proposed LNG terminal. Field 

investigation conducted by Downeast at the proposed LNG terminal site also indicated that no 

invasive plant species are present. 

Eelgrass mapping completed by Maine DMR in 2010 identified eelgrass within Mill Cove that 

was not present during previous mapping efforts in the 1990s. The proposed pier would cross 

about 350 feet of mapped eelgrass. We have recommended that Downeast conduct project 
4-73 4.4 – Wetlands and Vegetation

specific mapping within Mill Cove and determine potential presence and extent of eelgrass and 

need for mitigation for potential impacts (see section 4.4.2.2).

4.4.2.3 Sendout Pipeline

The sendout pipeline 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 sendout pipeline include early successional forests and maintained 

open areas such as open fields, residential, and agricultural land. In order to minimize impacts 

on vegetation communities, Downeast would implement its Plan, Procedures, and Soil Erosion 

and Sediment Control Guidelines. 

Mature Forests

The spruce-fir forest generally exhibits dense, closed canopies with sparse understory vegetation. 

Tree species commonly found include red spruce, balsam fir, northern white cedar, red maple, 

grey birch, paper birch, yellow birch, quaking aspen, big-toothed aspen, American beech, eastern 

white pine, white spruce, and eastern hemlock. In patches of less dense stands, shrub species 

consist primarily of striped maple (Acer pensylvanicum), mountain maple (Acer spicata), beaked 

hazelnut, mountain holly, low-bush blueberry, speckled alder, meadowsweet, winterberry, and 

red raspberry. Herbaceous plants found in the open canopy areas include Canada mayflower, 

wild sarsasparilla, bunchberry, wintergreen, starflower, sphagnum mosses (Sphagnum spp.), 

bracken fern (Pteridium aquilinum), and wood fern (Dryopteris spp.).

Spruce-northern hardwood stands occur as infrequent patches along the sendout pipeline route 

and are dominated by red spruce, sugar maple, red maple, American beech, and birch (Betuala 

spp.). Subdominate species include balsam fir and white pine. The sapling/shrub layer in this 

community is fairly well developed and composed of thick stands of striped maple and canopy 

species saplings. Other shrub associates include mountain maple, hobblebush (Viburnum 

lantanoides), beaked hazelnut, and mountain holly. Speckled alder, meadowsweet, and 

winterberry occur in wetter sites. The herbaceous layer is typically comprised of wood fern, tree 

seedlings, wild sarsaparilla, bristly sarsaparilla (Aralia hispida), bunchberry, and common woodsorrel (Oxalis montana).

White pine-mixed hardwood forest is located along the northwestern portion of the pipeline 

route. This transition forest type includes white pine, balsam fir, red and sugar maple, white ash 

(Fraxinus americanus), birch, American beech, black cherry (Prunus serotina), and eastern 

hemlock. Common understory shrubs include tree saplings, low-bush blueberry, striped maple, 

and beaked hazelnut. Canada mayflower tends to dominate the herbaceous layer along with 

starflower, bunchberry, and tree seedlings.

Early Successional Forest

Several areas along the proposed sendout pipeline route have been cleared during commercial 

forestry activity. These communities are variable in their structure and composition based on the 

length of time following timber harvest. Early successional forests are dominated by pioneering 

tree species such as birch species, aspen species, and red maple, which would eventually be 

replaced through natural succession by spruce-fir forests typical for the region.
4.4 – Wetlands and Vegetation 4-74

Maintained Open Areas

Typical plant species found in the open areas along the proposed right-of-way include introduced 

species such as timothy (Phleum pretense), clovers (Trifolium spp.), and fescues (Festuca spp.). 

Construction and Operational Impacts

Construction of the sendout pipeline would affect an estimated 175.4 acres of forest, of which 

approximately 112.2 acres would be permanently converted into a non-forested vegetation 

community. The construction of the sendout pipeline also would affect an estimated 31.3 acres 

of open land (which includes developed land, agricultural land, and grassland), of which 

approximately 18.9 acres would be permanently maintained as right-of-way. Widening and 

improvement of access roads would permanently impact approximately 10.0 acres of upland 

habitat, of which 0.5 acre is forested and 9.5 acres are developed. Staging areas would 

temporarily impact approximately 13.5 acres of forest and 5.2 acres of open habitats (2.5 acres of 

developed, 1.1 acres of herbaceous, and 1.6 acres of agricultural lands). Project impacts on 

vegetative communities are detailed in table 4.7.1-1 of section 4.7 in this EIS. 

The primary impact on vegetation would be the temporary and permanent clearing of vegetation 

along the pipeline right-of-way and access roads. Through upland areas, Downeast would create 

a 75-foot-wide construction right-of-way and maintain a 50-foot-wide right-of-way during 

operations. This would provide the minimum workspace necessary to permit staging, spoil 

stockpiling, assembly of the pipeline, and other activities necessary to building the pipeline.

Approximately 0.3 acre of recently harvested spruce-fir forest (plus 0.2 acre of right-of-way) 

would be cleared to construct one valve station for the sendout pipeline route. The effects would 

be permanent within the footprint of the station (total fenced area of 0.5 acre). One half of an 

acre would be permanently maintained for routine operations and maintenance.

All vegetation removal would be performed by hand or mechanical cutting. In areas of 

temporary impacts, rootstock and tree stumps would be left in place to encourage soil stability 

and natural revegetation. Discarded vegetation or other waste would be removed from the 

sendout pipeline right-of-way and properly disposed of in accordance with applicable permit 

conditions. Pre-established erosion controls would be installed immediately upon vegetation 

clearance and soil disturbance. 

Downeast has stated that it would implement its Plan and Soil Erosion and Sediment Control 

Guidelines to ensure successful revegetation of the right-of-way. Upon completion of pipe 

installation, pre-existing grade would be restored and topsoil replaced. Within six working days 

of substrate restoration, the disturbed wetland areas of the right-of-way would be seeded with an 

annual ryegrass at a rate of 40 pounds per acre. This method, recommended by FERC and the 

NRCS for the M&NE Phase II and Phase IV filings, has been shown to effectively stabilize a site 

and serve as a nursery crop as the indigenous wetland vegetation reestablishes itself through 

natural succession. The permanent right-of-way seed mixture specified in table 6 of M&NE’s 

Guidelines would be applied to most upland areas of the right-of-way. A permanent right-ofway would be maintained to permit access for routine on-site corridor patrols and emergency 

repairs, and to facilitate visibility during aerial patrols. Vegetation removal within the 50-footwide permanent right-of-way would be conducted every three to five years. A 10-foot-wide area 

directly over the pipeline would be mowed on an annual basis. There are no plans to utilize 

herbicides for right-of-way maintenance.
4-75 4.4 – Wetlands and Vegetation

Varied effects are associated with the thinning and removal of vegetation, as this alters the 

structure and function of the vegetated community and associated wildlife habitats. The removal 

of mature forest vegetation could have prolonged effects, as forested vegetative communities are 

typically complex and take a longer period of time to regenerate to pre-existing conditions 

following a disturbance. Habitat characteristics may be lost or transitioned into a different 

habitat type, such as the transition of forested land into scrub-shrub and graminoid vegetated 

communities. The permanent right-of-way would fragment intact forest stands. To mitigate 

forest fragmentation, Downeast has collocated the pipeline, to the most practical extent possible, 

along existing rights-of-way. Clearing of vegetation along the right-of-way may also increase 

the impacts of erosion and solar heat as the loss of deep rooted vegetation would destabilize soils 

and the loss of shade would increase exposure to the sun. Vegetative disturbance may also 

increase the exposure of wind to some trees and increase the occurrence of blow downs. In 

addition, many invasive plant species are pioneer species adapt to establishing immediately 

following a disturbance. Forest disturbance may also produce positive effects, such as 

diversifying available habitats, increasing species diversity, and encouraging the growth of shade 

intolerant plant species. 

All construction work areas would be monitored by Downeast for revegetation and restoration 

success. Inspections would be conducted at each of the following periods:

1. upon completion of 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.

FERC representatives would conduct restoration inspections in the spring following construction 

to verify revegetation success, as well as follow-up inspections as appropriate. We believe that 

with the implementation of Downeast’s proposed measures for pipeline construction and rightof-way restoration, construction and operation of the sendout pipeline would not significantly 

impact vegetation.

Unique or Invasive Plant Communities

Correspondence with Maine NAP indicates that rare and unique plant communities are present 

within 4.0 miles of the proposed right-of-way, but would not be affected by construction. These 

communities are discussed further in section 4.6 of this EIS. Two invasive plant species were 

documented in several places in the pipeline right-of-way during field surveys. Purple 

loosestrife (Lythrum salicaria) was documented in six herbaceous wetlands delineated in the 

pipeline right-of-way segment that abuts the existing EMEC powerline corridor. Alderbuckthorn (Frangula alnus) was identified in and adjacent to the right-of-way segment that 

would parallel Icehouse Road. 

Under Executive Order 13112, federal agencies shall not authorize, fund, or carry out actions 

that are likely to cause or promote the introduction or spread of invasive species in the United 

States or elsewhere unless the agency has determined and made public its determination that the 

benefits of such actions clearly outweigh the potential harm caused by invasive species. 

Additionally, the agency must ensure all feasible and prudent measures to minimize risk of harm 

be taken in conjunction with the actions. 

During installation, operation, and maintenance of the sendout pipeline, Downeast would 

primarily employ measures in the M&NE Soil Erosion and Sediment Control Guidelines to 
4.4 – Wetlands and Vegetation 4-76

prevent introducing new invasive species and avoid encouraging the spread of undesirable 

species already present. The M&NE Soil Erosion and Sediment Control Guidelines provide 

permanent seeding requirements that would facilitate quick revegetation to prevent unwanted 

species from becoming established. Following construction and initial revegetation, a 

monitoring plan would be employed to ensure that invasive species have not out-competed 

desirable vegetation during the re-establishment phase. The following strategy of integrated 

invasive plant management would be incorporated into construction procedures at locations with 

known invasive plant occurrences.

During construction:

• Remove invasive plants that could be potentially spread by construction equipment or 

workers. Along access roads, invasive plants would be identified and controlled to avoid 

introducing them into weed-free sites.

• Obvious vegetative material would be removed from construction equipment before 

allowing it to enter a weed-free area.

• Gravel and fill would come from weed-free sources to avoid introducing weedy 

vegetation to construction sites.

• Vegetation and ground disturbance activities would be confined to that which is deemed 

necessary for pipeline installation.

• Only certified weed-free straw, mulch, fiber rolls, and sediment logs would be used for 

erosion and sediment control.

• Workers would be trained to identify invasive plants, informed of the importance of 

infestation prevention, and required to employ measures to minimize weed invasion.

• Along the pipeline right-of-way, individual plants or small patches would be removed to 

control establishment.

During restoration:

• Any soil amendments (if any) and mulches would be obtained from weed-free sources.

• Certified weed-free seed would be used.

• Seeding and planting operations and maintenance would be conducted in a manner to 

ensure vigorous growth of desirable vegetation and discourage weeds.

• Bare ground would be seeded as quickly as possible.

• Seeded sites would be monitored for weed infestation.

• Identified weeds at monitored sites would be treated in the first full growing season.

• Mulching can limit the amount of unwanted seed sources reaching bare soil.

After initial revegetation steps have been achieved, the sendout pipeline right-of-way would be 

monitored and undesirable vegetation would be treated for the life of the project. We believe 

that Downeast’s implementation of its proposed integrated invasive plant management during 

construction, and its proposed monitoring following construction, would be adequate measures 

to control the spread of invasive plant communities and would comply with the intent of 

Executive Order 13112.
4-77 4.5 – Wildlife and Aquatic Resources

4.5 WILDLIFE AND AQUATIC RESOURCES

This section describes the existing terrestrial and aquatic wildlife, and fisheries that would be 

affected by the proposed Downeast LNG Project. Section 4.5.1 describes existing resources, 

impacts, and mitigations for terrestrial wildlife and their habitats, while section 4.5.2 describes 

existing resources, impacts and mitigations for aquatic wildlife along the proposed LNG marine 

traffic route, LNG terminal, and sendout pipeline. Species that are protected by federal or state 

regulations are discussed in section 4.6. 

4.5.1 Terrestrial Wildlife 

4.5.1.1 Waterway for LNG Marine Traffic

LNG vessels coming to the Downeast LNG Terminal could potentially take two transit routes 

from the Gulf of Maine to the Pilot Station. One is east of Grand Manan Island and follows the 

VTS indicated on navigation charts (see appendix F, figures F-1 to F-10). The other route 

generally would follow the coast of Maine west of Grand Manan Island. Once at the Pilot 

Station, LNG vessels would travel through Head Harbour Passage, Western Passage, and 

Passamaquoddy Bay, ending in Mill Cove near the entrance to the St. Croix River.

Around Grand Manan Island, the tides range from 19 to 22 feet. The tide ranges progressively 

increase with latitude towards the Bay of Fundy. Typical terrestrial fauna include seabirds, 

shorebirds, gulls, and sea ducks. Marine fauna are discussed in section 4.5.2.

Coastal and Marine Avifauna

Many avian species that occur in Maine are migratory; these species typically rest and feed in 

areas in or near the proposed waterway for LNG marine traffic, among other areas in Maine, 

before beginning or continuing the fall migration. Migratory species are protected by the 

Migratory Bird Treaty Act (MBTA) of 1918, and include all common songbirds, waterfowl, 

shorebirds, hawks, owls, eagles, ravens, crows, native doves and pigeons, swifts, martins, 

swallows and others, in addition to their body parts (feathers, plumes, etc.), nests, and eggs.13

A “take” under the MBTA is defined as “to pursue, hunt, shoot, wound, kill, trap, capture, or 

collect, or any attempt to carry out these activities.” 

Marine avifauna with potential to occur near the proposed LNG marine traffic route includes 

seabirds, shorebirds, gulls, and sea ducks. The Western Passage and the area just north of 

Campobello Island are important habitats for marine birds. Several species of arctic birds 

migrate to the Bay of Fundy, including the area north of Campobello Island in summer. Species 

that use these areas include northern gannets (Morus bassanus), Atlantic puffins (Fratercula 

arctica), common murres (Uria aalge), common terns (Sterna hirundo), Atlantic terns (Sterna 

paradisaea), black-legged kittiwakes (Rissa tridactyla) and razorbills (Alca torda) (SENES 

2007). Shortly before high tide in summer, large numbers of gulls, particularly Bonaparte’s gulls 

(Larus philadelphia), are attracted to an upwelling site that occurs within the LNG marine traffic 

route between Eastport and Deer Island (see appendix F, figure F-15).

 13 A complete list of species protected by the MBTA is found at 50 CFR 10.13.
4.5 – Wildlife and Aquatic Resources 4-78

The Quoddy Region, the area within a line drawn from Point Lepreau on the north shore of the 

Bay of Fundy, south to the Grand Manan archipelago, and west to the Maine shore, is an area of 

intense biological activity (Harvey, J. 2004). The Quoddy Region is used as a wintering ground 

for many seabirds (e.g., dovekies, shearwaters, and Wilson’s storm petrel) and waterfowl. 

Species such as scoters, common eiders (Somateria mollissima), and American black ducks 

(Anas rubripes) have been documented from Passamaquoddy Bay and the St. Croix Estuary 

(SENES 2007). Large rafts of marine birds could potentially occur at any time of the year in the 

Quoddy Region depending on the species.

The SENES Report (2007) states that 300 species of birds, many of which are migratory, inhabit 

the Canadian portion of the Quoddy Region during some part of the year, which suggests the 

global importance of this region. It notes that 100,000 to 1,000,000 birds travel through the Bay 

of Fundy during a single year. The study area is important for raptors such as the bald eagle, 

osprey, and peregrine falcon. The Wolf Islands, located east of Campobello Island, were 

identified as an important wintering ground for the harlequin duck with approximately 50 birds; 

White Head Island also accounts for another 25 birds. Grand Manan was identified as being 

renowned for its seabird populations. The colonies in Grand Manan’s Long Island Bay include 

double-crested cormorant, common eider, herring gull, and various sandpipers and terns. The 

colonies of common eider in 2002 on Grand Manan were estimated at 2,763 to 5,237 pairs. 

Great blue herons were also noted to occur on Long Island. 

The SENES Report (2007) notes that more than 9,300 acres of intertidal mud and sand flats 

occur in the inner Quoddy Region; these areas support diverse primary food types that are used 

by shorebirds, wading birds, and waterfowl. Mudflats of the upper Bay of Fundy serve as 

feeding and gathering grounds for much of the North American shorebird population during 

annual migrations. More than 278 acres of salt marsh occur in the inner Quoddy Region; these 

areas support nesting and migrant bird populations. 

Ten major islands and a number of ledges that remain exposed at high tide are found near the 

waterway for LNG marine traffic; these islands provide nesting, foraging, and loafing habitats 

for nesting and migratory birds. Of these islands, Hardwood Island has the largest colony of 

great blue herons in the Bay of Fundy (47 nests in 1981) and is an important stopover point for 

migratory birds in the spring and fall. Dicks Island has harbored up to 400 pairs of eider. 

Islands in the area provide nesting sites for the bald eagle and osprey (SENES 2007). 

Seabirds

In Chapter 335, Maine DEP defines seabirds as those birds that include colonial nesting 

waterbirds such as petrals, cormorants, terns, alcids, and eider. Maine DEP has defined the 

period from April 15 to August 31 as the nesting season on Maine nesting islands. Seabirds are 

likely to occur within the LNG waterway for marine traffic during this time, especially in an area 

of upwelling between Eastport and Deer Island. 

Maine DIFW has identified significant wildlife habitats used by migratory birds for feeding, 

breeding, and roosting activities. Significant wildlife habitats are regulated under the NRPA 

Chapter 335 (38 MRSA § 480-B [10]), which is administered by the Maine DEP. Significant 

wildlife habitats occur within and near the waterway for LNG marine traffic, as depicted in 

Appendix F, figures F-14 and F-15. These include inland waterfowl and wading bird habitat 
4-79 4.5 – Wildlife and Aquatic Resources

(IWWH), tidal waterfowl and wading bird habitat (TWWH), shorebird nesting, feeding and 

staging areas (Shorebird Areas), and seabird nesting islands. 

Inland Waterfowl and Wading Bird Habitat

The IWWH is ranked as high or moderate value based on observed species use, dominant 

wetland type, and the diversity, size, and interspersion of wetland types. In general, the state’s 

mapped IWWH includes the wetland complex and a 250-foot upland habitat buffer zone. 

IWWHs that have been mapped, but not evaluated, are classified as unknown or indeterminate. 

Protection is afforded to those habitats ranking moderate or high value. Two IWWHs occur near 

the LNG transit route immediately south of Gleason Cove in the Town of Perry. 

Tidal Waterfowl and Wading Bird Habitat

Maine DIFW considers four distinct TWWH types as high or moderate value based on aerial 

extent, including aquatic beds, reefs, emergent wetlands, and mudflats. Along the LNG transit 

route from Robbinston to Eastport TWWH occurs in most coastal areas. 

Shorebird Areas

Under Chapter 335, Maine DEP defines shorebirds to include members of the families 

Scolopacidae, Charadriidae, and Haematopodidae (e.g., sandpipers and plovers). High or 

moderate value Shorebird Areas and the 250-foot buffer zone surrounding those areas are 

considered to be Shorebird Areas. These protected areas are used for feeding, roosting, or 

staging prior to migration. Feeding and staging areas provide foods that enable shorebirds to 

develop fat reserves that are essential for long-distance migration. Staging habitats include those 

sites with suitable resting areas for shorebirds during high tide when food resources are 

unavailable. Generally, Shorebird Areas are coves that experience highly variable tidal cycles 

and that tend to be quiet, protected sites for feeding and roosting. 

A total of six Shorebird Areas occur along the waterway for LNG marine traffic. These areas are 

located in Mill Cove, Gleason Cove, Pleasant Point, Carrying Place Cove, Carlow Island, and 

Broad Cove, as depicted in appendix F, figures F-14 and F-15. With the exception of Mill Cove, 

which provides only shorebird feeding habitat, all other Shorebird Areas provide both feeding 

and roosting habitats. 

The SENES Report (2007) identifies 25 environmentally significant areas near the waterway for 

LNG marine traffic in Canada. One area occurs at the northern edge of Campobello Island, and 

is significant for vertebrate fauna. A second environmentally significant area occurs on Indian 

Island, located northeast of Eastport, and is significant for vertebrate fauna. Other 

environmentally significant areas occur near St. Andrews (significant for fisheries), near the 

West Isles, east of Deer Island (significant for fisheries and vertebrate fauna), and in Roosevelt 

Campobello International Park near Liberty Point, which are significant for vascular plants and 

invertebrate fauna.

Impacts on Coastal and Marine Avifauna

Coastal and marine avifauna may be indirectly or directly affected by disturbance from LNG 

marine vessel traffic. Birds are much less mobile during nesting and many marine species nest 

in colonies on offshore and inshore islands where they are vulnerable to disturbance (e.g., 
4.5 – Wildlife and Aquatic Resources 4-80

harassment). Vessels transporting LNG to the proposed terminal would pass by a single known 

colonial nesting area, located 2 miles from the vessel route on Spectacle Island (see figure F-15 

of Appendix F) and separated from the LNG transit route by Moose Island. Seabirds nesting on 

Spectacle Island are unlikely to be affected by normal passage of LNG vessels. Because known 

sea and shorebird nesting occurrence near the waterway for LNG marine traffic is low, it is 

anticipated that proposed LNG marine vessel operations would not adversely affect these 

species. 

Operation of the proposed project may directly affect birds due to increased vessel traffic in 

Passamaquoddy Bay. Birds are known to collide with a variety of man-made structures 

subsequently causing disorientation, injury, and often death. Bird strikes with marine vessels are 

not well reported; it is hypothesized that these events are infrequent based on information in 

Hebert and Reese (1995) and Trapp (1998). One incident (Bagg 1965, as cited in Hebert et al., 

1995) documented that approximately 150 to 175 birds landed on the deck of a vessel off the 

New Jersey coast in April of 1965. Mortality was limited to 23 Cape May warblers (Dendroica 

tigrina), which were assumed to have collided with the vessel’s infrastructure. Exhaustion 

consequential to low energy reserves during long migratory flights can be a contributing factor to 

bird collisions with man-made structures. Birds flying during the day near the water’s surface 

while feeding are expected to be able to avoid an LNG vessel that is docked or traveling in the 

waterway. However, birds that migrate at night may collide with a vessel during periods of low 

visibility. Nonetheless, bird collisions with LNG vessels are predicted to be low considering the 

existing anthropogenic factors in the landscape that are expected to create hazards for birds. The 

long-term effect of bird and vessel collisions is not predicted to have measurable consequences 

to bird populations in the project area. 

The potential for shoreline erosion and subsequent impact on avian habitats that occur along the 

waterway for LNG marine traffic is low because, although speed of the vessel would be at the 

discretion of the ship's Captain, attending pilot, and any operational parameters established by 

the Coast Guard Captain of the Port, vessels would typically travel at speeds of 10 knots or less. 

LNG vessel traffic is not expected to have adverse impacts on coastal or marine avifauna or its 

habitat, because it would not contribute to adverse degradation or disturbance to bird habitat or 

bird populations during normal operation. 

4.5.1.2 LNG Terminal 

The terminal site is located on approximately 80 acres between U.S. Route 1 and 

Passamaquoddy Bay, with its pier extending into the Passamaquoddy Bay in Robbinston, Maine. 

Wildlife species that use habitats associated with the proposed terminal include coastal wildlife, 

such as shorebirds and marine mammals, and terrestrial wildlife associated with the onshore 

terminal facilities. Marine mammals are discussed in section 4.5.2 of this EIS.

Coastal Avifauna

Coastal avifauna depend on wetlands and shoreline habitats for feeding, refuge, and loafing 

habitats. Field investigations were conducted in accordance with Maine DIFW protocols for 

shorebird presence along shoreline areas in July and September of 2006. Species with high 

frequency of occurrence included greater yellowlegs (Tringa melanoleuca) and lesser yellowlegs 

(Tringa flavipes); however, species observed in the greatest number were lesser yellowlegs and 

semipalmated plover (Charadrius semipalmatus). These species observations were consistent 
4-81 4.5 – Wildlife and Aquatic Resources

with data collected by Maine DIFW over a 6-year period from 1991 to 1997 (Maine DIFW 

2006a). Alcids, such as razorbills and puffins, are associated with isolated rocky islands in the 

Gulf of Maine, and are not likely to occur near the shores of Mill Cove. Table 4.5.1.2-1 lists 

birds that were observed during the field surveys of Mill Cove conducted by Downeast in 2006 

and 2007. Other birds such as gulls and cormorants were observed roosting on a weir in Mill 

Cove. Birds were observed foraging in the middle of Mill Cove, in the outlet to the bay, and 

around the standing water in the mudflats. Shorebird feeding and staging were observed in the 

northern portion of Mill Cove, more than 1,500 feet from the proposed pier. Approximately 

9.6 acres of coastal avian habitats would be affected by the operation of the terminal and pier 

facility (table 4.5.1.2-2). 

TABLE 4.5.1.2-1

Summary of Mill Cove Shorebird Observations

Species

2006 2007

July 

(n=4 obs)

Aug 

(n=4 obs)

Sept 

(n=2 obs)

Total 

2006

July 

(n=2 obs)

Aug 

(n=6 obs)

Total 

2007

Black-bellied Plover 0 0 0 0 0 0 0

Semipalmated Plover 23 63 0 86 0 54 54

Greater Yellowlegs 16 10 18 44 2 20 22

Lesser Yellowlegs 81 43 6 130 15 58 73

Solitary Sandpiper 0 0 0 0 0 1 1

Willet 0 0 0 0 0 1 1

Spotted Sandpiper 0 0 0 0 1 14 15

Sanderling 0 2 0 2 2 1 3

Semipalmated Sandpiper 19 17 0 36 7 26 33

Least Sandpiper 14 5 0 19 4 26 30

Western Sandpiper 8 7 0 15 0 0 0

White-rumped Sandpiper 0 0 0 0 0 2 2

Peep spp. 0 1 0 1 0 27 27

Short-billed Dowitcher 11 0 0 11 0 0 0

Total Individuals 172 148 24 344 31 230 261

The common tern (Sterna hirundo), which is associated with large expanses of open water in the 

Downeast LNG Project area, is listed as a FWS bird of conservation concern (FWS 2002). This 

species was observed flying over Passamaquoddy Bay during shorebird surveys at the site.

TABLE 4.5.1.2-2

Acres of Impact on Terrestrial Wildlife Habitats by Construction and Operation of the LNG Terminal

Facility

Forest Land Submerged 

Land Wetlands Agricultural Grassland Total

Con. Op. Con. Op. Con. Op. Con. Op. Con. Op. Con. Op.

LNG Terminal a/ 38.0 38.0 0 0 9.0 9.0 0 0 0 0 47.0 47.0

Off-site laydown areas 0 0 0 0 0 0 0 0 8.0 0 8.0 0.0

Pier trestle and 

unloading platform

0 0 3.6 3.6 9.6 9.6 0 0 0 0 13.2 13.2

Total LNG Terminal 38.0 38.0 3.6 3.6 18.6 18.6 0 0 8.0 0 68.2 60.2

a/ Includes the pig launching facility inside the terminal property.
4.5 – Wildlife and Aquatic Resources 4-82

Night-time construction of the proposed terminal and pier would require sufficient lighting for 

both land-based and barge-based methods. Lighting during nighttime construction would create 

an atypical environment for nocturnal birds, possibly making the area surrounding the terminal 

and pier unsuitable for certain activities such as hiding or locating prey. Operation of the 

proposed terminal would continue to have long-term night-lighting effects, but to a less intense 

level than that for any nighttime construction. To mitigate impacts on nocturnal species, 

Downeast would strategically locate light fixtures to minimize light pollution beyond the 

terminal area. Fixtures would be avoided on top of tall structures. Down-directed lighting 

would be used to reduce night-lighting effects to animals in the terminal area. Fixtures would 

point down and at angles to minimize glare beyond the terminal area. Perimeter lighting would 

be kept as low as possible to allow security camera operation without creating a nuisance to 

neighbors. High-intensity discharge (HID) fixtures would be used where possible. Additionally, 

low-glare yellow light bulbs versus white-glare bulbs would be used where feasible. To reduce 

lighting effects, Downeast would limit exterior lighting at the terminal and its associated pier to 

those levels mandated by the Coast Guard and necessary for maintaining human health and safety.

The electrical system would be designed in accordance with the National Electrical Code (NEC) 

and located to satisfy criteria established by the Coast Guard, the FERC, Maine regulatory 

authorities, federal and state occupational safety regulations, and Downeast LNG safety policies. 

However, lighting requirements are contingent upon Coast Guard review of safety lighting upon 

completion of construction. Using lighting methods that Downeast has proposed, the effects of 

lighting in the LNG terminal facilities are unlikely to significantly affect shorebirds and 

terrestrial species. Section 4.5.2 of this EIS discusses the impacts of LNG vessel water 

withdrawals and discharges during operation of the LNG terminal. 

Significant Wildlife Habitat

The proposed pier would traverse an 800-foot section of TWWH and its 250-foot buffer zone 

that is regulated by Maine DEP, Bureau of Land and Water Quality. The pier would also 

traverse a 250-foot section of state-designated Shorebird Area that extends across the mouth of 

Mill Cove to approximately 0.5 mile south of the proposed terminal. The Mill Cove Shorebird 

Area includes a 75-foot protective buffer zone. These significant wildlife habitats total 0.4 and 

0.6 acres, respectively, as shown in figures M-1 and M-2 of appendix M.

Waterfowl, wading birds, and shorebirds are expected to avoid this portion of Mill Cove while 

construction activities occur. Areas shaded by the pier would be unavailable to feeding 

shorebirds due to behavioral avoidance of overhead structures. The berthing facility would be 

located in deeper waters beyond these habitats; therefore, operational effects would be limited to 

noise, night safety lighting, and shading, which act to reduce both the quantity and quality of 

available shorebird habitat in Mill Cove. 

Maine DIFW indicated specific concerns regarding effects from construction of the proposed 

project on shorebirds and shorebird habitat. In a letter dated April 2, 2007, Maine DIFW noted 

that Downeast’s 2006 and 2007 shorebird surveys found most shorebirds using the north end of 

Mill Cove near the culvert at U.S. Route 1. In previous years, Maine DIFW observed shorebirds 

using the entire shore of the project area, from Mill Cove south to the next minor cove, as 

indicated on Maine DEP maps. Maine DIFW noted that construction of the pier would result in 

displacement of feeding shorebirds during migration. Construction over water would be more 
4-83 4.5 – Wildlife and Aquatic Resources

disruptive to shorebirds than construction over land. To prevent unreasonable disturbance to 

shorebirds, Downeast proposed its draft Migratory Shorebird Adaptive Management Plan as part 

of its Shorebird Mitigation Plan, described further below. This plan indicates that Downeast 

would not construct its pier during the high use period of significant shorebird activity and 

describes how it would determine the period of high use. Exact time frames for work exclusion 

are as yet undetermined but would be based on baseline conditions. 

Maine DIFW also expressed concerns regarding effects from operation of the proposed project in 

its letter dated April 2, 2007. Lighting and noise produced during normal terminal operations 

have the potential to make Mill Cove permanently unavailable as a viable feeding habitat to 

shorebirds. This possibility is exacerbated by both the length of time necessary to construct the 

terminal facilities, as well as the anthropogenic alteration to Mill Cove that effectively reduces 

the openness of habitat available for undisturbed feeding, and may elicit habitat avoidance 

responses by some shorebirds. 

Discussions between Downeast and the Maine DIFW in the summer of 2007 and the Maine 

DIFW’s testimony before the Maine Board of Environmental Protection (Maine BEP) in July 

2007 at public hearings revealed that Downeast and Maine DIFW disagree about the area of 

significant wildlife habitats that are likely to be affected by operation of the proposed Project. 

During these discussions, Maine DIFW indicated that the presence of the LNG terminal, pier, 

and all associated operation activities could affect as much as 9.6 acres by operation of the 

proposed project. A number of published peer-reviewed articles on shorebird and other water 

birds and the effects of disturbance were reviewed by Downeast (Pfister et al. 1992; Rodgers and 

Smith 1997; Gill et al. 2001; West et al. 2002; Burger et al. 2004) to develop opinions on the 

effects of the construction and operation of the Downeast LNG import terminal on shorebirds. 

Downeast believes that the likely effects of the proposed LNG import terminal on shorebirds are 

less than expected by Maine DIFW because the pier is more than 1,000 feet from the primary 

feeding area. Given these distances from shorebird activity, pedestrian or vehicular traffic on the 

pier during operation of the project is unlikely to substantially affect feeding shorebirds. 

However, to mitigate for potential habitat loss of the Shorebird Area in Mill Cove, Downeast 

developed a Shorebird Mitigation Plan in consultation with the Maine DIFW. The revised 

Shorebird Mitigation Plan was finalized during a series of meetings in July 2007 between 

representatives from the Maine DIFW, Downeast, and Woodlot Alternatives, and accepted by 

the Maine DIFW on August 15, 2007. Appendix N contains the Shorebird Mitigation Plan 

submitted to the Maine DIFW as well as copies of agency communications. The Maine DIFW 

indicated that the proposed Shorebird Mitigation Plan reasonably mitigates for the shorebird 

impacts if Maine DEP determines that compensation for shorebird impacts is warranted. This 

agreement may be subject to modification during the Maine DEP permitting process. 

The agreement includes provisions by Downeast to provide $3,000,000 in property acquisition 

funds to offset any potential impacts on shorebird habitat from the construction and operation of 

the Downeast LNG import terminal in Robbinston, Maine. The Maine DIFW may reduce the 

compensation amount if Downeast acquires conservation easements or purchases land in Mill 

Cove or other locations that result in permanent protection of a 250-foot riparian buffer. 

Additionally, this shorebird habitat compensation package includes research funding for an 

“advancing the science” program; a shorebird banding study; shorebird pre-construction, 

construction, and post-construction studies; and an adaptive management plan, as follows: 
4.5 – Wildlife and Aquatic Resources 4-84

• Downeast would provide the Maine DIFW with $500,000 (included in the $3,000,000 

described above) to establish an “advancing the science” program for shorebirds. Maine 

DIFW would develop and implement science programs that further an understanding for 

shorebird biology and enable better management of shorebird resources. 

• In consultation with the Maine DIFW, Downeast would conduct a shorebird banding 

study for five years. The purpose of this study would be to further the understanding of 

shorebird biology and enable better management of shorebird resources. The program 

would be initiated within the calendar year that construction begins subject to the Maine 

BEP permit. Downeast would coordinate appropriate permits and scope of the study in 

conjunction with the Maine DIFW prior to initiation of the study.

• Downeast would develop and implement surveys to document shorebird use of Mill Cove 

to estimate potential effects of the LNG terminal construction and operation on 

shorebirds. Surveys would be designed in consultation with Maine DIFW. An annual 

report of study details, results, and recommendations would be prepared and distributed 

by Downeast to the Maine DIFW and to other state and federal natural resource agencies 

upon request. 

• Downeast would develop an adaptive management plan in consultation with Maine 

DIFW for shorebirds that provides a process for identifying unreasonable adverse effects 

from development and operation of the LNG terminal and provides possible mitigation 

mechanisms. Adaptive management is intended to avoid, reduce, and minimize 

unreasonable adverse disturbances. The adaptive management plan is also found in 

Appendix N.

Additionally, Downeast has agreed to compensate for unavoidable impacts on coastal wetland 

areas, which include 0.1 acre of direct impact and an area overlain by the pier of 0.4 acre. The 

Maine DEP recommended compensation ratio for restoration of wetlands and significant wildlife 

habitats is 2 to 1. Downeast has identified two mitigation areas that are near one another; one is 

a coastal wetland with significant shorebird roosting, and the other is a salt marsh that transitions 

into a freshwater wetland, which also provides wildlife habitat. Downeast has been in 

discussions with the relevant agencies however a wetland mitigation package has not been 

finalized. We have recommended that Downeast continue to consult with the agencies and file 

the final wetland mitigation package with the Secretary (see section 4.4.1.2).

Terrestrial Wildlife

The land-based portion of the proposed terminal was historically used for agriculture and timber 

harvest, and as such is in various stages of forest succession. Spruce-fir forest dominates the 

proposed terminal site and provides the primary structural component for bird communities. 

This habitat is also heavily influenced by its proximity to Passamaquoddy Bay. Typical yearround residents include spruce grouse (Dendragapus canadensis), woodpeckers (Picoides spp.), 

and a variety of songbird species, such as dark-eyed junco (Junco hyemalis), black-capped 

chickadee (Poecile atricapillus), boreal chickadee (Poecile hudsonicus), and red-breasted 

nuthatch (Sitta canadensis). Small mammals that are expected to occur in the proposed terminal 

may include various rodent species (e.g., shrews, voles, moles, and squirrels), rabbits, and forest 

dwelling bats. The site of the terminal provides marginal habitat for medium and large terrestrial 
4-85 4.5 – Wildlife and Aquatic Resources

mammals due to its proximity to U.S. Route 1 and Passamaquoddy Bay. Downeast proposes to 

use off-site laydown yards, which are highly disturbed habitats that afford low-quality habitats to 

terrestrial wildlife. 

A wetland/stream complex that flows through the northwestern portion of the proposed terminal 

site provides marginal habitat for potentially occurring salamanders, such as the northern dusky 

salamander (Desmognathus fuscus) and northern two-lined salamander (Eurycea bislineata). 

These two species require a highly oxygenated environment (Krohn et al. 2000; DeGraaf et al. 

1992), which this stream is not likely to provide based on its morphology and low-gradient. Few 

reptile species are expected to occur in the proposed terminal due to its geographic location and 

absence of large open water sites. Species with potential to occur include common garter 

(Thamnophis sirtalis), ringneck (Diadophis punctatus), and redbelly snakes (Storeria 

occipitomaculata); all may use the upland, particularly those locales with rich soil. 

Shallow depressions created by skidders are a common artifact of timber harvest in the proposed 

terminal area. Though this habitat may function as a vernal pool, it would not be designated 

SVP status due to its anthropogenic origin, with the exception of those vernal pools that provide 

habitat to special status species. Species commonly associated with vernal pools, some of which 

are protected by the state of Maine and the FWS, such as wood frogs (Rana sylvatica), have been 

observed in this portion of the terminal area, and other vernal pool species such as spotted 

salamanders (Ambystoma maculatum) may also be present on-site. 

We requested that Downeast conduct additional vernal pool surveys of the proposed LNG 

terminal during spring using vernal pool determination protocols that comply with the criteria 

outlined by Maine DEP, Chapter 335. In response to our request, Downeast completed vernal 

pool surveys in the terminal location during late April 2007. SVP habitat was not identified 

(Stantec Consulting 2007). 

Constructing the terminal and off-site laydown yards would alter and reduce wildlife habitat in 

the predominantly spruce-fir forest through direct conversion of 47 acres to terminal facilities. 

Construction activities are also likely to cause mortality or injury to small, less mobile mammals 

that reside on-site. Spruce-fir habitat is not limited within Maine (see table 4.5.1.2-2). Of the 

47 acres that would be converted, 9 acres would be wetlands. Impacts on wetlands and stream 

habitats may include sedimentation, vegetation removal, or channel modification. Adherence to 

Downeast’s Plan, Procedures, and Soil Erosion and Sediment Control Guidelines would 

minimize these effects. In addition, Downeast has attempted to use a design that impacts the 

least amount of land by implementing a compact facility design. 

Short-term impacts, such as disturbance to wildlife outside of the boundary of the facility, would 

be expected only due to the noise and activity associated with construction. Operational noise 

would not significantly impact wildlife communities outside of the terminal site. 

As with nocturnal species that use habitats adjacent to the offshore terminal facilities, birds that 

use habitats near the onshore terminal facilities could also be affected by night-lighting during 

operation of the terminal. Affected species could include barred owl (Strix varia), common 

nighthawk (Chordeiles minor), and whip-poor-will (Caprimulgus vociferous), all of which have 

been detected in the region (Sauer et al. 2005). The operational lighting would be limited to the 

extent necessary to maintain safe working conditions at the terminal. To mitigate impacts on 
4.5 – Wildlife and Aquatic Resources 4-86

nocturnal species, Downeast would strategically locate light fixtures to minimize light pollution 

beyond the terminal area.

4.5.1.3 Sendout Pipeline 

The following section discusses wildlife habitats that were identified within or adjacent to the 

proposed amended sendout pipeline and potential impacts on species using those habitats. These 

areas are depicted in figures M-3 through M-31 contained in Appendix M. Vegetation 

communities, including unique, sensitive, or protected plant communities are discussed in 

section 4.4 of this EIS.

Wildlife-Habitat Associations

The proposed amended sendout pipeline crosses mature upland forest types (i.e., spruce-northern 

hardwoods and white-pine-mixed hardwoods), upland early successional forests (i.e., aspenbirch woodland/forest complex), upland maintained openings, and wetlands. Wetland types are

discussed in section 4.4.1 of this EIS. Old-growth forest is not present within areas crossed by 

the proposed sendout pipeline. 

Continuous mature forest interspersed with young forest is the principle character of the 

landscape along the proposed sendout pipeline route. Field surveys documented the presence of 

several forest dwelling species, such as snowshoe hare (Lepus americanus), porcupine 

(Erethizon dorsatum), and fisher (Martes pennanti). Forest communities support diverse 

assemblages of mammals due to the special structural features that are present, such as cavity 

trees for denning, seedling-sapling trees for food, and woody debris for cover. Small mammals, 

such as mice, voles, and shrews, need forests with closed canopy, thick litter, and woody debris 

to meet requirements throughout their lifetime. Other small mammals such as smoky shrew 

(Sorex fumeus) and northern flying squirrel (Glaucomys sabrinus) are found in upland forests 

crossed by the proposed sendout pipeline. Furbearing mammals such as bobcat (Felis rufus), and 

long-tailed weasel (Mustela frenata) would also be likely to occur in upland forests. 

Mature forests tend to have a high incidence of dead and dying standing trees, which are 

important elements of habitat diversity in forests. Standing snags and cavity trees provide nest 

sites; foraging substrate; plucking posts for raptors; singing, hammering, or drumming sites; food 

caches or granaries; courtship display sites; roosting sites; and hunting and hawking perches. 

The contiguously forested landscape provides secure and expansive habitat for forest raptors, 

such as broad-winged hawk (Buteo platypterus) and Cooper’s hawk (Accipiter cooperii). Forest 

raptors use the forest openings to hunt rodents and smaller birds. Habitat for forest raptors can 

be found at numerous locations along the proposed sendout pipeline in the form of mature forest 

interspersed with younger stands. 

Because spruce-fir forests are intensively managed for timber production, there is an abundance 

of food available for both black bear (Ursus americanus) and moose (Alces alces). Young, 

regenerating stands provide high-quality browse and cover for moose, and early successional 

forests produce thick crops of naturally occurring fruits and berries that are important foods of 

juvenile and adult bears. The prevalence of wetland communities throughout the region is 

attractive and important for both species, particularly during the spring when moose and bear 

nutritional demands are high, and they look to forage on new plant growth in thawing wetlands. 
4-87 4.5 – Wildlife and Aquatic Resources

Black bear and moose scat were observed in several locations along the sendout pipeline route; 

however, neither species is abundant in Washington County. 

Many forest birds require, or at least use, early-successional forests. Many shrub-nesting birds 

require young forest openings larger than one acre. Larger forest openings provide an interior of 

dense vegetative cover away from edges where mammalian predators may travel. Earlysuccessional birds include several migrant songbirds, such as mourning warbler (Oporornis 

philadelphia), white-throated sparrow (Zonotrichia albicollis), and Nashville warbler (Vermivora 

ruficapilla). The red-tailed hawk (Buteo jamaicensis) would likely occur in open areas and early 

successional woods that have scattered high perches. 

American woodcock (Scolopax minor) and ruffed grouse (Bonasa umbellus) are fairly common 

in early successional forests, and were observed during field surveys. Woodcock are migrant 

birds that breed in the region. Woodcocks perform courtship displays in open habitats as small 

as one acre. Daytime foraging habitats are found in dense cover of alder, aspen or birch that also 

have damp soils with abundant earthworms. Wild turkeys (Meleagris gallopavo) and their 

habitat also occur along the proposed sendout pipeline. The red-tailed hawk would occur in 

similar habitats with scattered high perches. Other birds such as black-billed cuckoo (Coccyzus 

erythropthalmus), whip-poor-will, flycatchers (Empidonax spp.), waxwings (Bombycilla spp.), 

and dark-eyed junco are also expected to occur in early successional forest habitats crossed by 

the proposed sendout pipeline. 

Streams, ponds, and wetlands occur along portions of the sendout pipeline right-of-way. Open 

water and wetlands attract mammals such as beaver (Castor canadensis), muskrat (Ondatra 

zibethicus), raccoon (Procyon lotor), moose, and bats, as well as birds such as loons (Gavia 

spp.), grebes (Podilymbus and Podiceps), ducks (Anas spp.), osprey (Pandion haliaetus), 

common yellowthroat (Geothlypis trichas), yellow warbler (Dendroica petechia), and belted 

kingfisher (Ceryle alcyon). Amphibians and reptiles such as eastern newt (Notophthalmus 

viridenscens), bullfrog (R. catesbeiana), snapping turtle (Chelydra serpentine), and northern 

watersnake (Nerodia sipedon) also use these habitats for breeding and feeding. All community 

types except spruce-fir forest are expected to support waterbirds during some phase of the annual 

life cycle according to Krohn et al. (2000) and DeGraaf et al. (1992).

Several species potentially occurring along the proposed sendout pipeline exist within a fairly 

specific environmental niche, such as the American bittern, (Botaurus lentiginosus), least bittern 

(Ixobrychus exilis), Virginia rail (Rallus limicola), and sora (Porzana carolina). These four 

species all require the presence of some emergent vegetation on their breeding grounds and are 

secretive in nature, often well camouflaged and hidden amongst the vegetation. The least bittern 

possesses perhaps the most constrained set of habitat components of these species: flooded 

robust vegetation (most often cattail), stable water levels, and large expanses of open water 

(Moore 2000; Gibbs and Melvin 1990; Weller 1961). Of these four webless waterbirds, the least 

bittern was listed as endangered (Maine DIFW 2007a) and is the most habitat-limited in the 

region. Based on known occurrences of least bittern (Maine DIFW 2007a), it is unlikely to occur 

within the proposed sendout pipeline right-of-way. 

Six bat species, including the little brown and northern long-eared myotis (Myotis lucifugus and 

M. septentrionalis), silver-haired bat (Lasionycteris noctivagans), eastern pipistrelle (Pipistrellus 

subflavus), hoary and red bats (Lasiurus cinereus and L. borealis), and big brown bat (Eptesicus 
4.5 – Wildlife and Aquatic Resources 4-88

fuscus), have the potential to occur in habitats associated with the sendout pipeline right-of-way. 

Suitable bat habitat would be limited to forests, forest openings, and open water. Cave 

environments have not been located in the vicinity of the sendout pipeline, and none are expected 

to be discovered in the region. However, any forest-dwelling bats would find suitable roosting 

habitat in trees with peeling bark or on the ground in the forest litter. Additionally, foraging 

habitat is available along the gravel roads, open stream corridors, and over ponds and 

impoundments. Habitat for forest-dwelling bats is prevalent in the Downeast LNG Project area.

Species warranting particular management attention include the blue-spotted salamander 

(Ambystoma laterale), which is likely to occur in hardwood forest types associated with the 

proposed sendout pipeline, providing that adequate breeding pools are present. The northern 

leopard frog (Rana pipiens) is associated with slow moving streams/pond-like environments, 

hardwood-dominated uplands, and most notably, wet meadows and fields for breeding. These 

two amphibians are listed in Maine as species of special concern. 

Impacts on Wildlife Species

Wildlife habitat may be lost or transitioned into a different habitat type, such as the transition of 

forested land into scrub-shrub and graminoid vegetated communities. Forest fragmentation 

would occur along the right-of-way, which could degrade wildlife habitat for interior woodland 

species sensitive to edge effects, and increase predation on some species in proximity to the 

right-of-way. Downeast has collocated the pipeline, to the extent practical, along existing rightsof-way, thereby minimizing additional forest fragmentation. In all, the sendout pipeline will 

temporarily impact 226.7 acres, and permanently impact 122.5 acres of wildlife habitats, as listed 

in table 4.5.1.3-1.

TABLE 4.5.1.3-1

Acres of Impact on Terrestrial Wildlife Habitats by Construction and Operation of the Sendout Pipeline

Facility

Forest 

Land Wetlands Agricultural Grassland Total

Con. Op. Con. Op. Con. Op. Con. Op. Con. Op.

30-inch-diameter Sendout 

Pipeline a/

151.0 98.9 26.6 14.2 2.0 1.1 11.7 7.4 191.3 121.6

Off-site pipe laydown and 

storage areas

15.7 0 1.9 0 0.7 0 0 0 18.3 0.0

Valve Station (MP 17.17) 0.3 0.4 0 0 0 0 0 0 0.3 0.4

Pigging Receiving and Gas 

Metering Facility at Baileyville 

Terminus b/

0 0 0 0 0 0 0 0 0 0

ATWS and HDD ATWS 12.6 0 0.9 0 1.7 0 1.0 0 16.2 0

Access Roads c/ 0.5 0.5 0.1 0 0 0 0 0 0.6 0.5

Total Sendout Pipeline 180.1 99.8 29.6 14.2 4.4 1.1 12.7 7.4 226.7 122.5

a/ Includes nominal 25-foot-wide construction right-of-way and a 50-foot-wide operation right-of-way.

b/ Pigging facilities at the Baileyville Compressor Station would be constructed in previously disturbed areas within the station 

property.

c/ Only the access road at MP 15.4 will require clearing for a new road base. The other three temporary access roads have 

existing road bases; however, they will need to be upgraded prior to construction of the sendout pipeline and will not be restored to 

pre-existing conditions.
4-89 4.5 – Wildlife and Aquatic Resources

Part of the amended sendout pipeline route would entail a 6,621-foot-long HDD under the 

St. Croix River from MP 14.1 to MP 15.3. Based on desktop review of information, Downeast 

determined that there are no known rare botanical or wildlife features or habitat within the 

construction area along the St. Croix River corridor. Nonetheless, it would conduct surveys to 

identify any sensitive areas prior to the start of construction. The FWS requested information 

about the potential impact of the HDD of Magurrewock Marsh on nesting bald eagle habitat. 

Downeast has indicated that the HDD drilling location is more than 0.5 mile from the location of 

the bald eagle nest at the Magurrewock Marsh. The drilling activity and associated equipment 

and materials storage would be outside the noise and staging buffer areas established by the 

FWS. Downeast would adhere to its Plan, Procedures, and Soil Erosion and Sediment Control 

Guidelines to protect water quality and wildlife during construction and operation of the sendout 

pipeline. Downeast would restore those affected areas and reseed using seed mixtures of plant 

species native to the area. 

Mammals

Short-term direct effects to terrestrial mammals would occur during construction of the sendout 

pipeline in the form of increased noise and human presence, which could displace some 

individuals. Forested habitat alteration would have short-term and long-term effects in the form 

of temporary (151 acres) and permanent (98.9 acres) conversion of mature forest to early 

successional forest and maintained openings (see table 4.5.1.3-1). Construction activities are 

likely to cause mortality or injury to small, less mobile mammals that reside on-site. During 

construction, mobile species would be displaced, and some would return after construction is 

completed, particularly those species that use forest edges. Some mammals may benefit from a 

permanent corridor of herbaceous vegetation, such as bats and white-tailed deer (Odocoileus 

viginianus), both of which would use the right-of-way for foraging and as a dispersal corridor 

that provides linkages between sources and sink populations throughout the landscape. 

Birds

Construction and operation of the sendout pipeline would directly affect terrestrial birds by 

converting upland and wetland forest to permanent, linear forest openings. Changes in 

vegetation and forest structure are discussed in section 4.4.2 of this EIS. The greatest loss of 

habitat would occur in forest areas, totaling 151 acres of temporary and 98.9 acres of permanent 

disturbance, followed by disturbance to wetland habitats that would total 26.6 acres during 

construction and 14.2 acres during operation (see table 4.5.1.3-1). 

The creation of a linear deforested corridor may also have indirect effects to birds. Pipeline 

corridors create brushy edges that are attractive to many shrub-nesting birds, such as northern 

cardinal (Cardinalis cardinalis) and common yellowthroat. Pipeline corridors in heavily 

forested landscapes have been reported to attract birds dependent on open habitats, such as has 

been the case for wild turkeys along parts of the M&NE corridor (Maine DIFW 2006b). 

Simultaneously, the right-of-way may also attract mammalian nest predators, such as striped 

skunk (Mephitis mephitis) and raccoon. However, negative edge effects may not be significant 

in such a heavily forested landscape. Additionally, the sendout pipeline has been sited along 

existing linear corridors for powerlines, roadways, all-terrain vehicle (ATV) and snowmobile 

trails, and in areas of timber harvesting. Because this low-level fragmentation already exists in 
4.5 – Wildlife and Aquatic Resources 4-90

the landscape, we conclude the proposed sendout pipeline corridor would have minimal 

contribution to the effects associated with mature forest conversion and associated edges. 

Mitigation of waterbird impacts would rely on strict adherence to BMPs for erosion control and 

maintenance of riparian buffers. Heavy equipment would be supported on weight-bearing 

surfaces (e.g., crane mats) to avoid creating micro-topographic changes in wetland habitats. 

Downeast has stated that it would prohibit pipeline construction in significant waterfowl and 

wading bird habitat during the breeding season from April 15 to July 15. Therefore, because of 

Downeast’s proposed mitigation, we conclude impacts on birds (including wading, waterfowl, 

and migratory birds) would not be significant.

Reptiles and Amphibians

Construction and operation of the sendout pipeline has the potential to affect both the quantity 

and quality of habitat available to reptiles and amphibians. During construction, mobile species 

would be displaced to adjacent areas, whereas less mobile species might be injured or killed. 

These species are found in most habitats crossed by the sendout pipeline, which would affect 

226.7 acres during construction and 122.5 acres during operation. These impacts include 

29.6 acres of temporary and 14.2 acres of permanent impacts on wetland habitats (see 

table 4.5.1.3-1). Where wetlands and streams must be traversed, impacts associated with 

construction activities could include short-term sedimentation (from erosion) and topographic 

changes (from heavy machinery) to the system. Downeast’s Plan, Procedures, and Soil Erosion 

and Sediment Control Guidelines outline measures that minimize impacts on resources. 

Construction and operation of the proposed sendout pipeline is not expected to adversely affect 

reptile and amphibian populations. 

Moosehorn National Wildlife Refuge

The Moosehorn NWR is principally managed to protect wildlife, including migrating waterfowl, 

wading birds, shorebirds, upland game birds, songbirds, and birds of prey. A species that 

receives much attention and research at the Moosehorn NWR is the American woodcock. 

Woodcock are known to use early successional habitats (clearings, alder thickets, young 

hardwood forests) for courtship rituals and breeding. Originally, the sendout pipeline crossed 

3.5 miles of the Moosehorn NWR; however, on September 27, 2007, the FWS deemed the 

proposed pipeline route to be inappropriate in the NWR. The amended sendout pipeline would 

no longer cross the Moosehorn NWR. At its closest point, the amended pipeline route would be 

more than 0.25 mile away from the Moosehorn NWR between MP 10.0 and MP 10.5, MP 12.3 

and MP 14.3, MP 15.1 and MP 15.2, and between MP 17.3 and MP 17.8, for a total of about 

3.1 miles. In a comment letter on the draft EIS, the FWS has expressed concern about the 

impacts from the sendout pipeline construction activities along the boundaries of the Moosehorn 

NWR and the timing of construction near the Moosehorn NWR. While we believe that 

Downeast has addressed the FWS’s concern by moving the proposed pipeline outside of the 

NWR, continued consultation with the FWS regarding construction near the refuge is 

appropriate. Therefore, we recommend that: 

• Downeast shall continue to consult with the FWS to determine if there are FWSrecommended seasonal or construction timing restrictions that Downeast could 

incorporate into its construction plan to minimize impacts of the sendout pipeline 
4-91 4.5 – Wildlife and Aquatic Resources

along the Moosehorn NWR boundaries. Prior to construction of the pipeline 

facilities, Downeast shall file with the Secretary copies of its correspondence with 

FWS and a description of the construction timing restrictions and/or mitigation 

measures it has agreed to implement along the Moosehorn NWR boundaries. 

Significant Wildlife Habitats

Significant and essential wildlife habitats in Maine are regulated under NRPA, which is 

administered by the Maine DEP. Significant wildlife habitats including vernal pools and IWWH 

were identified along the proposed sendout pipeline during correspondence with Maine DIFW, 

Maine NAP, and FWS. Additionally, one deer wintering area is crossed twice by the sendout 

pipeline. 

Due to the amount of significant wildlife habitat that would be disturbed by the proposed project, 

the Maine DEP requested compensation from Downeast. Downeast developed, in consultation 

with the Maine DEP, Maine DIFW, FWS, COE and EPA, several mitigation alternatives that 

specifically focus on preserving inland wetlands that contain significant wildlife habitat. 

Downeast will need to continue its consultation with these agencies for approval of a final, 

comprehensive wetland mitigation plan that addresses coastal and freshwater wetlands, areas 

used by tidal and inland wading waterfowl, and SVPs.

Significant Vernal Pools 

Maine DEP and legislature adopted rules governing, among others, SVP habitats, which were 

implemented on September 1, 2007. A vernal pool, defined by NRPA, is a natural, temporary to 

semi-permanent body of water occurring in a shallow depression that typically fills during the 

spring or fall and may dry during the summer; it has no permanent inlet, and lacks viable 

populations of predatory fish. Downeast conducted surveys along the proposed sendout pipeline 

in May and again in October 2007 to determine the locations of SVP habitats. See 

section 4.4.1.3 for a detailed discussion of vernal pools along the sendout pipeline. 

Inland Waterfowl and Wading Bird Habitat

Waterfowl habitat can be grouped into three broad categories: breeding; migration and staging; 

and wintering habitats. Wading bird habitat consists of breeding, feeding, roosting, loafing and 

migration stopover areas. Waterfowl and wading bird habitats are ranked as high, moderate, or 

low value based on observed species use, dominant wetland type, and the diversity, size and 

interspersion of wetland types; moderate and high value IWWH are protected in Maine. A high 

to moderate value IWWH is a complex of freshwater wetland and open water areas, and includes 

a 250-foot wide zone surrounding the wetland complex. The 250-foot buffer zone may include 

upland areas outside of the wetland. 

Nine discrete areas of IWWH occur along the amended sendout pipeline route. Many waterfowl 

and wading bird habitats crossed by the sendout pipeline are considered moderate to high value 

IWWH (see sendout pipeline figures in appendix M). Through refinements of its amended 

sendout pipeline route, Downeast has further reduced its impact on six areas of IWWH, affecting 

a total of 4.78 acres during construction and operation of the sendout pipeline (table 4.5.1.3-2). 

Possible effects to these bird habitats as well as vernal pools include increased turbidity and 

associated suspended solids, which could cause indirect effects such as shifts in prey community 
4.5 – Wildlife and Aquatic Resources 4-92

composition when nutrient enrichment and light attenuation alters primary productivity, or 

decreased ability to detect and capture prey. Heavy equipment could cause rutting and slight 

changes in elevation that could affect hydrology characteristics of IWWHs and vernal pools. 

Discharge of pollutants from worksite machinery into nearby aquatic habitats could occur. Noise 

resulting from construction activities could disturb breeding or migrating individuals (e.g., nest 

failure, reduced recruitment to breeding populations).

TABLE 4.5.1.3-2

Inland Waterfowl and Wading Bird Habitat Impacts Along the Sendout Pipeline

Milepost Temporary Impacts

(Acres)

Permanent Impacts

(Acres) Total

4.1 a/ 0.0 0.0 0.0

7.7 0.4 0.7 1.1

8.5 a/ 0.0 0.0 0.0

13.0 0.3 0.4 0.7

14.0 1.0 1.5 2.5

14.2 a/ 0.0 0.0 0.0

17.6 b/ 0.3 0.1 0.4

25.1 a/ 0.0 0.0 0.0

28.9 0.02 0.06 0.08

Total 2.02 2.76 4.78

a/ Denotes IWWH avoidance through HDD.

b/ Impacts on IWWH minimized through use of HDD in much of this wetland.

Construction activity is a disturbance that represents a potential impact on migrating, nesting, 

and brooding waterbirds. Mitigation of noise disturbance would be accomplished by limiting 

construction in sensitive areas to the non-breeding season for species whose preferred 

community types within IWWH exist in or adjacent to the construction activity area. Downeast 

would mitigate for impacts on IWWH and adjacent buffer zones by avoiding construction 

activities in those areas from April 15 to July 15. Furthermore, Downeast would implement its 

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

proposed sendout pipeline. Downeast would preserve wetland topography by limiting heavy 

equipment use to seasonal and edaphic conditions that are capable of supporting construction 

machinery. This would include operating during frozen ground conditions or on adequate 

weight-bearing substrates, either placed or natural. Downeast would minimize the risk of 

pollution by keeping fuels, lubricants, and other potential construction or machinery associated 

pollutants at least 100 feet from aquatic resources, except under limited, highly controlled 

circumstances. Given that Downeast would avoid construction during sensitive breeding periods 

for waterfowl and wading birds, and used in combination with Downeast’s adherence to 

protective measures in its Plan, Procedures, and Soil Erosion and Sediment Control Guidelines, 

significant impacts on IWWH from construction and operation of the proposed project are not 

anticipated. 
4-93 4.5 – Wildlife and Aquatic Resources

To mitigate for the unavoidable impacts on wetlands and significant wildlife habitat associated 

with the proposed sendout pipeline, as well as other portions of the Project, Downeast proposed 

wetland/upland preservation at three off-site areas as part of its compensation plan for wetlands 

and IWWH. One site does not contain wetlands or waters of the United States (as determined 

from NWI mapping), but instead provides a buffer to wetland complexes to the north and east of 

the parcel. Another site contains upland forest habitat, 23.2 acres of wetlands (23.1 acres of PFO 

and 0.6 acres of PEM/PSS wetlands), and a tributary to Beaver Lake, which is within a resource 

protection zone. Downeast would purchase the property and place the land in conservation to be 

protected from residential and commercial development in perpetuity. 

The compensation for freshwater wetlands includes preservation of 157 acres of wetlands and 

surrounding upland buffers. Of these 157 acres, 35 acres consist of IWWH. For preservation, 

Downeast would purchase the property and place the land in conservation to be protected from 

residential and commercial development in perpetuity. Downeast is currently discussing the 

potential for putting the preserved parcels under the stewardship of a regional land trust. 

As indicated in section 4.5.1.2, discussion with the relevant agencies is ongoing, and we have 

recommended that Downeast finalize the wetland mitigation package prior to the construction of 

the pipeline or LNG terminal facilities (see section 4.4.1.2). 

Deer Wintering Areas (DWA)

Forest stands of mature conifers with tree height greater than 30 feet and crown closure of 

greater than 60 percent provide critical winter habitat for deer. Wintering habitat is limited in 

availability, comprising only 2 to 25 percent of the land base in various parts of the state (Maine 

DIFW 2007b). More specifically, DWA is defined as, “forested areas used by deer when snow 

gets more than 12 inches deep in the open and in hardwood stands, when the depth that deer sink 

into the snow exceeds 8 inches in the open and in hardwood stands, and when mean daily 

temperature is below 32 degrees” (Maine DIFW 2007c). The sendout pipeline crosses one DWA 

twice between MP 16.72 and MP 16.80, and again from MP 16.86 to MP 17.02, affecting as 

much as 2.19 acres. During construction of the sendout pipeline, this DWA would not be 

available to overwintering deer, representing a loss of cover and forage. While much of the 

affected right-of-way would be allowed to revegetate over time, a portion of the right-of-way 

would be subject to routine vegetation clearing and represents a permanent loss of DWA habitat. 

To minimize potential impacts during construction of the proposed sendout pipeline, Downeast 

would implement its Plan, Procedures, and Soil Erosion and Sediment Control Guidelines. In 

addition, Downeast has agreed to consult with Maine DIFW and Maine DEP to develop DWA 

mitigation measures similar to those proposed by M&NE during its previous construction of its 

pipeline. Therefore, we recommend that:

• Downeast should continue to consult with the Maine DEP, DIFW, and BEP to 

finalize its DWA mitigation package. Prior to construction of the pipeline facilities, 

Downeast should file with the Secretary the final DWA mitigation package and 

copies of the consulted agencies’ comments on the final package and applicable 

approvals. 
4.5 – Wildlife and Aquatic Resources 4-94

4.5.2 Aquatic Resources

4.5.2.1 Waterway for LNG Marine Traffic 

The aquatic habitats associated with the LNG marine traffic route are open waters underlain by a 

gently rolling seabed with a drowned shoreline (OMG 2005). The marine waters traversed by 

LNG vessels in route to the proposed terminal provide habitat to a number of marine species, 

which are discussed in this section. Head Harbour Passage and the associated waters of 

Cobscook Bay are considered the most species-rich area in the western North Atlantic (Larsen 

2004). Federally listed threatened and endangered species known to occur in these waters are 

discussed in section 4.6 of this EIS.

Marine Mammals

Several species of marine mammals, including whales, porpoises, dolphins, seals, and other 

pinnipeds have the potential to occur along the proposed LNG marine traffic route, and are listed 

in table 4.5.2.1-1. Life history and published accounts of population distribution were reviewed 

to determine species that have a high likelihood to be affected by the proposed Downeast LNG 

Project. This review resulted in the identification of five species that are common within the 

limit of the territorial seas that would be transited by LNG vessels, including gray seal, harbor 

seal, harbor porpoise, white-sided dolphin, and minke whale. These species are discussed in 

further detail below. Other species that are less likely to be encountered within the proposed 

project area, but may occur as transient individuals, include Atlantic spotted dolphin, beaked 

whales, beluga whales, bottlenose dolphin, common dolphin, white-beaked dolphin, harp seal, 

hooded seal, killer whale, long-finned pilot whale, northern bottlenose whale and short-finned 

pilot whale. Threatened and endangered marine mammals are discussed in section 4.6 of this 

EIS and in our BA included as Appendix C.

In general, marine mammal occurrence along the proposed waterway increases from spring and 

summer and decreases from fall to winter. Their occurrence is usually related to the distribution 

of each species’ preferred prey (e.g., copepods and krill for baleen whales, fish prey for toothed 

whales). 

Resident colonies of gray seals occur in coastal Maine; pupping occurs on several isolated 

islands along the Maine coast (Waring et al. 2011). Maine is also a winter breeding ground for 

gray seals. 

Harbor seals are the most abundant pinniped species found in western North Atlantic waters, and 

are found in all nearshore waters of this region. Important habitat for seals occurs along the 

transit route and the adjacent coastline, and suitable seal habitat includes Passamaquoddy Bay. 

Seal habitats include feeding and breeding areas, and pupping and haul-out ledges. An estimated 

30,000 harbor seals spend all or part of the year in the Gulf of Maine, including small islands 

along the Maine coast (GoMOOS 2007). Seals haul out on remote exposed rocks, sandbars, 

rocky shores, and ice, but are usually solitary in the water. They are not migratory, but instead 

make seasonal movements in response to prey distribution. From September to late May, 

seasonal seal movements occur southward from the Bay of Fundy to the coasts of southern New 

England (Waring et al. 2011). Pupping season occurs in mid-May through June, and takes place 

primarily along coastal Maine (see Appendix F, figures F-20 and F-22). Harbor porpoises prefer 

nearshore habitats, especially waters less than 490 feet (50 meters) deep. Dense populations of 

this species occur in the Gulf of Maine and the southern Bay of Fundy. Harbor porpoises are 

considered year-round inhabitants in the Gulf of Maine.
4-95 4.5 – Wildlife and Aquatic Resources

TABLE 4.5.2.1-1

Marine Mammals Expected to Occur Along the LNG Marine Traffic Route and LNG Terminal a/

Species Marine Preference Project Area Occurrence Timing of

Occurrence

Atlantic Spotted Dolphin

(Stenella frontalis)

continental shelf waters; 

inshore

waterway for LNG marine 

traffic

Incidental -

Beaked Whales

(Mesoplodon spp.)

continental shelf waters; 

inshore

waterway for LNG marine 

traffic

Incidental late spring, 

summer

Beluga

(Delphinapterus leucas)

inshore waters, 

estuarines, bays

waterway for LNG marine 

traffic

Incidental -

Bottlenose Dolphin

(Tursiops truncates)

offshore and inshore 

(two different 

populations)

waterway for LNG marine 

traffic

Occasional -

Common Dolphin

(Delphinus delphis)

outer continental shelf waterway for LNG marine 

traffic

Occasional mid-summer to 

autumn

Cuvier's Beaked Whale

(Ziphius cavirostris)

continental shelf edge; 

deep water

waterway for LNG marine 

traffic

Incidental late spring, 

summer

Grey Seal

(Halichoerus grypus)

coastal waters waterway for LNG marine 

traffic

LNG Terminal

Common year-round

Harbor Porpoise

(Phocoena phocoena)

coastal waters less than 

150 meters deep

waterway for LNG marine 

traffic

LNG Terminal

Common year-round; most 

abundant in 

summer

Harbor Seal

(Phoca vitulina)

coastal waters waterway for LNG marine 

traffic

Common year-round

Harp Seal

(Pagophilus 

groenlandicus)

coastal waters; inshore 

waters

waterway for LNG marine 

traffic

Occasional; 

increasing

late spring, 

summer

Hooded Seal

(Cystophora cristata)

offshore waters; 

continental shelf waters 

during winter

waterway for LNG marine 

traffic

Occasional; 

increasing

late spring, 

summer

Killer Whale

(Orcinus orca)

continental shelf less 

than 200 meters deep

waterway for LNG marine 

traffic

Incidental -

Long-finned Pilot Whale

(Globicephala melas)

continental shelf; 

offshore (winter)

waterway for LNG marine 

traffic

Incidental late spring through 

autumn

Minke Whale

(Balaenopterus 

acutorostrata)

continental shelf; coastal waterway for LNG marine 

traffic

Common spring and summer 

(period of greatest 

abundance); rarely 

seen in winter

Northern Bottlenose Whale

(Hyperoodon ampullatus)

deep waters off the 

Scotian Shelf

waterway for LNG marine 

traffic

Incidental -

Short-finned Pilot Whale

(G. macrorhynchus)

continental shelf and 

slope waters; likely south 

of New Jersey

waterway for LNG marine 

traffic

Incidental -

White-beaked Dolphin 

(Lagenorhynchus 

albirostris)

Shallow, temperate to 

subpolar waters

waterway for LNG marine 

traffic

Occasional most abundant in 

July, August, and 

September

White-sided Dolphin

(Lagenorhynchus acutus)

continental shelf and 

slope waters with 

seasonal inshore / 

offshore movements

waterway for LNG marine 

traffic

Common summer

a/ Marine mammals protected by the ESA are discussed in section 4.6 of this EIS.
4.5 – Wildlife and Aquatic Resources 4-96

White-sided dolphins are especially abundant in the Gulf of Maine; from July to September, they 

are frequently found in waters ranging from the southern Gulf of Maine out along the continental 

shelf and slope to Cabot Strait. They likely make inshore/offshore seasonal movements in 

response to changing prey distribution. White-sided dolphins are generally observed in large 

pods of greater than 100 individuals.

Minke whales are found in the continental shelf or coastal waters of the North Atlantic Ocean, 

especially within the Gulf of Maine and the Bay of Fundy. They are common and widely 

distributed, and most abundant in spring and summer. 

Sea Turtles

One species of sea turtle, the leatherback sea turtle (Dermchelys coriacea) is known to occur in 

the waters of Passamaquoddy Bay and the Bay of Fundy during the summer and fall (typically 

June through October). This species is currently listed as endangered by both the United States 

and Canada. Information regarding this species including potential impacts and proposed 

mitigation measures associated with the project are discussed in section 4.6 of this EIS.

Finfish and Invertebrates

Numerous pelagic and demersal finfish species (including those of commercial and recreational 

importance) are known to occur within the waters associated with the LNG transit route. Many 

of these species are also known to occur in the waters associated with the LNG terminal and are 

discussed in detail in section 4.5.2.2 of this EIS. A comprehensive EFH assessment is provided 

in Appendix G and summarized in section 4.5.3.

Aquaculture also occurs in the vicinity of the transit route. There are 8 aquaculture sites located 

in the U.S. waters along the transit route and 15 aquaculture sites located in the Canadian waters 

along the transit route.

The most common and commercially important shellfish found within the waters associated with 

the transit route are the soft-shell clam (Mya arenaria), blue mussel (Mytilus edulisi), and the 

northern sea scallop (Placopecten megellanicus). In Maine waters, the soft-shell clam is 

primarily an intertidal benthic, infaunal clam that lives in a variety of sediments from coarse sand 

to soft silt at a depth in the sediment of only a few millimeters. The blue mussel is an epibenthic 

species that attaches itself to the bottom substrate through secreted fibers called byssal threads or 

byssus. They can be found both intertidally and subtidally in Maine waters on sediments ranging 

from coarse gravel and relic shell to fine silt where they often form large mats or beds just above 

and extending below the low watermark. The northern sea scallop is a strictly subtidal species 

that is found on bottoms ranging from coarse gravel and cobble to fine silt, although firmer 

bottom subject to swift currents is preferred. 

Harvesting of the soft-shell clam can only be accomplished using hand implements (i.e., clam 

rakes). Blue mussels and scallops may also be harvested by hand; however, they are usually 

harvested commercially using dredges. All three species are harvested in the region associated 

with the project, but sea scallops are by far the most commercially important of the three. 

According to Russell Write of the Maine DMR Marine Patrol for the Eastport-Lubec area, the 

shorelines along most of the transit route in Western Passage and Friar Roads are steep and rocky 

offering little habitat for soft-shell clams or mussels. In addition, the majority of the habitat that 
4-97 4.5 – Wildlife and Aquatic Resources

does exist is closed to harvesting due to pollution. Currently, only Lewis Cove, the southern 

portion of Mill Cove, and portions of the coastline along the Passamaquoddy reservation are 

open to shellfish harvesting. Several sections of the waterway from Todd Head (Eastport) to 

Frost Point (Perry) are closed. Shellfish harvesting in Gleason Cove is restricted, requiring a 

permit from the Maine DMR. Sea scallops, on the other hand, are harvested to some extent 

throughout the area; however, harvesting is concentrated principally in Cobscook Bay and South 

Bay just south and west of the transit route. Based upon a 1977 Maine DMR coast-wide survey, 

the only molluscan habitat near the LNG transit route is soft-shell clam habitat. 

Lobstering is also a significant commercial fishery within the state of Maine, accounting for 

nearly 75 percent of the value of Maine’s marine resources. Maine lobster fishing occurs yearround, with effort concentrated close to shore during summer months, shifting to higher 

concentration in offshore waters during winter. Commercial lobster fishing is known to occur 

along the majority of the proposed transit routes. Within the proposed eastern transit route 

following the VTS, lobster fishing is highly seasonal for the Grand Manan lobster fishery, taking 

place from the second Tuesday in November to January 15, as well as between April 15 and 

June 30. Within the proposed Grand Manan Channel route, the lobster season extends from 

June 1 through November 30. In addition, according to sworn testimony provided to the Maine 

BEP, the waters of Western Passage and Passamaquoddy Bay extending along the Perry, Maine 

shoreline from Gleason Cove to points north of the proposed project site in Mill Cove out to 

Canadian waters are also heavily fished for lobsters between the months of April and December. 

In federal waters, the American lobster fishery is managed by NOAA Fisheries Service, state, 

federal and Constituent Programs Office, under the Atlantic Coastal Fisheries Cooperative 

Management Act and under the Atlantic States Marine Fisheries Commission Interstate Fishery 

Management Plan in state waters (NOAA Fisheries 2008a). Federal lobster permit holders who 

intend to fish for lobster with trap gear during the fishing year are required to designate lobster 

management areas and tag all lobster traps. Federal lobster regulations require federal permit 

holders to abide by the most restrictive of either state or federal trap limits. In the state of Maine, 

the Maine DMR regulates trap limits and issues trap tags.

Commercial harvesting of marine worms including sandworms (Nereis virens) and bloodworms 

(Glycera dibranchiate) also occurs along the transit route. Both sandworms and bloodworms use 

intertidal mudflats and prefer areas dominated by fine sandy and silty soil with high organic 

contents (Wilson and Ruff 1988). While both bloodworms and sandworms are largely 

subterranean, the species emerge from the substrate and enter the water column to spawn and 

feed. Both species spawn in May and June, where spawning and then larval development occurs 

on the sediment surface. Harvesting of bloodworms and sandworms is currently regulated by the 

Maine DMR and represents an important commercial industry to many coastal communities. 

These species are also an important food source for a number of marine species. According to 

the Maine DMR, four commercial worm harvesting areas occur along the transit route, including 

Gleason Cove, Halfmoon Cove, Carlow Island Causeway, and Carrying Place Cove. 

Zooplankton and Ichthyoplankton

Invertebrate zooplankton and the planktonic eggs and larvae of many fish species 

(ichthyoplankton) make up an important portion of the plankton community within the waters of 

the LNG transit route. Many of the planktonic species are also known to occur in the waters 
4.5 – Wildlife and Aquatic Resources 4-98

associated with the LNG terminal. These species are discussed in detail in section 4.5.2.2 of 

this EIS.

Special Interest Areas

Downeast proposes to use two LNG transit routes near Grand Manan Island, including the Grand 

Manan Channel to the west of the island or a channel to the east of the island (a designated 

vessel traffic zone generally used by all vessels traveling up through the Bay of Fundy) (see 

Appendix F, figures F-1 to F-10). Neither transit route option in this area would cross any 

U.S. marine sanctuaries or marine protected areas of interest; however, the route east of Grand 

Manan would cross a small portion of the Canadian Division of Fisheries and Oceans’ Grand 

Manan Basin Whale Sanctuary. Right whales are known to frequent this sanctuary as well as the 

surrounding waters of the Bay of Fundy during the summer and fall. At present, vessels 

typically do not traverse the sanctuary if right whales are known to be in the area. In addition, 

NOAA has introduced mitigations to reduce ship strike of right whales which includes reducing 

vessel speed to 10 knots when traversing seasonal management areas or dynamic management 

areas established due to high concentrations of right whales (50 CFR Part 224). These measures 

apply to all vessels 65 feet or longer.

Potential Impacts of LNG Marine Traffic

Marine Mammals and Sea Turtles

At least 22 species of marine mammal and one species of sea turtle are likely to occur in the 

waterway for LNG marine traffic. Whale habitats include feeding and breeding grounds, as well 

as migration routes in the open ocean and Head Harbour Passage. Important habitat for seals 

occurs along the transit route and the adjacent coastline and in Passamaquoddy Bay. Seal 

habitats include feeding and breeding areas and pupping and haul-out ledges. Dolphin and 

porpoise species may also occur in the Bay of Fundy and Passamaquoddy Bay for feeding. 

Potential impacts on marine mammals that use waters in or near the proposed LNG marine 

traffic route may include vessel collisions, acoustic harassment (e.g., masking of communication/ 

echolocation), physical harassment, and exposure to pollutants and marine debris. In reviewing 

stock assessment reports, it appears that whales are more likely to suffer injury or mortality from 

vessel collisions, whereas seals, porpoises and sea turtles are more likely to become entangled in 

fishing gear. Vulnerability to vessel collisions may result from the whale’s limited ability to 

detect or maneuver around on-coming vessels, or because the species is at the surface feeding, 

resting, mating, and/or nursing. Impacts and mitigations associated with whales regarding vessel 

collisions are discussed in sections 4.6.2.1 and 4.6.2.2 of this EIS. 

To investigate the impacts of underwater noise on marine mammals, it is important to understand 

how they perceive sound and how it affects their physiology. Marine mammals rely on hearing 

for a wide variety of critical functions, so exposure to sounds that permanently affect their 

hearing ability poses significant problems for the survival and reproduction of these animals. 

The two main groups of marine mammals discussed below include cetaceans and pinnipeds. The 

hearing ability of marine mammals is a function of the following characteristics and processes:

• Absolute Hearing Threshold Curve – The level of a sound that is barely audible in the 

absence of significant ambient noise is the absolute hearing threshold. This varies with 

frequency, given a threshold curve with reduced sensitivity at low and high frequencies 
4-99 4.5 – Wildlife and Aquatic Resources

and maximum sensitivity in an intermediate frequency range. The graph of this 

information, threshold versus sound frequency is termed an audiogram, which is speciesdependent. A behavioral audiogram shows sound levels for each frequency that are both 

detectable by the species and elicit a specific behavioral response such as moving away 

from the noise source.

• Individual Variation – Auditory sensitivity varies between individuals. Published 

audiograms for most species are based on data for only one or two individuals; therefore, 

audiograms are only an indication of the range of frequencies detectable for a species and 

the sound levels of each frequency that elicits a behavioral response.

• Masking – Masking is the process by which the hearing threshold for one sound is raised 

by the presence of another sound, thus competing with important signals 

(communication) (NRC 2005). Ambient noise often masks the ability of an organism to 

detect a sound signal, even when that sound is above the hearing threshold. Not only can 

masking noise prevent the detection of anthropogenic sound sources by marine mammals, 

but it can also impede sound used by organisms for communication, detecting predators 

and prey. In general, masking effects are expected to be less severe when sounds are 

transient than when they are continuous and fixed. 

• Localization – Sound source localization is the ability of an organism to determine the 

direction from which a sound is originating. The ability of marine mammals to localize is 

important for social interaction and for detecting predators or prey, whether by 

echolocation or normal listening. It is also important in order to detect a signal of interest 

amongst a man-made or other noise (Kryter 1985). The precision of localization depends 

on species, frequency, and other characteristics of the sound (Fay 1988).

• Frequency and Intensity Discrimination – This refers to the ability to discriminate sounds 

of different frequencies and levels, particularly over ambient noise levels. 

As described above, there is individual variation among species and individuals; however, 

species groups appear to have similar sensitivity to sound. Table 4.5.2.1-2 lists ranges of 

frequencies to which marine mammal groups are typically sensitive.

TABLE 4.5.2.1-2

Hearing in Marine Mammals

Marine Mammal Group Examples Range of Detection Hz

Pinnepeds – Otariids Sea lions, fur seals Mid 1,000 - 30,000

Pinnepeds – Phocids True seals, walrus Low to Mid 200 - 50,000

Cetaceans – Mysticete Baleen whales Low 10 - 5,000

Cetaceans – Odontocete Toothed whales Mid to High 4,000 - 100,000

(some species detect in 

excess of 150,000 Hz)

Source: NOAA Fisheries 2004

Changes in underwater noise levels can cause different behavioral responses in marine 

mammals. Behavioral responses of marine mammals vary based on the degree and duration of 

the disturbance. Exposure to very loud sounds by marine mammals may cause avoidance of an 
4.5 – Wildlife and Aquatic Resources 4-100

area, disruption of echolocation, masking, habitat abandonment, aggression, pup/calf 

abandonment, annoyance, helplessness, hearing loss, and tissue rupturing (Caltrans 2002). 

Changes in behaviors such as altered motor behaviors and vocalization characteristics may have 

both direct energetic costs and potential effects to foraging, navigation, and reproductive 

activities (Southall 2005). 

Avoidance is a typical behavioral response displayed by marine mammals when disturbed by 

underwater noise, which includes changes in swimming course, in which horizontal movements 

may become random. Cetaceans have been known to reduce their swimming speeds, digress 

from travel routes, and otherwise avoid the source of noise disturbances (i.e., quick dives). 

Cetaceans often dive to deeper depths to avoid humans and boats near the surface, a technique 

commonly demonstrated by mother-calf pairs. Interruption of feeding, resting, or social 

activities, and abrupt diving or swimming away constitute possible short-term reactions of 

mysticetes disturbed by human-made noise (Finley 1982; Calkins 1983). These short-term 

behavioral responses are in response to broadband industrial and recreational vessel noise 

extending from below 75 hertz (Hz) to 1,000 Hz (DOSITS 2006). 

Marine mammals and sea turtles that occur in the waterway for LNG marine traffic could be 

affected by short-term and long-term impacts associated with transiting LNG vessels and 

construction vessels. These impacts and mitigations are discussed at length in sections 4.5.2.2, 

4.6.2.1, and 4.6.2.2 of this EIS. 

Other Impacts 

Other potential impacts on aquatic resources resulting from an increase in LNG marine traffic 

include impingement and entrainment of marine species from operational water intake 

requirements; thermal and chemical impacts from engine cooling water discharge; the potential 

to introduce non-native aquatic species; degraded water quality from vessel pollution and debris; 

and the disruption of fishing activities and other marine-based uses. LNG marine traffic during 

normal operation would not affect benthic habitat or shellfish.

Impingement and Entrainment

Impingement and/or entrainment of aquatic organisms (including fish eggs and larvae) would 

likely occur during transit as a result of water withdrawals to support vessel operation 

requirements. However, because vessels would be drawing water as they transit across deep 

open waters, the potential impact would be transient and therefore not a significant impact on 

any particular localized aggregation of aquatic organisms. Section 4.5.2.2 provides a more 

detailed discussion of impacts from impingement and entrainment during construction and 

operation of the LNG terminal. 

Cooling Water Discharge

Thermal impacts associated with vessel engine cooling discharge waters are also expected to be 

minor and insignificant. CORMIX modeling conducted by Downeast indicates that vessel 

engine cooling discharges would result in a maximum 26-square meter plume of water that 

would dissipate to a change of temperature of approximately 1°C or less warmer than ambient 

conditions 15 to 30 meters from the discharge source (see Appendix O). Temperature elevations 

of 1°C above ambient would not likely have an impact on adult or juvenile marine species or 

their eggs.
4-101 4.5 – Wildlife and Aquatic Resources

The engine cooling water systems of LNG vessels visiting the proposed terminal may include 

biocides for anti-fouling of engine systems. If biocides are used, the effects to native organisms 

from discharging cooling waters containing biocides would depend on the type of biocide used. 

Some biocides could adversely affect aquatic organisms, but we conclude the effects would be 

minor given its rapid dispersal in the environment. Downeast would have no control over the 

anti-fouling system used on the visiting LNG vessels. 

Accidental Releases and Spills 

All commercial vessels are required by law to operate in accordance with the 1978 Protocol of 

the 1973/78 International Convention for the Prevention of Pollution from Ships (MARPOL). In 

addition, discharges incidental to the normal operation of non-recreational vessels, 79 feet or 

greater in length, while in U.S. waters are now subject to CWA permitting through the EPA’s 

Vessel General Permit (VGP). The permit incorporates the Coast Guard’s mandatory ballast 

water management and exchange standards, and provides effluent limits for other types of 

discharges including deck runoff, bilge water, graywater, and other pollutants. It also establishes 

specific corrective actions, inspection and monitoring requirements, and recordkeeping and 

reporting requirements. 

Therefore, with the exception of a marine casualty or direct violation of law or an international 

convention (i.e. MARPOL), we conclude water quality effects associated with the discharge of 

graywater, blackwater, ballast water, or potential accidental releases while in U.S. waters would 

be effectively minimized. 

Invasive Species

Adverse environmental effects associated with the introduction of exotic/invasive/non-native 

species through ballast water exchange are not expected, as no ballast water would be discharged 

while transiting both federal and state waters per the requirements of 33 CFR Part 151, which 

prohibits the exchange of ballast water within 200 nautical miles of the U.S. shore. Hull fouling 

is another potential vector for introduction of exotic species; however, operators of commercial 

vessels have a significant economic interest in maintaining vessel hulls in a clean condition. 

Even a small amount of hull fouling can reduce the vessel’s maximum transit speed and lead to 

an increase in fuel consumption, as the fouling organisms provide resistance to movement. To 

prevent fouling and the associated economic costs, operators aggressively implement hull plating 

preservation and maintenance programs. Furthermore, failure to preserve and maintain hull 

plating not only raises short-term operation costs but also sets the stage for increased long-term 

hull maintenance costs. There is a particular sensitivity to this engineering and economic reality 

regarding commercial vessels operating at the higher end of the sailing rates schedule, as is the 

case for LNG vessels. In addition to the antifouling measures, fluid dynamics plays a practical 

role as a barrier to the introduction of invasive species. The amount of water that passes over the 

hull and through the seachest is a massively large volume. The velocity of the seawater, abrasive 

by nature, along the hull would be expected to “waterblast” off anything that is not affixed to the 

hull (e.g., a barnacle).

If fouling does occur despite the preventative systems, Downeast has stated that it is highly 

unlikely that any exotic species originating from the LNG source areas could biologically 

survive the variance changes in the marine conditions between the point of LNG origin 

(predominantly warm to tropical environs in the Mediterranean and Trinidad) and the Downeast
4.5 – Wildlife and Aquatic Resources 4-102

LNG Project site. While the variance changes may reduce the presence of fouling organisms, we 

do not believe it would eliminate them. However, the Coast Guard has developed practices to 

address exotic/invasive organisms associated with foreign vessels. The Coast Guard Office of 

Operating and Environmental Standards has developed Mandatory Practices for All Vessels with 

Ballast Tanks on All Waters of the United States. The mandatory practices include requirements 

to rinse anchors and anchor chains during retrieval to remove organisms and sediments at their 

place of origin and remove fouling organisms from hull, piping, and tanks on a regular basis and 

dispose of any removed substances in accordance with local, state, and federal regulations. 

Therefore, we conclude that the introduction of non-indigenous attached organisms via vessel 

hulls is not likely.

Research and Commercial Fishing

Scoping comments received by the Commission indicated stakeholder concern that the presence 

of the LNG vessels in the waters of the proposed LNG marine traffic route would inhibit the 

ability of educational researchers and fishermen to use the area. As discussed further in 

section 4.7.3 and 4.8.2 of this EIS, impacts to marine activity would be insignificant. 

Stakeholders also have expressed concern that LNG vessels travelling within the proposed LNG 

marine transit routes would result in disruption to normal fishing activities, specifically 

commercial lobstering, and result in the loss of both fishing gear and access to commercially 

important fishing areas. The herring fishery is conducted mainly through weirs and purse seins; 

however, weir locations are close to shore, removed from impacts from vessel traffic, and purse 

seiners are considered mobile fishing gear. Consultations with local fishermen conducted by 

Downeast indicate that in general fishermen try to avoid placing fishing gear directly in 

designated shipping lanes in order to prevent loss of their equipment. However, because there is 

no designated shipping lane within the Grand Manan Channel or Western Passage, it is likely 

that LNG vessels could interact with fishing gear along these routes. In order to minimize 

potential interactions with and loss of fishing gear, Downeast would coordinate with local 

fishermen, conduct advance mapping of lobster trap locations, and establish planned avoidance 

routes. In hearings held by the Maine BEP on July 16, 2007, fishermen agreed that coordination 

with Downeast to establish a recommended transit route through those areas that are heavily 

fished would alleviate some of the stakeholders concerns. In addition, Downeast in cooperation 

with the Maine DMR, has met with leading representatives of the local lobster fishery to further 

define and detail the lobstermen’s key concerns and to confirm the individual lobstermen fishing 

in any areas potentially affected. This information would be used in Downeast’s ongoing effort 

to update and revise its Fishermen Communication, Coordination and Compensation Plan, 

discussed further in section 4.8.2 of this EIS. The Fishermen Communication, Coordination, and 

Compensation Plan was developed by Downeast to address any potential and unavoidable loss of 

fishing equipment or income as a result of Downeast LNG terminal operations.

4.5.2.2 LNG Terminal

The LNG terminal would be located on an 80-acre parcel on the south side of Mill Cove, and the 

pier would extend about 3,862 feet northeastward into Mill Cove. Mill Cove is located just south 

of the confluence of Passamaquoddy Bay and the St. Croix River. The Cove area adjacent to the 

terminal is characterized by partially exposed to semi-protected marine conditions. Aquatic 

habitats that exist within the proposed terminal site consist of open water and benthic habitat 
4-103 4.5 – Wildlife and Aquatic Resources

including intertidal and subtidal habitats. The open water habitat includes all waters ranging 

from 16 to 68 feet deep at MSL in the project area. 

Existing Resources 

Benthic habitat community types known to occur in the project area are summarized in 

table 4.5.2.2-1. In general the majority of the intertidal zone within Mill Cove is a mosaic of 

gravelly sand of varying grade sizes, and fairly homogenous pebbly gravel pavement that support 

a number of invertebrate species (see discussion below). Tidal fluctuations in intertidal habitats 

within the vicinity of Mill Cove average about 18 feet. Mill Cove is generally protected from 

strong winds, such that the intertidal area experiences only moderate to low energy wave action. 

The subtidal habitats of Mill Cove are generally characterized by substrate that range from 

pebbly sand to fine mud. Water depths in the subtidal areas of Mill Cove reach a maximum of 

54.7 feet at MSL in the location of the proposed pier. Tidal currents in the project area typically 

range from 0.5 to 1.5 feet per second with a maximum velocity of between 2.5 and 4.0 feet per 

second.

TABLE 4.5.2.2-1

Substrates/Benthic Community Types Observed at the Mill Cove Study Area

(7-11 November 2005) and Associated Maine DEP Rankings

Habitat Location in 

Tidal Range

DEP Habitat 

Ranking Justification Notes

Intertidal 

Ledge Mid Moderate B,C,D,E,F,G,H,K,O,S,Y Mid intertidal ledge supported lush Ascophyllum 

growth. The habitat structure provided by the 

knotted wrack and stable rock substrate, in 

association with the grazing surface provided by 

the ledge added value to this habitat type. 

Mixed Coarse 

and Fines

High, Mid, 

and Low

Low A,E,F,G,H,I,L,O,P,U,Y Gravely sand substrates with various 

concentrations of pebble grade in and out with 

sand flat in the mid intertidal and comprise the 

primary grain size class in the narrow, low 

intertidal. Mussels, amphipods, and barnacles 

were observed in this habitat. This substrate was 

primarily unvegetated. 

Sand Flat Mid High A,B,C,D,E,F,G,H,I,J,L,O,P,T Sandy substrates with very little gravel supported 

moderate densities of soft-shelled clams. 

Subtidal

Unconsolidated 

Sediments

Shallow 

subtidal

High A,B,C,D,E,F,G,H,I,J,L,R,T,U,Y,AA Mud with varying amounts of fine pebble gravel 

characterized most of the subtidal sites observed. 

Justifications

A Nursery ground for commercial species O Foraging areas for shorebirds and/or wading birds

B Primary production/oxygen production P Shorebird roosting and/or staging areas 

C High diversity Q Supports terrestrial birds 

D High primary and secondary production R Supports terrestrial mammals 

E Shelter S Reduces coastal erosion

F Structure for attachment of settling larvae T Supports commercial fisheries 

G Food resources for one or more functional groups U Supports lobster fishery 

H Variety of functional groups represented V Supports tourism industry 

I Sediment and nutrient sink and/or source W Geographically isolated and rare populations of species

J Nutrient recycling X Haul out and pupping sites for gray and harbor seals 

K Production and export of detritus Y Foraging area for waterfowl and/or seabirds 

L Habitat dependent species Z Nesting habitat for endangered birds 

M Rare or endangered animals AA Supports anadromous fish 

N Rare or endangered plants 
4.5 – Wildlife and Aquatic Resources 4-104

Table 4.5.2.2-1 also identifies the habitat function and value classification, as designated by 

Maine DEP guidance (Ward 1999). Habitat rankings range from low to high for the intertidal 

substrate types located within the study area. Sand flat substrates located in the mid intertidal 

generated the highest possible ranking. These areas contribute to the overall 2.1 acres of 

intertidal substrate in the study area identified as gravelly sand mixtures. Sand flat at this site 

was observed to support at least one commercially important species, the soft-shelled clam. The 

actual footprint of the pier would only occupy a small percentage of this area.

Vegetated ledge, which comprised about 15 percent (1 acre) of the intertidal study area’s aerial 

coverage, garnered a moderate value ranking. The balance of the coarser gravelly sand grades 

fall under the “mixed coarse and fines” Maine DEP designation and is assigned a low value 

ranking by Maine DEP. Fairly uniform pebble substrate in the mid intertidal comprised 0.3 acre, 

or 3.9 percent of the study area, and also falls under the Maine DEP designation “mixed coarse 

and fines.” The actual footprint of the pier would only occupy a small percentage of this area.

Subtidal substrates ranging from gravelly sand (very shallow subtidal) to various grades of mud 

that dominate the study area are designated as unconsolidated sediments by Maine DEP criteria 

and are ranked as having a high value.

The intertidal and subtidal zones associated with the terminal area supports sparse populations of 

knotted wrack and kelp, which provides an important source of food for sea urchins and 

gastropods, as well as habitat for fishes and invertebrates. Eelgrass (Zostera marina) was not 

observed during surveys conducted by Downeast, and has not historically been mapped in Mill 

Cove. However, eelgrass mapping completed in 2010 by Maine DMR identified eelgrass beds in 

Mill Cove that were not previously identified by Maine DMR mapping efforts (see 

section 4.4.2.1).

Both the benthic and open water habitats associated with the terminal project area support a 

number of marine aquatic resources. These resources are discussed in further detail below. No 

freshwater fishery resources are associated with the proposed terminal site. Marine vegetation is 

discussed further in section 4.4 of this EIS.

Invertebrates

Benthic sampling was performed in November 2005 by Downeast at 49 locations (14 intertidal 

locations and 35 subtidal locations) within the proposed terminal location, in accordance with 

Maine DEP guidelines (Ward 1999). Additional benthic video surveys also were conducted in 

August, September, and October of 2007 and March of 2008. The surveys covered a total of 

approximately 18,100 meters (18.1 kilometers) around the immediate vicinity of the proposed 

pier, the general area of Mill Cove normally fished for lobsters, and specific areas where 

oversized and small lobsters reportedly have been found. The specific emphasis of the studies 

was the areas adjacent to an abandoned weir to the south of the proposed pier and along an active 

herring weir in the center of Mill Cove north of the proposed project site. Benthic video surveys 

were conducted in accordance with Maine DMR guidelines. 

In the intertidal areas, the substrate consisted of sandy pebbly gravel/gravelly sand and ledge. 

Species observed in the lower intertidal areas included amphipods, blue mussels, northern rock 

barnacles (Semibalanus balanoides), and periwinkles (Littorina littorea). Species observed in 

the mid intertidal areas included the northern rock barnacles and periwinkles, soft-shelled clams, 
4-105 4.5 – Wildlife and Aquatic Resources

and several species of polychaete. The high intertidal areas included only a species-poor worm 

community. 

Substrate in the subtidal area between 1.5 to 25 feet mean lower low water (MLLW) ranged from 

gravelly sand to mud. Mussels and periwinkles were present on coarser substrates, and mud 

supported amphipod/worm burrows, cerianthid anemones (Cerianthus borealis), erect 

ectoprocts, moon snails (Nacticidae), tubularian hydroids (Tubularia spp.), northern sea scallops 

(Placopecten megellanicus), American lobster (Homarus americanus), and crab (Cancer spp.).

Substrates in the subtidal area between 26 to 50 feet MLLW were gravelly mud and fine mud. 

Species in this area included sponges, fringed anemone (Metridium senile), red-gilled nudibranch 

(Flebellina sp.), orange-footed cucumber (Cucumaria frondosa), stalked tunicate (Boltenia 

ovifera), green sea urchin (Strongylocentrotus droebachiensis), American lobster, cancer crabs, 

sea vase (Cliona intestinalis), sculpin (Myoxocephalus spp.), and mysid shrimp (Mysidacea). 

Patchy stalked tunicate “meadows” supporting individual Boltenia were also observed at two 

locations in this zone. Substrate in the subtidal area between 51 to 81 feet MLLW was fine mud. 

Infaunal sampling in this area indicated a species richness that was similar to that observed in 

water depths ranging from 26 to 50 feet MLLW. 

A number of the invertebrate species found within the proposed project area are of commercial 

and/or recreational importance, including sea scallops, lobsters, soft-shelled clams, periwinkles, 

and blue mussels. These species are discussed in further detail below.

Several of the species found within Mill Cove are considered invasive exotic species, including 

the green crab (Carcinus maenas) and the common periwinkle.

Pelagic and Demersal Finfish

There are about 500 species of fish found in coastal Maine and nearby Canada, not including 

37 species of cartilaginous fish (sharks, skates, rays, and chimaeras). These fish can be generally 

grouped into demersal or groundfish—those occurring on or close to the bottom including such 

species as cod, haddock, and pollock; and pelagic—those occurring in the water column usually 

away from the bottom including such species as herring and mackerel. 

Most information about finfish resources in Passamaquoddy Bay and Mill Cove is dated; 

however, studies conducted by Tyler (1971) at locations near the proposed project area give 

insight into the abundance and seasonality of the finfish species likely to occur in the project 

area. These representative demersal and pelagic finfish species are identified in table 4.5.2.2-2. 

As noted in table 4.5.2.2-2, a number of these demersal and pelagic species are of commercial 

and/or recreational importance. These species are discussed in more detail below.

Migratory Finfish Species

Anadromous fishes generally spawn in freshwater and mature in marine waters. Anadromous 

fish would ascend rivers and streams, typically in the late-winter and spring, and spawn in 

freshwater above the head of tide. Depending upon the species and the life stage, migratory fish 

tend to travel at different positions within the water column, move at different times of the day, 

and may or may not overlap with other migratory species. The typical pattern is for a springtime 

adult in-migration and a fall out-migration of juveniles. 
4.5 – Wildlife and Aquatic Resources 4-106

TABLE 4.5.2.2-2

Representative Finfish and Invertebrate Species Known to Occur in the Project Area

Common Name

(Scientific Name)

Commercial

Fishery

Recreational

Fishery Anadromous Catadromous

Threatened 

or 

Endangered

Finfish Species

Alewife (Alosa pseudoharengus) X X

Alligator fish (Aspidophoroides monopterygius)

American Eel (Anguilla rostrata) X X

American Plaice (Hippoglossoides platessoides)

American Shad (Alosa sapidissima) X X

Atlantic Cod (Gadus morhua) X

Atlantic Mackerel (Scomber scombrus)

Atlantic Salmon (Salmo salar) X X

Atlantic Herring (Clupea harengus harengus) X

Atlantic sea raven (Hermitripterus americanus)

Atlantic tomcod (Microgadus tomcod)

Blueback Herring (Alosa aestivalis) X X

Daubed Shanny (Leptoclinus maculates) X

Fourbeard rockling (Enchelyopus cimbrius)

Grubby (Myoxocephalus aenaeus)

Haddock (Melangerammus aeglefinus)

Longhorn sculpin (Myoxocephalus octodecemspinosa) X

Lumpfish (Cyclopterus lumuis)

Ocean Pout (Macrozoarces americanus)

Pollock (Pollachius virens)

Rainbow Smelt (Osmerus mordax) X X X

Redfish (Sebastes sp.)

Shorthorn sculpin (Myoxocephalus scorpius) X

Silver Hake (Merluccius bilinearis)

Winter Flounder (Pleuronectes americanus) X

Yellowtail Flounder (Pleuronectes ferruginea)

Cartilaginous Finfish Species

Little Skate (Leucoraja erinacea)

Smooth Skate (Malacoraia senta)

Thorny Skate (Amblyraja radiate)

Spiny Dogfish (Squalus acanthias) X

Winter Skate (Leucoraja ocellata)

Invertebrate Species

American Lobster (Homarus americanus) X

Blue Mussel (Mytilus edulis)

Deep Sea Scallop (Placopecten magellanicus) X

Northern Sea Scallops (Placopecten magellanicus) X

Common Periwinkles (Littorina littorea)

Green Sea Urchins (Stronglylocentrotus 

droebachiensis) X

Soft-shelled Clams (Mya arenaria) X

Jonah/Rock Crab (Cancer spp)
4-107 4.5 – Wildlife and Aquatic Resources

As indicated in table 4.5.2.2-2, anadromous fish occurring in the project area include alewife 

(Alosa pseudoharengus), blueback herring (Alosa aestivalis), American shad (Alosa 

sapidissima), and rainbow smelt (Osmerus mordax). The Atlantic salmon (Salmo salar), listed 

as federally endangered, also has the potential to occur in the general vicinity of the Downeast 

LNG Project (see section 4.6 of this EIS). The St. Croix River, located just north of Mill Cove, 

is a significant source of freshwater habitat for many of the migratory fish, and the Western 

Passage represents a major passageway between Passamaquoddy Bay and the northern Gulf of 

Maine. As such, many of the migratory species listed above are likely to migrate past the pier 

during their in- and out-migrations. 

Communication with the St. Croix International Waterway Commission has indicated that the 

migratory striped bass species is known to occur in the waters associated with the project area 

(including both the terminal and the sendout pipeline). However, data and information obtained 

from the Atlantic States Marine Fisheries Commission (ASMFC), Maine DMR, and NOAA 

Fisheries indicated that while striped bass have been caught in the St. Croix River and its 

associated watershed, this species has been historically scarce in the eastern region of Maine. As 

such, it is unlikely that construction or operation of the project would adversely impact striped 

bass.

NOAA Fisheries staff has expressed concern for the blueback herring, currently managed under 

a fisheries management plan (FMP). Historically, blueback herrings have been reported in 

abundance in the waters of the St. Croix River. However, legislation passed in 1995 closed the 

fishway during the spawning season to keep alwives, and consequently bluebacks, out of the 

upper portions of the river, effectively eliminating the run. As a consequence, the alewife run 

(including bluebacks) has gone from about 2.8 million adults in the late 1980s to only 800 to

11,000 in recent years (CFN 2005; Tom Squires DMR). Most recently, in April 2013, Maine 

State Legislature passed a law (LD 72) for fishway barriers to be removed to allow passage of 

spawning alewives. Removal of barriers would also allow for blueback herring to pass up river. 

The blueback herring could occur in the project area during migration. However, because the 

project would not create a barrier to passage up or down the St. Croix River, impacts from the 

construction and/or operation of the project on blueback herring are not anticipated.

Catadromous species spawn in the ocean and then migrate into freshwater locations for growth 

and maturation. The American eel (Anguilla rostrata) is the only true catadromous species that 

may occur within the vicinity of the proposed project area.

Commercial and Recreational Species

As indicated in table 4.5.2.2-2, there are 11 finfish and 5 invertebrate species of commercial 

importance that have historically occurred in the project area. Of these species, the daubed 

shanny (Lumpenus maculates), hake (juvenile), sculpin (Myoxocephalus sp.), short-horned 

sculpin (Myoxocephalus scorpius), and winter flounder (Pleuronectes americanus) were 

observed in the subtidal areas of the project site during site surveys conducted in January 2006. 

Two fishing weirs for Atlantic herring are located in the immediate vicinity of the proposed 

project. One of these, located immediately north of the proposed pier site, appears to be in 

functional condition while the southern of the two is apparently abandoned and in disrepair. 

Despite the cyclical nature of this fish species, fishing weirs in the Cove have experienced a 

significant decline in catch for many years (Morrison 2006). Both hake (white and red) and 
4.5 – Wildlife and Aquatic Resources 4-108

winter flounder are considered species with EFH within Passamaquoddy Bay. Detailed 

descriptions of these species, as well as an analysis of impacts to habitat for these species, as 

requested by NOAA Fisheries, is included in the EFH Assessment (Appendix G).

Winter flounder is one of the most common shoalwater flounder in the Gulf of Maine and all life 

history stages are prevalent in the saltwater and brackish water mixing zones within 

Passamaquoddy Bay. Adult winter flounder occur in depths ranging from 1 to 100 meters, and 

salinities between 15 and 33 ppt. Spawning winter flounder adults are found in waters with 

temperatures below 15°C, depths less than 6 meters and salinities between 5.5 and 36 ppt. 

Spawning occurs in January through May, the optimal temperature being 3.3°C to 5.6°C and 

optimal salinity 11 to 33 ppt. Temperature dependent migration occurs, although food 

availability may also be a factor (Pereira et al. 1999). Flounder eggs tend to occur in waters with 

temperatures less than 10°C, water depths less than 5 meters, and salinities between 10 and 

30 ppt; eggs are often observed from February to June. Winter flounder larvae are often 

observed from March to July. Young-of-the-year occupy bottom habitats with a substrate of 

mud or fine grained sand, within waters where the temperature is below 28°C, depths from 0.1 to 

10 meters, and salinities ranging between 5 and 33 ppt. Age 1-plus juvenile are found in inshore 

areas in waters with temperatures below 25°C, depths from 1 to 50 meters, and salinities between 

10 to 30 ppt.

Potential impacts on winter flounder near the terminal include construction related lighting, 

noise, increased sedimentation and turbidity associated with pile driving and hydrostatic testing 

of storage tanks, as well as operational impacts including entrainment/impingement of juvenile 

winter flounder during LNG vessel ballast water uptake or engine cooling, shading from the 

trestle and platform, and loss of eelgrass habitat. Installation of the pier would disturb and 

occupy a very limited area (4,885.5 square feet or 0.1 acre) of bay floor, removing only a 

selected portion of the benthic community immediately underlying and/or adjacent to each pile. 

Additionally, as described in section 4.3.2.1, suspended sediments from pile driving does not 

typically result in the release of a substantial amount of sediment into the water column. The 

proposed LNG terminal is in an area known to be utilized by winter flounder for spawning and 

feeding. Comment letters during the scoping process have expressed concern for winter flounder 

adults, juveniles, and larvae near the LNG terminal. Operational impacts are discussed in greater 

detail below. Impacts on winter flounder in the project area would be similar to those detailed 

for all EFH species in Appendix G.

Other commercial species of importance known to occur in the vicinity of the project area 

consist of invertebrate species, including American lobster, green urchins, soft-shelled clams, 

and sea scallops. Interviews with local fishermen indicate that many of the commercial fisheries 

in Mill Cove have declined in recent years. In addition, as of January 17, 2007, Maine DMR 

closed the northwest portion of Mill Cove to the harvest of clams, quahogs, oysters, mussels, and 

other marine mollusks because of pollution. Despite this decline, lobstering in Mill Cove is 

currently still active. According to local fishermen, there are six to eight lobstermen who fish the 

area between Perry and Calais on a regular basis, and two to three lobstermen who set traps 

regularly near Mill Cove (Morrell 2006). According to Town of Robbinston officials, there are 

only two lobstermen who regularly lobster the Mill Cove area setting up to 15 to 30 traps in and 

near the Mill Cove area (Stanhope 2005; Moholland 2005; Morrell 2006). During a trap survey 

conducted October 1, 2006, eight lobster traps were observed within Mill Cove near the northern 
4-109 4.5 – Wildlife and Aquatic Resources

fishing weir and an equal number were set immediately outside of Mill Cove in the main 

waterway. 

Site-specific information regarding the overall abundance of lobster and value of the associated 

fishery in Mill Cove as well as the greater Passamaquoddy and Cobscook Bays currently is not 

well characterized (Maine DMR 2007). However, in the last 10 years, both the population and 

fishery have experienced a period of rapid growth. In 2012, new lobster regulations for the Gulf 

of Maine regulated the maximum number of traps (800) per permit and instituted a limited entry 

program for the fishery (50 CFR Part 697). This rule effectively sustains fishing effort at current 

levels to prevent growth of the fishery that could lead to overfishing. Lobstering currently 

accounts for nearly 75 percent of the value of Maine’s marine resources and according to the 

Maine DMR, greater than 50 percent of the recent increase in lobster trap tags issued in the last 

10 years has been in the zone that encompasses the proposed project area. Given stakeholder 

concern for potential project impacts on the lobster fishery in Mill Cove, which local fishermen 

have indicated is a significant habitat for juvenile and egg-bearing lobsters, Downeast initiated 

an extensive monthly benthic video monitoring survey to assess overall fisheries composition, a 

lobster trapping study to investigate local lobster population size and composition, and a lobster 

tagging study to track the movements of lobsters within Mill Cove and beyond. A detailed 

description of these surveys can be found in Appendix O. These subtidal studies and functional 

assessments were conducted in August, September, and October of 2007 and March, May, June, 

July, and September of 2008, in accordance with the Survey Requirements for Proposed 

Dredging in Subtidal Areas developed by the Maine DMR. Video surveys covered 

approximately 38,330 meters (38.3 kilometers) in the general area of Mill Cove and points both 

north and south normally fished for lobsters and specific areas where oversized and small 

lobsters have been reportedly found, with emphasis on the areas adjacent to an abandoned weir 

to the south of the proposed pier and along an active herring weir in the center of Mill Cove 

north of the proposed project site. The survey area is shown in figure 4.5-1.

Maine DMR guideline density for important lobster habitat is 0.1 lobster/m2. The largest 

concentrations of lobsters found within the study area running from Active Weir 2 at the south 

to Red Beach at the north are generally found in association with weirs (Active Weir 1 [up to 

0.190 lobster/m2], Active Weir 2 [up to 0.190 lobster/m

2

], Abandoned Weir Mill Cove [up to 

0.160 lobster/m2], and in the vicinity of Loring Cove [up to 0.142 lobster/m2]). The high lobster 

density found in the rock/boulder habitat in the vicinity of Loring Cove is consistent with the 

higher fishing effort (larger number of traps) observed in this area compared to the other sections 

of the shoreline. In 2007 and 2008, video surveys indicated that lobsters observed at the 

abandoned weir south of the proposed pier are predominantly large or oversized, eggbearing 

females. Lobsters observed over firmer rock and cobble substrate along the north shoreline of 

Mill Cove are generally small, juvenile lobsters usually found under rocks. Lobsters observed 

along the Perry shoreline are of varying sizes, although these are generally large lobsters and 

when found around weirs are large, oversized, reproductive lobsters (primarily eggbearing 

females) similar to the population found at the abandoned weir in Mill Cove.
Figure 4.5-1 

Downeast LNG Project

Mill Cove Lobster Survey Area

4-110
4-111 4.5 – Wildlife and Aquatic Resources

Downeast also conducted a lobster trap study in Casco Bay in September 2007 and in Mill Cove 

between September and October 2007 and again between August and November 2008. Survey 

design included standard commercial lobster traps, modified traps (small mesh and closed vents), 

and oversized traps. Despite the relatively short survey period in Casco Bay, the number of 

lobsters caught (433 lobsters), as well as the catch per unit effort (3.7 lobsters/trap haul) in the 

Bay, was significantly greater than the total numbers caught (239 lobsters) and catch per unit 

effort (0.54 lobsters/trap haul) over the study period in Mill Cove (see table 4.5.2.2-3).

Downeast is also conducting an ongoing lobster tagging study of lobsters caught in the study 

traps to determine species movement and sight fidelity. All lobsters caught in the 2007 and 2008 

study traps were tagged with a yellow rubber band, bearing an ID number and reporting phone 

number, applied to the “knuckle” (joint) below the right-hand claw. In over-sized lobsters, 

however, when the band could not be stretched enough to go over the claw, the band was applied 

to a tail fin, or uropod, usually second from right. Two banded lobsters were recaptured and 

reported in 2007: #22, a female lobster weighing approximately 1.3 pounds, caught on 

September 30 just north of Loring Cove, and #62, a male lobster weighing approximately 

1.5 pounds, caught on December 30 off of the “factory” in Robbinston. No lobsters were 

reported recaptured in 2008.

No tags were applied in 2009. In 2010 the yellow bands were replaced with Stoffel Seal 

EQUILOX seals. Different colors were used to identify lobsters caught along the shoreline, each 

color corresponding to a section of the Western Passage to Red Beach and the St. Croix River 

shoreline. However, fishing activities were focused on the area between (from north to south) 

McCurdy Point and Lewis Cove. As a result, only yellow and green tags were deployed. Four 

tagged lobsters were re-captured within the study area during 2010 sampling. 

Additionally, a sonar tagging program was started in 2010 to apply sonar transmitting tags on 

selected large reproductive lobsters from the abandoned weir population in Mill Cove. These 

tags are tracked using either portable or fixed receivers to study short-distance movement 

behavior of the lobsters for further determination of habitat fidelity. A total of 10 lobsters 

consisting of six females, four of which were egg-bearing, and four males, all ranging in size 

from 123 mm to 202 mm carapace length (CL), were collected by a SCUBA diver, tagged, and 

released to their original location on August 25, 2010. Data from the remote sensing buoy were 

downloaded on nine occasions between September 2, 2010 and November 12, 2010. Manual 

tracking was conducted on eight occasions between September 2, 2010 and December 10, 2010.

The tagged lobsters initially showed no consistent behavior with respect to movement, depth, 

temperature, or time of departure from the immediate vicinity of the abandoned weir. However, 

when water temperature had dropped to near 120C in October 2010, all detected lobsters were 

found in progressively deeper water ranging between 20 meters (66 feet) and nearly 73 meters

(240 feet) in depth. Distance traveled also varied considerably. Based on the final position for 

all lobsters, the four lobsters last detected within the vicinity of Mill Cove had traveled an 

average distance of 1.4 kilometer from the initial point of tagging with a range of 440 meters to 

1.64 kilometer; it should be noted that only one of these lobsters was found to be remaining in 

the vicinity of Mill Cove on the last detection date, December 10, 2010.
4.5 

– Wildlife and Aquatic Resources

4-112

TABLE 4.5.2.2-3

Lobster Catch Data and Indices for Mill Cove with Comparison Catch Data from Casco Bay

Legals Subleg Notched Egged Total # traps #/trap 

haul

Nite

set

#/trap 

haul/n-s Lgl/trap Sub/trap N-E/trap M F M-F % M:F

Mill Cove Haul Data Summary

9/10/07 1 4 0 0 5 24 0.21 1 0.21 0.042 0.167 0.000 2 3 40.0% 60.0% 1.0 1.5 

9/11/07 2 9 0 0 11 23 0.48 1 0.48 0.087 0.391 0.000 7 4 63.6% 36.4% 1.0 0.6 

9/12/07 4 5 0 0 9 23 0.39 1 0.39 0.174 0.217 0.000 6 3 66.7% 33.3% 1.0 0.5 

9/19/07 6 6 0 0 12 27 0.44 7 0.06 0.222 0.222 0.000 8 4 66.7% 33.3% 1.0 0.5 

9/26/07 8 2 0 0 10 25 0.40 7 0.06 0.320 0.080 0.000 7 3 70.0% 30.0% 1.0 0.4 

10/4/07 6 3 0 0 9 26 0.35 8 0.04 0.231 0.115 0.000 6 3 66.7% 33.3% 1.0 0.5 

10/10/07 7 2 0 0 9 26 0.35 6 0.06 0.269 0.077 0.000 7 2 77.8% 22.2% 1.0 0.3 

10/17/07 4 8 1 0 13 25 0.52 7 0.07 0.160 0.320 0.040 8 5 61.5% 38.5% 1.0 0.6 

10/29-31/07 6 2 0 0 8 34 0.24 12 0.02 0.176 0.059 0.000 4 4 50.0% 50.0% 1.0 1.0 

All dates 44 41 1 0 86 233 0.37 5.6 0.15 0.191 0.178 0.004 55 31 64.0% 36.0% 1.0 0.6 

8/23/08 32 0 6 6 32 24 1.33 6 0.22 1.33 0.00 0.25 16 16 50.0% 50.0% 1.0 1.0

8/30/08 16 8 7 7 24 24 1.00 7 0.14 0.67 0.33 0.29 8 16 33.3% 66.7% 1.0 2.0

9/6/08 11 7 6 6 18 22 0.82 6 0.14 0.50 0.29 0.27 7 11 38.9% 61.1% 1.0 1.6

9/13/08 11 16 5 5 27 23 1.17 7 0.17 0.48 0.67 0.22 13 14 48.1% 51.9% 1.0 1.1

9/20/08 15 8 7 7 23 23 1.00 7 0.14 0.65 0.33 0.30 9 14 39.1% 60.9% 1.0 1.6

10/11/08 7 7 4 4 14 24 0.58 21 0.03 0.29 0.29 0.17 4 10 28.6% 71.4% 1.0 2.5

10/19/08 6 5 3 3 11 24 0.46 16 0.03 0.25 0.21 0.13 5 6 45.5% 54.5% 1.0 1.2

11/5/08 2 1 0 0 3 24 0.13 16 0.01 0.08 0.04 0.00 2 1 66.7% 33.3% 1.0 0.5

11/11/08 0 1 0 0 1 24 0.04 6 0.01 0.00 0.04 0.00 1 0 100.0% 0.0% 1.0 0.0

All dates 100 53 38 38 153 212 0.72 10.2 0.10 0.47 0.25 0.18 65 88 42.5% 57.5% 1.0 1.4

7/3/2010 16 6 0 2 25 81 0.31 - - 0.20 0.07 0.00 12 13 48.0% 52.0% 1.0 1.1

7/10/2010 19 3 0 2 25 82 0.30 6 0.05 0.23 0.04 0.00 14 11 56.0% 44.0% 1.0 0.8

7/17/2010 18 2 1 0 22 83 0.27 6 0.04 0.22 0.02 0.01 14 8 63.6% 36.4% 1.0 0.6

7/24/2010 41 6 0 0 47 82 0.57 6 0.10 0.50 0.07 0.00 28 19 59.6% 40.4% 1.0 0.7

7/31/2010 62 6 1 3 72 86 0.84 6 0.14 0.72 0.07 0.01 46 26 63.9% 36.1% 1.0 0.6
4-113 4.5 

– Wildlife and Aquatic Resources

4-113

TABLE 4.5.2.2-3

Lobster Catch Data and Indices for Mill Cove with Comparison Catch Data from Casco Bay

Legals Subleg Notched Egged Total # traps #/trap 

haul

Nite

set

#/trap 

haul/n-s Lgl/trap Sub/trap N-E/trap M F M-F % M:F

8/7/2010 84 7 0 0 91 83 1.10 6 0.18 1.01 0.08 0.00 59 32 64.8% 35.2% 1.0 0.5

8/14/2010 114 5 3 2 124 80 1.55 6 0.26 1.43 0.06 0.04 72 52 58.1% 42.0% 1.0 0.7

8/21/2010 140 13 0 6 160 81 1.98 6 0.33 1.73 0.16 0.00 106 54 66.3% 33.8% 1.0 0.5

8/28/2010 102 8 2 7 119 82 1.45 6 0.24 1.24 0.10 0.02 67 52 56.3% 43.7% 1.0 0.8

9/6/2010 105 15 1 16 127 75 1.69 8 0.21 1.40 0.20 0.01 66 61 52.0% 48.0% 1.0 0.9

9/11/2010 113 25 2 7 147 79 1.86 4 0.47 1.43 0.32 0.03 64 83 43.5% 56.5% 1.0 1.3

9/18/2010 108 15 2 3 127 76 1.67 6 0.28 1.42 0.20 0.03 68 59 53.5% 46.5% 1.0 0.9

9/27/2010 82 6 2 4 99 78 1.27 7 0.18 1.05 0.08 0.03 54 45 54.6% 45.5% 1.0 0.8

10/3/2010 52 9 0 2 67 74 0.91 5 0.18 0.70 0.12 0.00 39 28 58.2% 42.0% 1.0 0.7

10/9/2010 50 9 1 3 64 76 0.84 5 0.17 0.66 0.12 0.01 31 33 48.4% 51.6% 1.0 1.1

10/17/2010 49 5 0 3 58 71 0.82 7 0.12 0.69 0.07 0.00 24 34 41.4% 58.6% 1.0 1.4

10/24/2010 33 7 1 6 46 65 0.71 6 0.12 0.51 0.11 0.02 22 24 47.8% 52.2% 1.0 1.1

10/31/2010 21 0 0 0 22 33 0.67 6 0.11 0.64 0.00 0.00 14 8 63.6% 36.4% 1.0 0.6

All dates 1209 147 16 66 1442 1367 1.05 6 0.18 0.88 0.11 0.01 800 642 55.5% 44.5% 1.0 0.8

Comparison Haul Data Summary from Casco Bay

9/20/07 17 150 15 4 182 45 4.0 4 1.01 0.378 3.333 0.333 41 140 22.7% 77.3% 1.0 3.4 

9/21/07 36 197 19 12 252 71 3.5 4 0.89 0.507 2.775 0.268 86 166 34.1% 65.9% 1.0 1.9 

All dates 53 346 34 16 433 116 3.7 4.0 0.95 0.457 2.983 0.293 127 306 29.3% 70.7% 1.0 2.4 
4.5 – Wildlife and Aquatic Resources 4-114

Lobster larvae sampling was conducted on five occasions in 2008 using a surface layer sampling 

neuston net. Over the five sampling events, only two larvae were caught, one Stage I and one 

Stage IV, from the 18,503 m3 of water sampled, yielding a larval density of 0.00011 larva/m3.

We believe the impacts on both the lobster fishery and lobster fishing industry from the 

construction and operation of the LNG terminal in Mill Cove would be relatively minor (see also 

section 4.8.2.5). However, to ensure impacts on the lobster industry are minimized, Downeast in 

cooperation with the Maine DMR is developing a Fishermen Communication, Coordination and 

Compensation Plan, described further in section 4.5.2.1 above, and in section 4.8.2 of this EIS. 

Data does indicate that the area supports numerous large, egg-bearing females. However, video 

transects along the pier vicinity and the expanded area beyond the pier resulted in average linear 

densities of 0.003 and 0.032 lobsters per 100 meters, respectively. Habitat within the footprint of 

the pier would be permanently altered where pilings are installed; however, it is expected that 

such impact would be minor and that lobsters, being highly mobile, would continue to utilize 

Mill Cove after construction and throughout the operational life of the proposed facilities. 

Because Downeast has not yet finalized its Fishermen Communication, Coordination and 

Compensation Plan; we recommend that:

• Downeast should continue to consult with NOAA Fisheries, Maine DMR, other 

appropriate agencies, and appropriate representatives of the local lobster fishery to 

determine impacts on the local lobster population and any recommended 

mitigations to minimize impacts on lobster and lobster habitat during all proposed 

construction and operational activities at the LNG terminal. Prior to the start of 

construction of the LNG terminal facilities, Downeast should file with the Secretary,

for review and written approval by the Director of OEP, its final Fishermen 

Communication, Coordination and Compensation Plan, including copies of its 

correspondence with consulted agencies and a description of any mitigation

measures it has agreed to implement.

When this information is filed with the Commission, FERC staff will consult with respective 

agencies as needed during its review.

Finfish aquaculture and the harvesting of marine worms is also an important commercial activity 

within the vicinity of the project area, in particular along the United States/Canadian border of 

the proposed LNG marine traffic route. These commercial activities are discussed in greater 

detail in see section 4.5.2.1 of this draft EIS.

To date, the extent of recreational fishing activities within Mill Cove and the project area are not 

well quantified; however, observations of the site by Downeast from 2004 to October 2006 

indicate that recreational activity is extremely limited, likely due to the large extent of the 

intertidal area exposed at low water and the strong tidal currents at the site. Downeast confirmed 

these observations with town representatives. Of the 39 species identified in table 4.5.2.2-2 that 

could potentially occur in the vicinity of the project, Atlantic cod, Atlantic mackerel, Atlantic 

salmon, haddock, pollock, shad, and winter flounder are among the species generally known to 

be targeted by recreational fishermen in other coastal Maine waters.
4-115 4.5 – Wildlife and Aquatic Resources

Zooplankton and Ichthyoplankton

The zooplankton community comprises a diverse assemblage of essentially microscopic freefloating animals, with most marine invertebrate phyla represented as eggs, larvae, or adults. 

Zooplankton feed on phytoplankton, detritus, and other zooplankton, and provide a link between 

the primary production of the ocean (i.e., phytoplankton) and the higher trophic levels in the food 

web. Predators of zooplankton include fish, shellfish, whales, and other zooplankton. Most 

zooplankton are capable of movement within the water column and some species show a strong 

diurnal vertical migration in and out of the photic zone, while others tend to augment wind and 

tidal currents by “swimming” to move laterally throughout bays and coastal environments. 

Within the Gulf of Maine region, seasonal zooplankton cycles are related primarily to 

fluctuations in temperature, rather than light and nutrients, as is the case for phytoplankton 

(Kropp et al. 2003). Zooplankton abundances are highest in mid-summer, lower in the spring 

and fall, and typically reach lowest levels in late winter, with variable seasonal trends for 

individual species. 

The Maine DMR currently does not monitor zooplankton within the immediate Downeast project 

area. The nearest sampling station for zooplankton is located in the vicinity of Grand Manan 

Island located at 44o55’48”N, 66o51’00”W (approximately 15 miles southeast of the project area) 

and is maintained by the Canadian Department of Fisheries and Oceans (DFO) as part of its 

Atlantic Zone Monitoring Program (AZMP). Based on a review of the data collected at this 

station from 1999 through 2002, the four-year mean zooplankton abundance is 1,579/m3. 

Copepod mean density is 1,230 per m3 of which Calanus finmarchicus, an important contributor 

to the annual zooplankton biomass cycle and highly abundant copepod species, comprises 

5 percent. 

In addition to invertebrate zooplankton, the planktonic eggs and larvae of many fish species, 

known as ichthyoplankton, also make up a portion of the plankton community within the project 

region. Existing data on ichthyoplankton composition, distribution, and abundance in 

Passamaquoddy Bay are sparse. Currently, the Maine DMR does not conduct ichthyoplankton 

monitoring within Cobscook Bay, Western Passage, or the area within Passamaquoddy Bay. The 

Maine DMR does, however, include ichthyoplankton monitoring as part of its annual inshore 

trawl survey. The proposed terminal is approximately 22 miles from the nearest Maine DMR 

sampling location off of Gouldsboro Bay and within Grand Manan Channel. 

Downeast conducted on-site sampling for ichthyoplankton and zooplankton from October 2006 

through November 2008. Following Maine DMR protocols, preliminary sampling tows were 

made during the day at low tide and high tide and at night during low tide, both at 30 to 35 feet, 

coinciding with the anticipated ship seawater intake depth, and as composites of bottom, mid, 

and surface depths. Results of preliminary on-site sampling conducted in October 2006 indicate 

fish larvae are present predominantly at night with Atlantic herring being the dominant fish 

larvae at a nighttime density (averaged between the target and composite depths) of 

0.128 larvae/m3 (97.0 percent of all larvae), very similar to the density of 0.123 larvae/m3

(89.8 percent of all larvae) found by Maine DMR during their above-mentioned trawl survey 

efforts conducted in October 2001. The similarity of these results to the previous Maine DMR 

inshore trawl survey sampling suggests that the Maine DMR Region 5 data may be substantially 

representative of the Passamaquoddy Bay area. 
4.5 – Wildlife and Aquatic Resources 4-116

Additional on-site sampling was conducted in February, May, August, September, and October 

of 2007 and February, June, July, August, and November of 2008 in accordance with a sitespecific Ichthyoplankton and Zooplankton Sampling Protocol developed in coordination with 

NOAA Fisheries and the EPA, and submitted by MER Assessment Corporation to Downeast in 

January 2007 in anticipation of implementation of the protocol in February 2007 (see 

Appendix O for a copy of the protocol). 

Results of the on-site ichthyoplankton sampling, as summarized in the Interim Report (see 

Appendix O), indicate that fish larvae are most abundant predominantly in the afternoon samples 

with zooplankton most abundant during nighttime sampling. Fish larvae species assemblages 

were variable throughout the year with snake blenny (Lumpenus lampretaeformis) and winter 

flounder (Pseudopleuronectes americanus) being the dominant larval species in spring, the 

radiated shanny (Ulvaria subbifurcata) in summer, the fourbeard rockling (Enchelyopus 

cimbrius) and Atlantic herring (Clupa harengus) in the fall, and Atlantic seasnail (Liparis 

atlanticus) dominant in winter. In general, zooplankton species composition also varied by 

season with copepods being dominant in all seasons. Spring abundance was highest for calanoid 

copepods and crustacean larvae. This pattern continued through summer where abundance of 

most copepods was much greater (two to four times) in late summer. During fall, copepods 

again became the dominant species. In winter, abundance was considerably less than previous 

seasons; however, copepods were most abundant. 

Detailed results of the ichthyoplankton and zooplankton sampling efforts, conducted in 

accordance with the sampling plan through November 2008, as reported by Downeast’s Interim 

Report, can be found in Appendix O. 

Marine Mammals and Sea Turtles

Several marine mammals and sea turtles have been identified as occupants or migrants within the 

waters where LNG vessels would be docked. Specifically, harbor seals, gray seals, and harbor 

porpoise are considered year-round residents in Passamaquoddy Bay, as well as islands and 

coastline of the surrounding areas, and are likely to be present in the vicinity of the proposed 

terminal. Other species of marine mammals are not expected to occur within Mill Cove; 

however, transient individuals could use areas adjacent to the proposed terminal pier. 

Threatened and endangered species as well as those protected by the MMPA that could occur in 

the vicinity of the pier are discussed in section 4.6 of this EIS. 

Leatherback turtles are known to inhabit the waters of Passamaquoddy Bay and the Bay of 

Fundy during the summer and fall (typically June through October) and could be affected by the 

construction and operation of the Downeast LNG terminal. This species of sea turtle is currently 

listed as endangered by both the United States and Canada. Information regarding this species, 

including potential impacts and proposed mitigation measures associated with the project, are 

discussed in section 4.6 of this EIS.

Construction Impacts 

Turbidity

Construction of the LNG terminal would involve the installation of the pier and berthing 

facilities within Mill Cove. Organisms in the vicinity of the proposed project area would be 

affected by construction activities. Specifically, pier construction could contribute to water 
4-117 4.5 – Wildlife and Aquatic Resources

quality degradation through increased turbidity. The resuspension of sediments during pier 

installation activities, including propeller wash from construction vessels, could cause increased 

turbidity resulting in reduced light penetration and hence reduction in primary productivity. 

Turbidity can also cause an increase in biological oxygen demand resulting in decreased 

dissolved oxygen concentrations available to fish in and around the affected area. Low dissolved 

oxygen concentrations can also negatively affect organisms that are an important resource base 

in fish habitat. Turbidity would reduce visibility thus affecting the ability of sight feeders to 

locate prey. Those organisms in the immediate footprint of the pier piles with little or no 

mobility would suffer some mortality. Filter feeding organisms may experience clogging from 

construction-related suspended sediment. Finfish may also experience similar gill clogging 

effects; however, this should be a relatively minor impact given the tidal flushing in the area. 

Noise

Noise generated from tugboats, operation of barge-mounted equipment, and pile driving during 

LNG terminal construction could affect fish, marine mammals, pinnipeds, and sea turtles if 

present during construction activities. Section 4.6.2 of this EIS further describes noise impacts 

on listed species and marine mammals. Section 4.11.2 of this EIS provides additional discussion 

of some of the basic acoustics associated with underwater noise and discusses Downeast’s 

underwater acoustic modeling analysis. In a filing with the Commission on May 3, 2013 

Downeast stated that based on current design and engineering the project could be constructed 

using only vibratory hammering for pile driving, and committed to the singular use of vibratory 

hammering for the installation of piles. Use of vibratory hammering, rather than impact

hammering, would reduce underwater noise (see section 4.11.2). 

Sounds of short duration that are produced intermittently or at regular intervals, such as sounds 

from pile driving, are classified as "pulsed." Sounds produced for extended periods, such as 

sounds from generators, are classified as "continuous." Although continuous noise sources 

(tugboats, operation of diesel-powered construction equipment) have the potential to elicit 

certain behavioral effects to marine species, it is impact pile driving that has the greatest 

potential to cause harassment or injury through generation of intense underwater sound pressure 

waves. Large diameter steel pipe piles are anticipated to be used to support the trestle and 

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

top of the underlying rock. Driving hollow steel piles with impact hammers produce intense, 

sharp spikes of sound that can easily reach levels that injure fish. Conversely, vibratory 

hammers produce sounds of lower intensity, with a rapid repetition rate. 

In discussing the impacts of sound on aquatic resources, it is important to note the difference in 

sound intensity in air versus water. Sound intensity in air uses a standard of 20 micropascals 

(μPa), while sound intensity measured in water uses a standard level of 1 μPa. Sound sources 

are typically presented as sound pressure levels at a distance of 1 meter from an idealized point 

source, i.e., decibels (dB) re 1 μPa at 1 meter.

The intensity of the sound pressure levels produced during pile driving depends on a variety of 

factors including, but not limited to, the type and size of the pile, the firmness of the substrate 

into which the pile is being driven, the depth of water, the type and size of the pile-driving 

hammer, and the geometry and boundaries of the surrounding underwater environment. During 

impact pile driving, the maximum in-air sound levels upon impact can range from 105 to 
4.5 – Wildlife and Aquatic Resources 4-118

115 dBA at 50 feet. The sound frequency generated upon impact is typically 9 kilohertz. In 

water, the frequency component of pile driving varies with principal energy found in the 200 to 

400 Hz range. Impact pile driving source levels well in excess of 200 dB (re: 1 μPa) at 1 meter 

have been documented from similar construction projects. 

Although the effects of pile driving are poorly studied and there appears to be substantial 

variation in a species’ response to sound, intense sound pressure waves can change fish behavior 

or injure/kill fish through rupturing swim bladders or causing internal hemorrhaging (NOAA 

Fisheries 2005; Hastings and Popper 2005). Potential effects of noise on marine mammals 

include masking, disturbance (behavioral), hearing impairment, and non-auditory physiological 

effects. Noise impacts on marine mammals are discussed further in section 4.6.2 of this EIS and 

the BA. 

The degree to which marine species are exposed to and affected by sound waves is dependent 

upon variables such as the peak sound pressure level and frequency as well as the species and 

size (e.g., small fish appear to be more susceptible to injury by intense sound waves than are 

larger fish of the same species). Short-term exposure to peak sound pressure levels above 

190 dB (re: 1 μPa) are thought to physically harm fish (Hastings 2002). For pulsive sounds, 

NOAA Fisheries requires that individual whales not be exposed to received levels of over 

180 dB re 1 μPa (root mean square) and pinnipeds to levels over 190 dB to protect the animals 

from damaging noise levels. Received levels of over 160 dB may cause disturbance or “Level 

B” harassment. The effects of underwater noise on sea turtles are not well studied. There are no 

safety criteria for sea turtles similar to those used by NOAA Fisheries for marine mammals. 

The presence of predators can also influence how marine species might be affected by pile 

driving (e.g., fish stunned by pile-driving activities may be more susceptible to predators). If 

drilling and/or vibropiling were to occur during anadromous fish migrations, the avoidance of the 

nearshore areas could restrict migrating fish to deepwater areas that are less suitable for some 

species, which could increase the susceptibility of some smaller species to predation.

Unlike fish with swim bladders, or marine mammals with ears, most benthic invertebrates are 

unlikely to be susceptible to tissue damage from most common construction noise levels as the 

energy would pass through their bodies. Marine invertebrates do not hear noise in the same way 

that vertebrates do, rather they detect pressure changes, usually at fairly close range. Sound 

pressure waves passing through the water or sediments may create a localized avoidance 

response in those benthos that are sensitive to disturbance; however, we do not believe it would 

have any adverse impact on populations of marine invertebrates.

Underwater noise during construction activities would be temporary and long-term noise impacts 

are not expected to be significant. Use of vibratory hammers rather than impact hammers would 

reduce the noise impact from pile installation. A “noise-alert” procedure may also be used to 

cause mobile marine species sensitive to the acoustics generated by the pile driving to vacate and 

avoid the immediate area before pile-driving procedures are continued. Additional potential 

mitigation measures include time of year restrictions, bubble curtain systems, caissons, or the 

engagement of a NOAA Fisheries-approved mammal and marine spotter to ensure no sensitive 

species are within the designated NOAA Fisheries Acoustic Safety Zone during construction 

activity. Prior to commencing construction activities, Downeast has stated its EI would search 
4-119 4.5 – Wildlife and Aquatic Resources

the work area for the presence of sea turtles; if a sea turtle were sighted, work would be delayed 

until the EI provided procedures to the work crew to avoid harassment of the animal.

Downeast has consulted with the FWS, NOAA Fisheries, and other relevant federal and state 

agencies to discuss appropriate mitigation measures. Appropriate mitigation measures are also 

part of the FWS and NOAA Fisheries review of the BA. Mitigation measures would be 

implemented during all stages of the project, maximizing protection of the listed species by 

either avoiding adverse impacts, or minimizing the potential for adverse impacts. Downeast has 

proposed that the following mitigation measures be implemented during all stages of the project, 

maximizing protection of the listed species by either avoiding adverse acoustic harassment 

impacts, or minimizing the potential for adverse impacts:

• sound generated by vibratory pile driving would be mitigated by reducing power settings 

on the hammer, and by enclosing the pile(s) within a confined bubble curtain;

• Downeast would determine the effectiveness of mitigated pile driving by modeling sound 

levels throughout the ensonified area and provide an updated isopleth map to NOAA 

Fisheries prior to the issuance of a concurrence letter;

• all pile installation, regardless of technique or equipment would conform to existing 

thresholds for Level A (i.e., sound pressure level of 180 dB RMS re: 1μPa) for injury to 

cetaceans, and Level B harassment (160 dB RMS re: 1μPa) for impulse noise and 

continuous sound (120 dB RMS re: 1μPa) as they pertain to listed marine mammals;

• Downeast would record PEAK sound pressure level and calculate Cumulative Sound 

Exposure Level (CSEL) and Root Mean Squared (RMS) from the SPL waveform and 

report results to our staff on a daily basis;

• during rock socket drilling and pile driving, Downeast would monitor sound pressure 

level (SPL) with hydrophones and a digital recorder capable of operating at a minimum 

of 30,000 samples per second for a minimum of one second, with an adjustable trigger 

level, and a range of at least 30 psi. Based on protocol for measuring in-water acoustic 

fields and natural noise attenuation of 3-6 dB per doubling of distance, a minimum of 

three locations would be monitored, located approximately 10, 20, and 40 meters from 

the sound source;

• an acoustic monitoring plan (e.g., locations, personnel, and equipment) would be 

provided to Max Tritt at the NOAA Fisheries at 17 Godfrey Drive, Suite 1, Orono, Maine 

04473 or to max.tritt@noaa.gov at least 30 days prior to implementation;

• if any listed species are encountered in the action area, FERC and NOAA Fisheries

Maine Field Station would be contacted immediately at (202) 502-6257 and (207) 866-

3756 respectively;

• a post-project report, confirming completion of construction and the successful 

application of all terms and conditions of the permit, would be submitted to NOAA 

Fisheries and to FERC within four weeks of project completion; and

• due to the water depth and vessel draft, the use of ship’s bow thrusters would be

prohibited during low tide when approaching/departing the pier or while docked.

These measures would minimize acoustic harassment impacts on all listed cetatean and sea turtle 

species. In addition, Downeast has committed to continue its consultation with the FWS, NOAA 

Fisheries, and other relevant federal and state agencies to discuss other mitigation measures if 
4.5 – Wildlife and Aquatic Resources 4-120

appropriate. Upon completion of ESA consultation and federal and state permitting processes, 

Downeast would incorporate the final approved construction and mitigation measures into a 

comprehensive Prevention and Mitigation Manual for use in training of Downeast’s construction 

and operational personnel, which would be filed with FERC for review and approval prior to 

construction. Downeast would conduct consultations with federal agencies as FERC’s nonfederal representative; however, it would be the FERC’s responsibility to complete any 

necessary agency consultations.

Contaminated Sediments

Based upon investigations conducted by Downeast, there are several areas of contaminated 

sediments located within the footprint of the proposed facilities that could adversely impact 

surrounding water quality. However, the mobilization of sediments is not anticipated as being 

substantially different from normal bottom disruption caused by storm events. Given the piles 

used to support the trestle structure (pier, unloading platform, and dolphins) would be vibropiled, 

no rock or sediment spoil would be generated during pile installation (Balloch 2007).

Despite the aforementioned impacts, the effects associated with construction in Mill Cove are 

anticipated to be short term and minor. Given the tidal amplitude and strong currents affecting 

the area, construction activities are not likely to produce thick layers of sediment in any one 

location of the project area. The installation of the pier would also be conducted using a 

conventional “over-the-top” method of construction whereby the pier trestle is constructed from 

the shore seaward. This method of installation would limit the use of barge-mounted equipment 

reducing the amount of impacts on the Cove seabed from anchoring, as well as reduce the area of 

habitat disturbance and loss from propeller wash. Downeast has stated it would use BMPs to 

minimize/localize turbidity. In addition, as the pier support structures would be bolted to the 

bedrock underlying the softer seafloor surface, foundations would not have to be poured or filled, 

resulting in a relatively small footprint of the seafloor. Total permanent habitat loss due to piling 

structures would be approximately 0.11 acre.

Those benthic species that are affected during construction would likely begin recolonizing 

disturbed habitats within a period of weeks to days after construction for pioneering communities 

and several years for more “mature” communities. In addition, mobile fish and larger 

invertebrates would likely avoid construction activities and return to the area once activities have 

been completed. 

Timing of Construction Activities

To further mitigate for construction-related impacts, Downeast is currently consulting with the 

appropriate agencies regarding the timing of construction activities to avoid particularly sensitive 

periods. Timing may include seasonal considerations to avoid sensitive periods such as during 

spawning, migration, and peak fishery activity. Timing may also include avoiding equipment 

relocation activity during specific periods of the diurnal tide to avoid excessive disturbance to the 

bottom and reduce sediment resuspension by construction vessels. Additional mitigation options 

include specific measures for impact containment, such as the use of silt retention devices to 

restrict silt plumes. Downeast has not yet finalized its consultations with the appropriate 

agencies to establish construction timing restrictions; therefore, we recommend that:
4-121 4.5 – Wildlife and Aquatic Resources

• Downeast should continue to consult with NOAA Fisheries, Maine DMR, and other 

appropriate agencies to determine any recommended seasonal or construction 

timing restrictions to minimize impacts on marine species and habitats during all 

proposed in-water work and pile driving activities at the LNG terminal. Prior to 

construction of the LNG terminal facilities, Downeast should file with the Secretary 

copies of its final Prevention and Mitigation Manual, to include correspondence 

with consulted agencies and a description of any mitigation measures, including 

seasonal or construction timing restrictions.

When this information is filed with the Commission, FERC staff will consult with respective 

agencies as needed during its review.

Invasive Species

Downeast has documented the presence of invasive/exotic marine species, including the common 

periwinkle and green crab, in the general area surrounding the proposed pier. As is common in 

the marine environment, adding a vertical structure in the water column may provide additional 

habitat for all marine species, including invasive/exotic species that may exist in the area. 

However, it is unlikely that the minimal additional habitat area provided by the pier structures, as 

compared to the larger habitat area of Mill Cove and Passamaquoddy Bay, would have any 

discernible effect on either indigenous or invasive/exotic marine species. We have concluded 

that the proposed pier and construction activities are not likely to exacerbate the current 

populations of invasive species.

Commercial Fisheries

Impacts on the commercial fisheries would occur both as a result of pier installation, through the 

alteration of traditional fishing patterns, specifically lobstering and weir operation. The extent of 

these impacts would depend on the level of fishing activity in the immediate vicinity of the pier. 

In areas that have been identified as commercial lobster harvesting areas or areas of weir 

operations that would be disturbed or removed as the result of construction activities, Downeast 

has agreed to compensate fishermen for any adverse fisheries-related fiscal loss. We have 

recommended in section 4.8.2.5.1 of this EIS that Downeast complete the necessary 

consultations to finalize its Fishermen Communication, Coordination and Compensation Plan 

prior to operation of the LNG terminal.

Communication from the St. Croix Waterway Commission expressed concern for the impact of 

construction on the commercially important blue mussel and green sea urchin. For the blue 

mussel, given the generally soft sediments associated with nearly all of the intertidal and subtidal 

zones within the project area and the strong currents they are subject to, conditions are not 

generally suitable to support the establishment of large mussel beds that would appeal to 

commercial harvesters. In addition, as of January 17, 2007, Maine DMR closed the northwest 

portion of Mill Cove to the harvest of clams, quahogs, oysters, mussels, and other marine 

mollusks because of pollution. As such, construction of the project would not adversely affect 

the commercial fishery for blue mussels or commercial harvesting of green sea urchin. The 

presence of green sea urchins and their associated habitat (kelp beds) are low in the project area 

and reports from local fishermen indicate that the species is not present in sufficient amounts to 

be of commercial importance. The project could, however, result in a minor positive net increase 

in the presence of the species due to the presence of the pier pilings which would provide habitat 
4.5 – Wildlife and Aquatic Resources 4-122

for mussels and marine vegetation such as kelp and seaweed that are preferred habitats for green 

sea urchins.

The St. Croix Waterway Commission also expressed concern for impacts on mysid shrimps. 

These shrimps, while not a commercially important species, are an important food source for 

marine mammals and groundfish known to occur in the project area, as well as for processing 

plankton. Mysid shrimp occur in benthic habitats during the day and pelagic habitats during the 

evening. Construction impacts would include habitat loss and turbidity from the installation of 

the pilings for the pier, and entrainment during water uptakes for hydrostatic testing. The total 

area of impact would be minor relative to the available benthic habitat available to these species 

within the project area. Studies of the mysid shrimp indicate that this species repopulates after 

disturbance very rapidly (Jumars 2006).

Scoping comments received by the Commission indicated stakeholder concern that the LNG 

project would disturb or destroy breeding ground for lobster. Data does indicate that the area 

supports numerous large, egg-bearing females. Habitat within the footprint of the pier would be 

permanently altered where pilings are installed; however, it is expected that such impact would 

be minor and that lobsters, being highly mobile, would continue to utilize Mill Cove after 

construction and throughout operation of the proposed facilities. However, we have 

recommended that Downeast continue to consult with NOAA Fisheries, Maine DMR, and other 

appropriate agencies to determine impacts on the local lobster population and any recommended 

mitigations to minimize impacts on lobster and lobster habitat (see section 4.5.2.2).

Due to the limited nature of recreational fishing activities in the Cove, installation of the 

Downeast LNG Project would not result in significant adverse impacts.

Impingement and Entrainment

During construction of the LNG terminal, Downeast would conduct hydrostatic testing of the 

LNG storage tanks using approximately 28 million gallons of water, obtained principally from 

Passamaquoddy Bay. Entrainment and impingement of fish and other aquatic organisms such as 

phytoplankton, zooplankton, and ichthyoplankton could occur during water withdrawals. 

Downeast would minimize entrainment and impingement of fish by regulating the intake rate 

and by the use of screens on intake hoses. Downeast is currently proposing the use of a #200 

mesh filter during intake of hydrostatic test waters. Downeast has also stated it would coordinate 

with federal and state agency personnel regarding the scheduling of testing to minimize potential 

conflicts with seasonal/life-cycle periods of important aquatic resources. All water used for 

testing of the LNG storage tanks would be discharged back to the Bay.

Accidental Releases and Spills

During construction, the potential for spills and accidental releases of material such as diesel 

fuel, lubricants, and hydraulic fluid could affect fishes and other aquatic life through acute or 

chronic toxicity, and sub-lethal effects that could affect reproduction, growth, and recruitment. 

Depending upon the magnitude of the release, it is possible that when combined with the 

18+ foot tidal range, some material could wash up onto the intertidal zone, resulting in harm and 

mortality to intertidal benthos. To minimize the likelihood of accidental spills and releases, 

Downeast has adopted the measures specified in our Procedures regarding spill prevention and 

containment near waterbodies. In addition, we have recommended in section 4.3.2.1, that 
4-123 4.5 – Wildlife and Aquatic Resources

Downeast develop a Marine SPCC Plan to prevent, respond to, and mitigate any potential spills 

of oil, gas, lubricants, or other hazardous materials that could occur during construction and 

operation of the marine terminal. Given the adoption of the measures in our Procedures and the 

recommendation to develop a Marine SPCC Plan, we believe the risk of accidental spills or the 

introduction of other hazardous materials to the marine environment and their effects to aquatic 

life would be effectively minimized. 

Operation Impacts 

Shading

Once completed, the bottom of the pier deck and unloading platform would be approximately 

38.1 feet above the surface of the water at MLLW, and would shade a total of approximately 

6.6 acres of intertidal, subtidal, and open-water habitat. Included in the area impacted by 

shading would be about 0.6 acre of eelgrass as mapped by Maine DMR. We have recommended 

that Downeast conduct project specific mapping to determine potential presence and extent of 

eelgrass and need for mitigation for potential impacts, including from shading during operation 

(see section 4.4.2.2). Predatory species, especially those that forage primarily by sight, are often 

sensitive to intense sunlight and seek shade or deeper water during periods of intense sunlight. 

Shading of the area underneath the pier could enhance the habitat for predatory species or other 

species such as lobsters that avoid intense direct sunlight during the day and seek seclusion. The 

vertical structures associated with the pier structure would also provide additional hard intertidal 

and subtidal substrate for sessile flora and fauna attachment and could help foster the 

development of these types of communities. 

Lighting

The presence of the pier structure could also affect marine organisms due to shading and the 

presence of artificial lighting. However, the pier is relatively narrow and would be constructed a 

sufficient height above the water as to have minor shading affects. The marine transfer area for 

LNG must have a lighting system and separate emergency lighting that meets Coast Guard 

standards as published in 33 CFR Part 127.109. Downeast would work with the Coast Guard in 

coordination with Maine DMR and NOAA Fisheries to establish a lighting plan that would meet 

33 CFR Part 127.109 while minimizing the impacts associated with artificial lighting on marine 

organisms to the extent possible. In addition, while the pier may serve as a detractor to various 

species due to shading or lighting, the pilings themselves would provide new attachment surfaces 

for various marine species. In the Eastport region, piers are known for their biological richness.

Propeller Wash

During operation of the LNG terminal, propeller wash and other hydraulic effects from LNG 

ships and tugs could temporarily increase suspended sediments and turbidity within the pier 

location. Propeller wash could affect the substrate within and adjacent to the pier location and 

could scour and dislodge demersal fish eggs and limit the recolonization of benthic species in 

those areas. However, modeling was conducted for the Boston Harbor Navigation Improvement

Project to assess the effect of ship passage on the resuspension of surficial sediments in federal 

ship channels (COE 1995). The modeling assumed a channel depth of 45 feet and varying vessel 

drafts from 12 to 42 feet. The study concluded that silt, the predominant grain size of the 

surficial sediments assessed in the model, can be resuspended by currents as slow as 

0.65 feet/second. The study also found that bottom velocities generated by cargo vessels passing 
4.5 – Wildlife and Aquatic Resources 4-124

at slow speeds through the harbor can exceed this value up to 1,312 feet astern of the vessel and 

that tugs can generate bottom velocities above this value up to 656 feet astern of the vessel. 

Turning areas were found to be particularly susceptible to resuspension of sediments as the result 

of ship passage. The results indicated that the surficial sediments in the federal ship channels 

and berth areas are subject to resuspension during virtually every ship passage. However, the 

results also indicated that ship-induced bottom velocities dissipate rapidly following the passage 

of the ship and that sediments resuspended by these currents settle back to the substrate after 

being transported relatively short distances (COE 1995). 

Following completion of the Boston Harbor Navigation Improvement Project, the COE 

conducted additional studies to monitor the effect of deep-draft vessel movement on the 

resuspension of bottom sediments (SAIC 2000, 2001). These studies used static and mobile 

monitoring techniques to evaluate the impact of the passage of an LNG vessel (Matthew) on 

bottom sediment resuspension from the confined aquatic disposal cells along a portion of the 

Mystic River downstream of the Distrigas LNG facility as well as material resuspended from 

other parts of the channel. 

These studies demonstrate that sediment resuspension due to passage of deep-draft vessels can 

mobilize bottom sediments, but the volume of sediment resuspended is relatively small and the 

sediments are not transported far from their original locations. Vessel movements within a 

navigation channel result in short-term water quality effects that generally dissipate within 

1 hour of the vessel passing any particular point along the channel.

The potential for resuspended sediment to impact fish eggs and larvae depends upon the species, 

the concentration of particles, and the duration of exposure. Demersal eggs, such as those of 

winter flounder, may be dislodged and/or partially or completely covered by fine-grained 

sediments as they settle back to the bottom. This may slow the exchange of oxygen between the 

water and egg and, therefore, slow development or cause eggs to experience higher mortality 

rates (Wilbur and Clarke 2001). Exposure to high levels of suspended solids (between 200 and 

500 mg/L) for durations of less than 24 hours has been shown to reduce feeding rates in some 

fish larvae (Breitburg 1988). In general, however, exposure to increased turbidity for periods of 

less than one day, which would be likely from LNG vessels, appears to have little measurable 

effect on pelagic fish eggs and larvae (Kiorboe et al. 1981; Wilbur and Clarke 2001). 

Based on the results of the Boston Harbor studies, the increased suspended solids levels resulting 

from LNG vessel passage could result in reduced feeding rates for some fish larvae in the 

immediate vicinity of the pier. However, we expect there would be minimal impact on most 

pelagic fish eggs and larvae because suspended solids concentrations should return to 

background conditions within one hour or less of ship passage. Additionally, propeller wash due 

to normal operation of tugs, escort vessels, and LNG vessels would not be expected to increase 

turbidity in the vicinity of the pier because the sediments in this area appear to be cohesive, soft 

marine clays. Based on the initial monitoring in the Mystic River, the sediment plume did not 

rise above mid-water elevations (i.e., the plume was not observed at the water surface, and 

monitoring equipment indicated a maximum water column elevation of about 20 feet above the 

channel bottom). The dimensions of the monitored plumes in Boston Harbor suggest that 

impacts on demersal fish eggs and larvae by remobilized sediments would likely be limited.
4-125 4.5 – Wildlife and Aquatic Resources

Water Withdrawals and Discharges

No seawater would be used in the regasification of the LNG. LNG vessels would require water 

withdrawals and discharges while at the port for vessel operations. The majority of this water 

would consist of engine cooling water that is recirculated or cycled through a heat exchanger 

before being discharged back to Passamaquoddy Bay, and water used for hoteling, ballasting, 

and fire suppression pump testing. Water circulation and water withdrawals and discharges

would result in impacts on marine organisms. It is anticipated that the size of vessels servicing 

the terminal would range from 125,000 m3 up to 165,000 m3 cargo carrying capacity. To 

maintain a constant draft while berthed at the pier, 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. Vessels would also require between 2.7 million gallons (large capacity 

165,000 m3 diesel vessel) and 55.5 million gallons (steam-driven large capacity 165,000 m3

vessel) of water to support engine cooling and between an estimated 2.7 million gallons (large 

capacity 165,000 m3 diesel vessel) and 7.2 million gallons (125,000 to 165,000 m3 steam-driven 

vessels) of water to support hoteling needs during the 21-hour cargo unloading period. Diesel 

powered vessels use a different propulsion system, which requires less water. A breakdown of 

water intake estimates for the range and type of LNG vessels that are anticipated to service the 

port are summarized in table 4.5.2.2-4. Ballast, engine cooling, and hoteling water would be 

drawn through intake openings located on the side of the vessel. These openings would be 

covered with a strainer plate with slots designed to prevent intake of large objects. Aquatic 

organisms including zooplankton, icthyoplankton, and mysid shrimp in the immediate vicinity of 

the LNG vessel could therefore be subject to impingement and/or entrainment during water 

intake. Ballast, engine cooling, and hoteling intakes on the LNG vessels are located near the 

bottom of the vessel, and therefore, impingement and/or entrainment would be limited to 

organisms in the deeper water column (30 to 35 feet below the surface). The impacts on 

ichthyoplankton, zooplankton, and mysid shrimp related to the water used by vessels servicing 

the Downeast LNG terminal would vary based on a number of conditions including vessel type, 

vessel size, and duration at port. Loss estimations of ichthyoplankton and zooplankton from 

intakes associated with engine cooling and ballasting for each vessel class, species densities 

(worst case) and 100 percent mortality are included in Appendix O. Hoteling water intakes were 

not included within the context of this impact assessment; however; intake for this purpose 

would be relatively minor compared to those associated with engine cooling and ballasting. As 

indicated in table 4.5.2.2-4, the total zooplankton loss per visit for a full load ballast, based on 

plankton sampling to date, ranges from a low of 281 million for a diesel 165,000 m3 vessel to a 

high of 869 million for a steam-driven 165,000 m3 vessel.

The emergency fire suppression system along the pier would also require the use of seawater 

during periodic system testing with the potential to adversely impact ichthyoplankton and 

zooplankton in the vicinity of the project area (see table 4.5.2.2-5). The fire system would 

consist of seven pumps that would draw water from a minimum of 30 feet below the water 

surface at a capacity of 3,000 gpm per pump. The pumps would be tested weekly and require a 

total of 180,000 gallons of seawater for a test period of at least one hour per system test. Annual 

ichthyoplankton and egg losses resulting from the emergency fire suppression testing are 

estimated to be 44,000 and 134,000, respectively. The total annual zooplankton loss from 

emergency fire suppression system testing is estimated to be 926 million.
4-126 4.5 

– Wildlife and Aquatic Resources

TABLE 4.5.2.2-4

Vessel Seawater Usage Impacts on Fish Eggs, Fish Larvae, and Zooplankton per Visit Based on Worst Case Densities

Vessel 

class a/

Cooling 

flow 

rate b/ 

(m3/hr)

Time in 

port c/ 

(hrs)

Ballast volume 

d/ (m3

)/(gals)

Total 

seawater 

usage/visit 

e/ (m3

)/ (gals)

% of Total 

area flow f/ 

(322x106 

m3

)

% of Total 

regional 

flow g/ 

(1452x106 

m3)

Max. 

Fish 

eggs h/ 

(#/m3)

Total fish 

egg 

loss/visit 

i/

Max.

Ichthy. j/ 

(#/m3)

Total 

ichthyo 

loss/visit k/

Max. 

Zooplanton l/ 

(#/m3)

Total 

zooplankton 

loss/visit m/

Full load ballast

125K MT 6,341 21 53,683/

14,181,548

186,835/

49,356,585

0.0580% 0.0129% 0.541 101,078 0.177 33,070 3733 697,455,704

138K MT 7,000 21 53,107/

14,029,385

200,107/

52,862,677

0.0621% 0.0138% 0.541 108,258 0.177 35,419 3733 746,999,431

145K MT 7,355 21 56,964/

15,048,297

211,421/

55,851,519

0.0657% 0.0146% 0.541 114,379 0.177 37,421 3733 789,232,808

165K MTS 500 21 64,759/

17,107,518

232,759/ 

61,488,427

0.0723% 0.0160% 0.541 125,923 0.177 41,198 3733 868,889,347

165K MTD 500 21 64,759/

17,107,518

75,259/

19,881,324

0.0234% 0.0052% 0.541 40,715 0.177 13,321 3733 280,941,847

Vessel 

class a/

Cooling 

flow 

rate b/ 

(m3/hr)

Time in 

port c/ 

(hrs)

Ballast volume 

d/ (m3

)

Total 

seawater 

usage/visit 

e/ (m3

)

% of Total 

area flow f/ 

(322x106 

m3

)

% of Total 

regional 

flow g/ 

(1452x106 

m3)

Max. 

Fish 

eggs h/ 

(#/m3)

Total fish 

egg 

loss/visit 

i/

Max.

Ichthy. j/ 

(#/m3)

Total 

ichthyo 

loss/visit k/

Max. 

Zooplanton 

l/ (#/m3

)

Total 

zooplankton 

loss/visit m/

Light load ballast (80.8% of full load ballast)

125K MT 6,341 21 43,372/

11,457,670

176,524/

46,632,707

0.0548% 0.0122% 0.541 95,500 0.177 31,245 3733 658,964,741

138K MT 7,000 21 42,910/

11,335,623

189,910/

50,168,914

0.0590% 0.0131% 0.541 102,742 0.177 33,614 3733 708,935,732

145K MT 7,355 21 46,027/

12,159,047

200,483/

52,96,006

0.0623% 0.0138% 0.541 108,462 0.177 35,486 3733 748,404,658

165K MTS 8,000 21 52,325/

13,822,803

220,325/ 

58,203,717

0.0684% 0.0152% 0.541 119,196 0.177 38,998 3733 822,473,225

165K MTD 500 21 52,325/

13,822,803

62,825/

16,596,609

0.0195% 0.0043% 0.541 33,988 0.177 11,120 3733 234,526,740

a/ Vessel size class in thousands of metric tons

b/ Flow rate source: John Egan, Marine Master, personal communication 2006

c/ Estimated time in port/at dock: John Egan, Marine Master, personal communication 2006

d/ Ballast volume source: John Egan, Marine Master, personal communication 2006

e/ Total seawater usage per visit = cooling flow rate x time in port + ballast volume

f/ Mean tidal flow across line from St. Andrews, New Brunswick and Lewis Cove, Robbinston, Maine - W.F. Baird & Associates, July 6, 2006, Table 6.1, p. 27

g/ Mean ebb and flood tidal flow in and out of Passamaquoddy Bay through Western Passage - W.F. Baird & Associates, July 6, 2006, Table 6.1, p. 27

h/ Based on maximum October 2006- November 2008 fish egg sampling in Mill Cove (July 2009)

i/ Mill Cove annual maximum total fish egg count multiplied by total visit seawater usage

j/ Based on maximum October 2006- November 2008 ichthyoplankton sampling in Mill Cove( July 2009)

k/ Mill Cove annual maximum ichthyoplankton count multiplied by Total visit seawater usage

l/ Based on maximum October 2006- November 2008 zooplankton sampling in Mill Cove (July 2009)

m/ Mill Cove annual maximum total zooplankton count multiplied by total visit seawater usage
4-127 4.5 

– Wildlife and Aquatic Resources

TABLE 4.5.2.2-5

Fire Suppression Seawater Usage Impacts on Fish Eggs, Fish Larvae, and Zooplankton per Visit Based on Worst Case Densities

Number 

Fire 

pumps

Pump 

flow rate 

(gpm)

Total test 

flow rate a/ 

(m3/hr)

Test 

period 

(hrs)

Total test 

volume b/ 

(m3)

Max. 

Fish 

eggs c/ 

(#/m3)

Total fish 

egg 

loss/test d/

Total fish 

egg 

loss/year e/

Max. 

Ichthy.f/ 

(#/m3)

Total 

ichthy. 

loss/test 

g/

Total 

ichthy. 

loss/year 

h/

Max. 

Zooplankton i/ 

(#/m3

)

Total 

zooplankt

on loss j/

Total Annual 

zooplankton 

loss k/

7 3,000 4,769 1 4,769 0.214 2,580 134,164 0.134 844 43,895 3733 17,803,050 925,758,616

a/ Total test flow rate (m3/hr) = ((((Pump flow rate (gpm) * 7) * 60min)*3.785 l/gal)/1000 l/m3

b/ Total test volume = Total test flow rate * Test period

c/ Based on maximum October 2006- February 2008 fish egg sampling in Mill Cove (August 2007)

d/ Mill Cove annual worst case total fish egg count multiplied by total test volume

e/ Total fish egg loss/test * 52 tests/year

f/ Based on maximum October 2006- February 2008 ichthyoplankton sampling in Mill Cove (May 2007)

g/ Mill Cove annual worst case total ichthyoplankton count multiplied by total test volume

h/ Total ichthyoplankton loss/test * 52 tests/year

i/ Based on maximum October 2006- February 2008 zooplankton sampling in Mill Cove (August 2007)

j/ Mill Cove annual worst case zooplankton count multiplied by Total test volume

k/ Total zooplankton loss/test * 52 tests/year
4.5 – Wildlife and Aquatic Resources 4-128

The engine cooling water systems of LNG vessels visiting the proposed terminal may include 

biocides for anti-fouling of engine systems. If biocides are used, the effects to native organisms 

from discharging cooling waters containing biocides would depend on the type of biocide used. 

Some biocides could adversely affect aquatic organisms. However, many biocides do not result 

in toxic reactions with seawater when released, and any chemicals discharged would be rapidly 

dispersed by the tidal flushing that occurs in Mill Cove. Downeast would have no control over 

the anti-fouling system used on the visiting LNG vessels.

Impingement and Entrainment

Using the mean annual density of larvae and eggs found over the plankton sampling occasions 

from October 2006 through February 2008, Downeast estimated the potential annual impacts on 

fish stocks of individual species resulting from egg and larvae losses. Egg and larvae losses 

were calculated by employing a worst-case scenario assumption of 61.5 million gallons of 

seawater usage by an LNG vessel (165,000 m3 steam-driven vessel) per visit, and assumed a total 

of 68 LNG vessel visits per year.

Equivalent adult losses are based on three assumptions for larvae and egg survival: one adult per 

100,000 eggs or larvae, one adult per 10,000 eggs or larvae, and one adult per 1,000 eggs or 

larvae. The maximum number of equivalent adult losses, based on a survival assumption of one 

adult fish per 100,000 eggs and one adult fish per 10,000 larvae, are presented for each vessel 

class in table 4.5.2.2-6. Total annual equivalent adult losses are estimated to range from a low of 

12 for a 165,000 m3 diesel vessel to a high of 102 for a 165,000 m3 steam vessel. For 

commercially important fish species, the total annual equivalent adult losses are estimated to 

range from a low of 12 for a 165,000 m3 diesel vessel to a high of 36 for a 165,000 m3 steam 

vessel. Data on equivalent adult losses for specific species can be found in Appendix O.

TABLE 4.5.2.2-6

Annual Vessel Seawater Usage Adult Equivalency Fish

Vessel Class a/ Total Annual

Fish Loss b/

Total Annual

Commercially-Important Fish Loss c/

125K MT 82 29

138K MT 87 31

145K MT 92 33

165K MTS 102 36

165K MTD 33 12

a/ Vessel size class in thousands of metric tons

b/ Total equivalent loss of adult fish assuming a survival rate of 1 fish: 100,000 eggs and 1 fish: 10,000 larvae

c/ Commercially important, NEFMC managed species. Total equivalent loss of adult fish assuming a survival rate of 1 fish: 

100,000 eggs and 1 fish: 10,000 larvae 

Data presented in Appendix O

The estimated equivalent adult losses in the vicinity of the Downeast LNG Project are within the 

same order of magnitude, but slightly less, than those previously estimated based on results from 

the Maine DMR inshore trawl survey sampling within Region 5. Estimated egg and larval losses 

by species based on Maine DMR trawl survey efforts conducted in October 2001 and June 2002 

and 2003 under worst-case scenario are provided in Appendix O. 
4-129 4.5 – Wildlife and Aquatic Resources

Despite estimated losses, the significant tidal fluctuations and water exchange that occurs in the 

project area; the high densities of zooplankton and ichthyoplankton; quick recovery times of 

mysid shrimp that occur in the surrounding Passamaquoddy Bay; and the comparatively small 

amount of water withdrawn suggest that the overall impacts on zooplankton, ichthyoplankton, 

and mysid shrimp in the project area would have inconsequential effects to overall community 

populations and associated fish stocks. However, NOAA Fisheries staff has expressed concern 

for plankton losses due to water withdrawals from LNG vessel visits to the Downeast LNG 

terminal. NOAA Fisheries has recommended monitoring activities to confirm our conclusions. 

NOAA Fisheries has suggested that such monitoring activities would provide baseline 

information to assist in adaptive mitigation, should the need arise, for managing potential 

impacts on these species. NOAA Fisheries has encouraged continued consultation with 

Downeast to develop a monitoring plan and/or compensatory mitigation program, if necessary, to 

offset ‘life cycle’ impacts that may result from the Downeast LNG Project. While we understand 

NOAA Fisheries’ request for ichthyoplankton and zooplankton field survey data during water 

withdrawals by the LNG carrier, we believe that Downeast’s use of best available scientific data 

for plankton impacts are adequate to determine impacts. Further, we note that Downeast would 

have no control over the LNG vessels calling on the Project, and would not be able to conduct 

adaptive management to minimize impacts on the plankton during operation of the vessels. 

Thermal Impacts

Thermal impacts associated with vessel engine cooling discharge waters are also expected to be 

minor and insignificant. CORMIX modeling conducted by Downeast indicates that vessel 

engine cooling discharges would result in a thermal plume that would dissipate to approximately 

1°C or less warmer than ambient conditions at a distance of 15 to 30 meters from the discharge 

source (see Appendix O). Temperature elevations of 1°C above ambient would not likely have 

an impact on adult or juvenile marine species or their eggs.

Commercial Fisheries

Impacts on the commercial fisheries would also occur as a result of pier operation, including the 

fixed safety/security zone around the pier and berthed LNG vessel, through the alteration of 

traditional fishing patterns, specifically dragging, lobstering, and weir operation. The extent of 

these impacts would depend on the level of fishing activity in the immediate vicinity of the 

Downeast LNG pier and the safety/security zones around a vessel at berth. Currently, Downeast 

is in negotiations with local lobstermen and weir operators known to fish in the vicinity of the 

pier to establish plans to mitigate and/or compensate for loss of fishing during operations. The 

Coast Guard’s WSR recommends that the size of the fixed safety/security zone for an LNG 

vessel berthed at the Downeast LNG terminal be a 500-yard radius around the moored vessel. 

The WSR further recommends that Downeast prepare a Facility Security Plan as required by 

33 C.F.R. § 105.120 for review and approval of the COTP Sector Northern New England before 

the facility begins operations. This plan would provide the conditions and parameters of the 

safety/security zone at the pier. 

Due to the limited nature of recreational fishing activities in the Cove, installation of the 

Downeast LNG Project would not likely result in significant adverse impacts.
4.5 – Wildlife and Aquatic Resources ion 4-130

Accidental Releases and Spills

All commercial vessels must comply with MARPOL regulations and the EPA’s VGP (for nonrecreational vessels, 79 feet or greater in length), which regulates discharges from vessels. 

Compliance with these applicable regulations would effectively minimize potential impacts on 

aquatic habitats associated with the discharge of graywater, blackwater, ballast water, or 

potential accidental releases from LNG vessels at the berth. As discussed in section 4.3.2.1, we 

have recommended that Downeast develop a Marine SPCC Plan to prevent, respond to, and 

mitigate any potential spills of oil, gas, lubricants, or other hazardous materials that could occur 

during construction and operation of the marine terminal. As discussed in section 2.7.1.1, 

Downeast would have spill containment basins in the process, vaporizer, and LNG transfer areas 

to collect and contain any LNG spills.

4.5.2.3 Sendout Pipeline 

The proposed 29.8-mile sendout pipeline would cross a total of 22 fresh waterbodies (see 

table 4.3.2.2-1). Waterbodies crossed by the proposed LNG project are also discussed in more 

detail in section 4.3 of this EIS. 

Maine’s inland freshwater fishery includes a total of 56 freshwater species, 20 of which are 

classified as sportfish species regularly pursued by anglers. Waterbodies in the project area are 

generally classified as coldwater fisheries and warmwater fisheries. Of the waterbodies crossed 

by the proposed sendout pipeline, a total of 13 waterbodies are classified as coldwater fisheries 

and nine waterbodies are classified as a warmwater fishery. Of these waterbodies, two unnamed 

streams at MP 2.0 (unnamed stream) and MP 4.3 (unnamed stream, outlet of Keene Lake) were 

observed to have suitable fish spawning habitat. Species likely to occur in the unnamed stream 

at MP 2.0 include brown bullhead (Ameiurus nebulosus), sunfish (Lepomis spp.), and minnows. 

At the unnamed stream at MP 4.3, species likely to occur include small mouth bass (Micropterus 

dolomieu), brook trout (Salvelinus fontinalis), and chain pickerel (Esox niger).

The Maine DIFW also noted the potential for brook trout habitat to occur in the vicinity of the 

crossings of Wapsaconhagen Brook, Eastern Stream, Magurrewock Stream, Anderson Brook, 

and Wetland 1 at the terminal site. Additionally, the Maine DMR comment letter of February 1, 

2008 indicates that the St. Croix River and Magurrewock Stream contain species of concern, 

including alewife, American eel, and Atlantic salmon. This area is used as a migration corridor 

for all three species and also may be used by the American eel for rearing purposes. The 

presence of Atlantic salmon and its habitats in waters crossed by the sendout pipeline are further 

discussed in section 4.6 of this EIS. Downeast’s stream habitat surveys confirmed five stream 

crossings that are riffle and pool complexes that meet the COE criteria as special aquatic sites. 

Table 4.5.2.3-1 lists these streams by milepost along with the potential area of disturbance and 

Downeast’s proposed crossing method. Approximately 4,640 square feet of riffle pool habitat 

would be affected by pipeline construction right-of-way and temporary workspace and 

approximately 1,740 square feet would be within the permanent right-of-way. Downeast stated 

it would attempt to avoid installing the pipeline in riffle habitats, where possible.

Construction Impacts

Downeast’s proposed construction methods for crossing each waterbody are listed in 

table 4.3.2.2-1. Depending on the construction method used, direct impacts on aquatic habitats 
4-131 4.5 – Wildlife and Aquatic Resources

and species would either be avoided (e.g., through HDD) or would occur in localized areas. The 

seasonal construction window for coldwater fisheries is from July 16 to September 30 annually. 

The seasonal construction window for warmwater fisheries is June 1 to November 30 annually. 

Downeast proposes to cross streams primarily using dam and pump crossing techniques, except 

at nine locations where HDD would be used, including an unnamed stream (MP 4.3; outlet of 

Keene Lake), Flowed Land Ponds (MP 6.7), the tributary of Beaver Brook (MP 8.6; upstream of 

Flowed Land Ponds, outlet of Carson Heath), the Magurrewock Stream outlet (MPs 14.1 to 

14.2), the St. Croix River (MPs 14.3 to 15.3), two unnamed streams (tributaries of the St. Croix 

River) at MPs 17.8 and 18.1, Anderson Brook (MP 25.2), and the headwater tributary to 

Anderson Brook at MP 28.9. In addition, Downeast proposes to use the HDD method to cross 

two streams at MPs 17.8 and 18.1 to avoid affecting riffle pool habitat (see table 4.5.2.3-1). 

Refer to section 4.3 of this EIS for a detailed description of crossing methods. 

TABLE 4.5.2.3-1

Estimates of Impact on Riffle Pool Habitat

Perennial Stream Milepost Habitat

Type

Pipeline 

Installation 

Method

Area Affected (sq. ft.)

Workspace –

Temporary 

ROW

25 feet

Pipeline

Permanent 

ROW

30 feet

Total 

Construction 

ROW

55 feet

Average 

Stream Width

(feet)

Unnamed Stream 

(Inlet to Flowed Land 

Pond)

7.7 Low gradient riffle 

located upstream 

of ROW

Dam-andpump200.0 240.0 440.0 8.0

Unnamed Stream 

(Tributary to St. 

Croix River)

17.8 Low gradient riffle HDD - - - 3.0

Unnamed Stream 

(Tributary to 

St. Croix River)

18.1 High gradient riffle HDD - - - 1.0

Stoney Brook 18.4 Low gradient riffle 

located in ROW

Dam-andpump325.0 390.0 715.0 13.0

Wapsaconhagen 

Brook

21.3 Low gradient riffle 

located in ROW

Dam-andpump925.0 1,110.0 2,035.0 37.0

Total Area (sq.ft.) (Worst-Case Scenario) 1,450.0 1,740.0 3,190.0

General impacts from dam and pump construction techniques would result in in-stream 

disturbances; however, downstream flow of water would not be interrupted, and the release of 

sediment to the waterbody would be generally less and of shorter duration than with other 

methods such as the wet-trench open-cut crossing method. 

Although not currently proposed, in the event Downeast’s proposed crossing method is 

determined unsuccessful or infeasible, an open-cut crossing technique may be applied. General 

impacts from open-cut crossings would occur to aquatic life such as plankton, aquatic vegetation, 

amphibians, fish, and aquatic invertebrates. Impacts on water quality and associated aquatic 

habitats would include sedimentation, turbidity, altered water temperatures and dissolved oxygen 

levels, and introduction of contaminants, all of which can affect the ability of aquatic life to 

survive and reproduce. Impacts would also include the physical disturbance or destruction of instream cover due to trenching and removal of riparian vegetation. Construction activities could 

also result in blockage of fish migrations and interruptions of spawning activities, as well as 
4.5 – Wildlife and Aquatic Resources ion 4-132

entrainment of fishes or reduced stream flows during withdrawals for hydrostatic testing. These 

potential impacts are discussed below in more detail. To ensure appropriate mitigation measures 

are employed at any open-cut crossing originally proposed to be crossed by HDD or other dry 

ditch methods, we recommended in section 4.3.2.2 of this EIS that Downeast file any amended 

wetland or waterbody crossing plans concurrent with the appropriate state and federal 

applications for any required permits or approvals to construct the crossing using this plan. The 

Director of OEP must review and approve the plan in writing before construction of the crossing.

As indicated, pipeline construction would result in sedimentation and turbidity in surface waters 

and aquatic habitats through clearing and grading of streambanks, in-stream trenching, trench 

dewatering, and backfilling of the in-stream trench. In addition, blasting could potentially occur 

in areas of shallow bedrock along the proposed sendout pipeline route (see section 4.1 for details 

regarding blasting).

Increased sedimentation and turbidity from in-stream construction across waterbodies has the 

potential to adversely affect fishery resources; however, these types of impacts would be short 

term and would only occur during the construction phase. Total suspended solid concentrations 

may increase during construction following in-stream construction, but soon after construction is 

complete these concentrations would decrease as the in-stream sediments disturbed during 

construction are allowed to settle. 

Turbidity resulting from suspension of sediments during in-stream construction could reduce 

light penetration and photosynthetic oxygen production. Additionally, re-suspension of organic 

and inorganic materials can cause an increase in biochemical oxygen demand, resulting in a 

decrease in dissolved oxygen; however, any decreases in oxygen would be short term and may 

occur during active construction across waterbodies. 

Benthic invertebrates can suffer significant negative effects from deposited sediments because 

they are adapted to specific substrate particle sizes. As sediment settles into the interstitial 

spaces in the streambed, the availability of substrate decreases, resulting in decreased species 

diversity, abundance, and productivity. In turn, fish communities that depend on the benthic 

invertebrate community as a food source may suffer. 

To minimize impacts, all perennial and intermittent streams designated as A, B, coldwater or 

coldwater/warmwater fisheries would be crossed using dry crossings methods. At crossings 

where riffle habitat has been identified that would be crossed using a dam and pump or HDD, 

Downeast has stated it would attempt to avoid installing the pipe in riffle habitats. Where that 

may not be possible, Downeast would prevent discharge of fill to the streams using construction 

measures outlined in its Plan, Procedures, and Soil Erosion and Sediment Control Guidelines. 

All construction activities would also take place in accordance with requirements set forth by the 

COE, Maine DEP, and the Maine Land and Water Quality Bureau’s Erosion and Sediment 

Control Best Management Practices. To further minimize impacts, Downeast would continue to 

consult with the appropriate agencies to determine any site-specific timing restrictions for 

construction.

Construction would require clearing of streamside vegetation, which would result in reduced 

shading, possible increases in water temperature, and decreased nutrient input from organic 

debris in some of the streams. In addition, some in-stream and shoreline cover would be altered 
4-133 4.5 – Wildlife and Aquatic Resources

or lost at the stream crossings and fish that normally reside in these areas would be displaced. 

However, these effects would be relatively minor because of the small area affected at each 

stream. The adoption of our Procedures, which limit vegetation maintenance adjacent to 

waterbodies to allow a riparian strip at least 25 feet wide and to permanently revegetate with 

native plants across the right-of-way, would reduce the long-term effects of construction. In 

addition, a riparian buffer extending 100 feet back from the banks of perennial waterbodies 

(Class A, coldwater, and coldwater/warmwater) would be allowed to grow across the entire 

width of the project right-of-way following construction, with the exception of a 10-foot-wide 

strip centered over the pipe. Thus, downstream water temperatures would not be significantly 

increased. 

To ensure impacts are minimized, EIs would be employed to ensure erosion control and all other 

environmental safeguards are in place and maintained during construction activities. In addition, 

the FERC would conduct compliance inspections throughout project construction and 

restoration.

Loss of streambank vegetation could also result in bank erosion if not properly restored. Upon 

completion of the sendout pipeline, Downeast would restore streambeds and streambanks to 

approximate pre-construction condition. Streambank stabilization and reseeding following 

NRCS guidelines would be conducted to restore habitat, shade, and cover to wildlife. 

Introduction of pollutants into waterbodies and aquatic habitats could occur through disturbance 

of contaminated soils or sediments, accidental spills, and inadvertent releases of drilling fluids 

during HDD operations. Pollutants could affect fishes and other aquatic life through acute or 

chronic toxicity, and sub-lethal effects that could affect reproduction, growth, and recruitment. 

Pollutants can also be introduced during discharge of hydrostatic test waters. However, 

Downeast has stated that biocides and other potentially toxic hydrostatic test water additives 

would not be used during hydrostatic testing of the sendout pipeline. 

Downeast proposes to cross the unnamed stream (MP 4.3; outlet of Keene Lake), Flowed Land 

Ponds (MP 6.7), the tributary of Beaver Brook (MP 8.6; upstream of Flowed Land Ponds, outlet 

of Carson Heath), the Magurrewock Stream outlet (MPs 14.1 to 14.2), the St. Croix River 

(MPs 14.3 to 15.3), two unnamed streams (tributaries of the St. Croix River) at MPs 17.8 and 

18.1, Anderson Brook (MP 25.2), and the headwater tributary to Anderson Brook at MP 28.9 

using the HDD method. Downeast also proposes to cross the riffle pool habitat associated with 

the unnamed steams at MPs 17.8 and 18.1 with a HDD. A pipeline crossing by HDD would 

avoid stream bottom disruption and subsequent impacts on aquatic habitats along that portion of 

the pipeline route. However, HDD methods generally require larger workspace areas on either 

side of the crossing and are not without risk as inadvertent drilling fluid releases could result if 

the drilling fluid escapes containment at pits or tanks at the HDD entrance and exit points or if a 

“frac-out” occurs. A frac-out occurs when drilling fluids migrate unpredictably to the surface 

through fractures, fissures, or other conduits in the underlying rock or unconsolidated sediments. 

During HDD operations, a frac-out directly into a waterbody would cause turbidity and 

sedimentation. Potential impacts from increased turbidity would include decreased water quality 

and compromised aquatic habitat integrity. As suspended materials settle out of the water 

column, sedimentation would partially or entirely cover the waterbody substrate and any sessile, 

benthic organisms. Temporary displacement of fish species and their prey items, as well as the 
4.5 – Wildlife and Aquatic Resources ion 4-134

potential for the smothering or burying of prey items, and the clogging of fishes’ gills could also 

occur. The proposed HDD drilling fluid, however, would consist of water and bentonite. 

Bentonite contains a mixture of non-toxic clays and rock particles which if released in small 

quantities would not be detrimental to fisheries or water quality. However, the release of large 

quantities into a waterbody could result in adverse impacts on fisheries. To minimize the 

potential for impacts, Downeast would conduct proactive monitoring of all the drilling 

operations, including monitoring of drill fluid volumes and pressures and downhole annular 

pressure between the drill rod and the hole. In addition, Downeast would require the HDD 

contractor to have the necessary equipment on site (e.g., haybales, pumps, silt booms, vactrucks) to adequately contain and clean up any fluid lost in the event of a “frac-out” incident. 

Section 4.3.2.2 describes Downeast’s plans for mitigating inadvertent releases of drilling muds. 

Normal movements of resident fish and other aquatic organisms would be temporarily 

interrupted during dam and pump stream crossings. The HDD crossing technique typically does 

not affect migrating species from ascending or descending stream sections during construction. 

However, stakeholders have expressed concern that noise and vibrations from an HDD operation 

could adversely affect fisheries of interest (i.e., Atlantic salmon, alewife, American eel, 

American shad, rainbow smelt, and blueback herring). Downeast has indicated that HDD 

crossings would be a minimum of 60 feet below each river and/or streambed; therefore, impacts 

from HDD vibrations are unlikely. Downeast has also noted that diesel engines used to support 

HDD operations would contain sound mitigation devices to minimize potential noise impacts. 

Downeast is also consulting with the Maine DMR to determine if construction activities should 

be limited during the spawning migration period. The duration of in-stream disturbance also 

would be short term. Downeast has estimated that each HDD would take between 24 and 

48 hours depending on the size of the stream, except for the proposed HDD crossing of the 

St. Croix River and Magurrewock Stream outlet. Downeast has estimated that the crossings of 

the St. Croix River and the Magurrewock Stream outlet would take approximately 75 to 90 days 

to complete, based on the presumption that drilling would be conducted 24 hours per day, with 

some reduction to 12 hours per day if necessary. For this crossing, Downeast proposes a 

construction window between June and August to avoid potential impacts on species such as 

Atlantic salmon, alewife, American eel, American shad, rainbow smelt, and blueback herring. 

We agree with this proposed construction window. Dam and pump crossings may take longer 

than other types of crossing (e.g., open-cut), but flow is channeled through a flume or hose for 

the duration of the crossing, thereby minimizing impacts. Restoration would occur immediately 

after the crossing further reducing the impact on fisheries and benthic organisms.

Operation of heavy equipment or other vehicles in and near surface waterbodies would also 

introduce chemical contaminants, such as fuels and lubricants, into surface waters or result in 

accidental spills during construction. Downeast has adopted the measures specified in our 

Procedures regarding spill prevention, containment, and minimization near waterbodies. 

Downeast has also developed a SPCC Plan template to be used by its contractors. These 

measures and the SPCC Plan template are discussed in more detail in sections 4.3.1.2 and 4.3.1.3

of this EIS, and would include, but not be limited to:

• keeping construction materials, fuels, etc., 100 feet or more from any stream or wetland 

system, except under limited, highly controlled circumstances;
4-135 4.5 – Wildlife and Aquatic Resources

• refueling construction equipment in upland areas 100 feet or more from any stream or 

wetland system, except under limited, highly controlled circumstances; and

• not washing construction equipment in/or immediately adjacent to any wetland or 

watercourse.

Given the adoption of the measures in our Procedures and the measures included in Downeast’s 

SPCC Plan template, the risk of accidental spills or the introduction of other hazardous materials 

to waterbodies and their effects to aquatic life would be effectively minimized. 

Hydrostatic testing of the sendout pipeline would be conducted using approximately 6.1 million 

gallons of freshwater withdrawn from the BUD through a direct connection to the fire hydrant 

system (see section 4.3.2.2 of this EIS). Therefore, entrainment of fish and other aquatic 

organisms would not occur during withdrawals of water for hydrostatic testing of the pipeline 

facilities. 

Downeast would prevent or adequately limit impacts from hydrostatic testing by implementing 

its Procedures. In addition, the sendout pipeline may be hydrostatically tested in segments, 

allowing the re-use of the same water for different segments. No chemicals would be added to 

the test water and waters would be discharged back to surface waterbodies through a straw bale 

dewatering structure adjacent to an unnamed creek at MP 17.5 or the BUD sewer system, if 

feasible. The rate of flow and discharge location would be controlled to prevent temporary 

flooding conditions. The estimated discharge flow rate is 1,400 to 2,800 gpm. Discharges 

would also comply with regulatory permit conditions and would be controlled to prevent scour 

and sedimentation, flooding, and the introduction of foreign or toxic substances into the aquatic 

system. 

Due to the limited and short-term nature of stream crossings during construction of the sendout 

pipeline, installation would not likely result in significant adverse impacts. In addition, given the 

adoption of the measures in our Procedures and the measures included in Downeast’s SPCC 

Plan, construction windows to avoid spawning fish, use of HDD construction methods, avoiding 

habitat such as riffle pools, and other mitigations and best practices being employed, we 

conclude that impacts on waterbodies and their effects to aquatic life would be effectively 

minimized.

Operation Impacts 

Operation of the sendout pipeline would not have a permanent impact on fishery resources. The 

pipeline would be buried below the bed of waterbodies, and the bed and banks of the streams 

would be stabilized and restored. If maintenance activities were required, Downeast would 

employ protective measures substantially the same as those used during construction. As a 

result, any impacts derived from maintenance would be short term in nature and similar to those 

discussed above for the initial pipeline construction. The minor clearing of riparian vegetation in 

localized areas would not be expected to cause significant temperature increases downstream. 

As stated above, Downeast would allow a riparian buffer at least 25 feet wide to permanently 

revegetate with native plant species across the right-of-way after construction is complete. 
4.5 – Wildlife and Aquatic Resources ion 4-136

4.5.3 Essential Fish Habitat 

The MSA (Public Law 94-265 as amended through October 11, 1996) was established, along 

with other goals, to promote the protection of EFH in the review of projects conducted under 

federal permits, licenses, or other authorities that affect or have the potential to affect such 

habitat. EFH is defined in the act as those waters and substrate necessary to fish for spawning, 

breeding, feeding, or growth to maturity.

Federal agencies that authorize, fund, or undertake activities that may adversely impact EFH 

must consult with NOAA Fisheries. Although absolute criteria have not been established for 

conducting EFH consultations, NOAA Fisheries recommends consolidated EFH consultations 

with interagency coordination procedures required by other statutes, such as the NEPA, Fish and 

Wildlife Coordination Act, ESA, or the Federal Power Act (50 CFR 600.920(e)) in order to 

reduce duplication and improve efficiency. Generally, the EFH consultation process includes the 

following steps:

1) Notification – The action agency should clearly state the process being used for EFH 

consultations (e.g., incorporating EFH consultation into EIS, Section 10 permit, etc.).

2) EFH Assessment – The action agency should prepare an EFH Assessment that includes 

both identification of affected EFH and an assessment of impacts. Specifically, the EFH 

should include: (1) a description of the proposed action; (2) an analysis of the effects 

(including cumulative effects) of the proposed action on EFH, the managed fish species 

and major prey species; (3) the federal agency’s views regarding the effects of the action 

on EFH; and (4) proposed mitigation, if applicable.

3) EFH Conservation Recommendations – After reviewing the EFH Assessment, NOAA 

Fisheries would provide recommendations to the action agency regarding measures that 

can be taken by that agency to conserve EFH.

4) Agency Response – Within 30 days of receiving the NOAA Fisheries recommendations, 

the action agency must respond to NOAA Fisheries. The action agency may notify 

NOAA Fisheries that a full response to the conservation recommendations will be 

provided by a specified completion date agreeable to all parties. The response must 

include a description of measures proposed by the agency for avoiding, mitigating, or 

offsetting the impact of the activity on EFH. 

In 2009, the FERC staff consolidated EFH consultations for the Downeast LNG Project with the 

interagency coordination procedures required under NEPA and ESA. On May 19 of that year, 

the FERC contacted NOAA Fisheries for the purposes of reviewing this project under NEPA. 

NOAA Fisheries provided recommendations to the FERC on June 25, 2009 regarding mitigation 

and EFH conservation for the project. NOAA Fisheries indicated that construction and operation 

of the proposed Downeast LNG Project would result in adverse effects to fishery resources and 

habitats. NOAA Fisheries recommended that seasonal work restrictions be developed in 

consultation with federal and state resource agencies, that measures be taken to reduce intake 

velocity to minimize egg and larval entrainment, and that site-specific HDD plans be developed.

In addition, NOAA Fisheries recommend that a biological monitoring plan be presented and that 
4-137 4.5 – Wildlife and Aquatic Resources

a compensatory mitigation be provided to offset temporary and permanent impacts on fishery 

resources and habitats. 

An assessment of potential effects of the project on EFH, incorporating NOAA Fisheries 

comments on the draft EIS has been included in Appendix G. The EFH Assessment includes a 

detailed description of the life history characteristics and habitat preferences of EFH species and 

a discussion of the potential for these species to occur within the proposed project’s area of 

potential effect. A summary of the EFH assessment is included in the following sections.

4.5.3.1 Waterway for LNG Marine Traffic and LNG Terminal

To delineate EFH, coastal waters were mapped by regional Fisheries Management Councils 

(FMCs) and superimposed with 10-minute by 10-minute square coordinate grids or quadrants. 

The proposed project’s terminal area crosses three of the 10-minute by 10-minute quadrants that 

have been designated EFH for 29 species of finfish, three species of shellfish, and four species of 

skate. However, based on the review of available literature, we believe that the project would 

have no impact on 22 of these species because the project would not be within the known range 

of the species, the project would not impact habitat for the species, or EFH has not been 

designated for the species in question (see table 4.5.3.1-1). These 22 species are not addressed 

further in this assessment. 

TABLE 4.5.3.1-1

Essential Fish Habitat Designated by NEFMC for Species Identified as Occurring in the Waters of Passamaquoddy 

Bay, Maine, Eliminated from Further Consideration for the Downeast LNG Project

Species Reason for Elimination from Further Consideration Determination

of Effect

Barndoor skate (Dipturus laevis) EFH not designated for this species within the project area No Effect

Black sea bass (Centropristus striata) Relative abundance is rare within the project area No Effect

Bluefish (Pomatomus saltatrix) Relative abundance is rare within the project area No Effect

Butterfish (Peprilus triacanthus); 

also called Atlantic butterfish

Relative abundance is rare within the project area No Effect

Haddock (Melanogrammus aeglefinus) Relative abundance is rare within the project area No Effect

Little skate (Leucoraja erinacea) EFH not designated for this species within the project area No Effect

Long finned squid (Loligo pealei) Relative abundance is rare within the project area No Effect

Monkfish (Lophius americanus) Relative abundance is rare within the project area No Effect

Ocean quahog (Artica islandica) Relative abundance is rare within the project area No Effect

Offshore hake (Merluccius albidus) Relative abundance is rare within the project area No Effect

Redfish (Sebastes fasciatus) Relative abundance is rare within the project area No Effect

Scup (Stenotomus chrysops) Relative abundance is rare within the project area No Effect

Short finned squid (Illex illecebrosus) Relative abundance is rare within the project area No Effect

Smooth skate (Malacoraia senta) EFH not designated for this species within the project area No Effect

Spiny dogfish (Squalus acanthias) Relative abundance is rare within the project area No Effect

Summer flounder (Paralicthys dentatus) Relative abundance is rare within the project area No Effect

Surf clam (Spisula solidissima) Relative abundance is rare within the project area No Effect

Thorny skate (Amblyraja radiata) EFH not designated for this species within the project area No Effect

Tilefish (Lopholatilus chamaeleonticeps) Relative abundance is rare within the project area No Effect

Winter skate (Leucoraja ocellata) EFH not designated for this species within the project area No Effect
4.5 – Wildlife and Aquatic Resources ion 4-138

TABLE 4.5.3.1-1

Essential Fish Habitat Designated by NEFMC for Species Identified as Occurring in the Waters of Passamaquoddy 

Bay, Maine, Eliminated from Further Consideration for the Downeast LNG Project

Species Reason for Elimination from Further Consideration Determination

of Effect

Witch flounder (Glyptocephalus cynoglossus) Relative abundance is rare within the project area No Effect

Yellowtail flounder (Pleuronectes ferruginea) Relative abundance is rare within the project area No Effect

Sources: Jury et al.1994, David K. Stevenson, Ph.D (personal communication)

The remaining 14 species, and their associated life history stages, with designated EFH that are 

identified as occurring or having the potential of occurring within the project area are listed in 

table 4.5.3.1-2. A detailed description of the life history characteristics and habitat preferences 

of EFH species is provided in the EFH Assessment included as Appendix G, as is a discussion of 

the potential for these species to occur within the proposed project’s terminal area of potential 

effect. 

In general, many of the impacts on benthos described in section 4.5.2.1 and section 4.5.2.2 are 

also relevant in many instances as a component of impacts on EFH. Seafloor disturbances would 

have both temporary and permanent impacts on demersal species such as loss of eggs, temporary 

reduction in benthic prey items, or loss of habitat from the pilings associated with the pier. 

Construction of the pier and shading during operation would have some impact on eelgrass 

recently identified by Maine DMR mapping. The pier would cross about 350 feet of mapped 

eelgrass and impact an estimated 0.6 acre from shading during operation. We have 

recommended that Downeast conduct project specific mapping and determine potential presence 

and extent of eelgrass and need for mitigation for these impacts (see section 4.4.2.2). 

Entrainment of eggs and larvae would occur with water withdrawals for LNG vessel ballast, 

hoteling, fire suppression, and engine cooling needs, as well as weekly fire suppression system 

testing and the one-time hydrostatic test water withdrawals associated with the testing of the 

LNG storage tanks. However, we believe that the significant tidal fluctuations and water 

exchange that occurs in the project area; the high densities of zooplankton and ichthyoplankton; 

and the comparatively small amount of water withdrawn suggest that the overall impacts on 

zooplankton, ichthyoplankton, and mysid shrimp in the project area would have inconsequential 

effects to overall community populations and associated fish stocks. NOAA Fisheries has 

recommended that Downeast conduct monitoring to confirm our conclusions. While we 

understand NOAA Fisheries’ request for ichthyoplankton and zooplankton field survey data 

during water withdrawals by the LNG carrier, we believe that Downeast’s use of best available 

scientific data for plankton impacts are adequate to determine impacts. Further, we note that 

Downeast would have no control over the LNG vessels calling on the Project, and would not be 

able to conduct adaptive management to minimize impacts on the plankton during operation of 

the vessels. Any new navigation safety upgrades or enhancements, such as data buoys and aids 

to navigation, installed in the waterway would have no effect to EFH. 

Impacts on EFH from pier construction across Mill Cove would primarily be temporary, and the 

acreage affected for construction of the pier is small. The pier is relatively narrow and would be 

of sufficient height above the water as to have minimal shading affects. The pilings would create 
4-139 4.5 – Wildlife and Aquatic Resources

structures that could benefit some species and may interfere with other species’ use of the area. 

Operation of the LNG terminal and the associated increase in vessel traffic in the waters of the 

proposed transit route would result in increased levels of noise, water use, and nighttime lighting 

at the pier, which could alter conditions and affect species residing in or moving through these 

areas.

4.5.3.2 Sendout Pipeline

The proposed route for the project’s sendout pipeline crosses a portion of the St. Croix River 

longitudinally. NOAA Fisheries has designated the St. Croix River as EFH and as a Habitat 

Area of Particular Concern for Atlantic salmon. EFH for Atlantic salmon is described as all 

waters currently or historically accessible to Atlantic salmon within the streams, rivers, lakes, 

ponds, wetlands, and other waterbodies of Maine, New Hampshire, Vermont, Massachusetts, 

Rhode Island, and Connecticut. In general, impacts on the benthos as described in 

sections 4.5.2.1 and 4.5.2.2 would be avoided since the longitudinal crossing of the St. Croix 

River and the crossing of the head of Magurrewock Stream would be done using HDD, as 

described in detail in section 4.5.2.3. Entrainment of eggs and larvae would not occur as a result 

of hydrostatic test water withdrawals associated with the testing of the sendout pipeline system, 

because the water would be obtained from the BUD through a direct connection to the fire 

hydrant system not directly from the St. Croix River or Magurrewock Stream. Downeast would 

require make-up water for mixing of the HDD drilling mud, but has not yet identified a source. 

Impacts on EFH associated with the operation of the sendout pipeline are not anticipated.

TABLE 4.5.3.1-2

Essential Fish Habitat Designated by NEFMC for Species Identified as Occurring or Having the

Potential of Occurring, With Relative Abundance Estimates for Saltwater Salinity Zones, 

Within the Project Area in the Waters of Passamaquoddy Bay, Maine

Species Eggs Larvae Juveniles Adults Spawning Adults

American plaice (Hippoglossoides platessoides) C C C C C

Atlantic cod (Gadus morhua) C C C

Atlantic halibut (Hippoglossus hippoglossus) ND ND ND ND ND

Atlantic herring (Clupea harengus A H H

Atlantic mackerel (Scomber scombrus) C C

Atlantic salmon (Salmo salar) C C

Atlantic sea scallop (Placopecten magellanicus) A A A A A

Ocean pout (Macrozoarces americanus) A A A A A

Pollock (Pollachius virens) C A C

Red hake (Urophycis chuss) C C

White hake (Urophycis tenuis) A A

Whiting (Merluccius bilinearis) also called Silver hake A A

Windowpane flounder (Scopthalmus aquosus) C C C C C

Winter flounder (Pleuronectes americanus) H H H H H

Sources: NEFMC 1998a; Jury et al. 1994

Key:

A indicates that EFH has been designated within the square for a given species and life stage with abundant relative abundance.

C indicates that EFH has been designated within the square for a given species and life stage with common relative abundance.

H indicates that EFH has been designated within the square for a given species and life stage with highly abundant relative 

abundance.

ND indicates no relative abundance data reported, but life history stage is known to occur.

Blank cells indicate that the particular life history stage is not known to occur based on Jury et al. 1994.
4.6 – Threatened, Endangered,

and Other Special Status Species

4-140

4.6 THREATENED, ENDANGERED, AND OTHER SPECIAL STATUS SPECIES

Federal agencies are required by Section 7 of the ESA (Title 16 USC Part 1536(c)), as amended 

(1978, 1979, and 1982), to ensure that any actions authorized, funded, or carried out by the 

agency do not jeopardize the continued existence of a federally listed endangered or threatened 

species, or result in the destruction or adverse modification of the designated critical habitat of a 

federally listed species. Federal action agencies (e.g., the FERC and the COE) are required to 

consult with the FWS and/or NOAA Fisheries to determine whether federally listed endangered 

or threatened species or designated critical habitat are found in the vicinity of the proposed 

project, and to determine the proposed action’s potential effects to those species or critical 

habitats. For actions involving major construction activities with the potential to affect listed 

species for designated critical habitat, the federal agency must prepare a BA. The action agency 

must submit its BA to the FWS and/or NOAA Fisheries, and if it is determined that the action 

may adversely affect a listed species, the federal agency must submit a request for formal 

consultation to comply with Section 7 of the ESA. In response, the FWS or NOAA Fisheries 

would issue a Biological Opinion as to whether or not federal action would likely jeopardize the 

continued existence of a listed species or result in the destruction or adverse modification of 

designated critical habitat. 

As the lead federal agency conducting the NEPA analysis, FERC is also analyzing projectrelated activities authorized by the COE that could potentially affect federally listed endangered 

and threatened species. In compliance with Section 7 of the ESA, the FERC staff prepared a BA 

that was included with the draft EIS, and a revised BA submitted to the FWS and NOAA 

Fisheries in June 2012. The revised BA is included in Appendix C of this EIS. The BA details 

the environmental baseline for federally listed species and critical habitat; direct, indirect, 

interdependent and interrelated, and cumulative effects; proposed conservation measures; and 

determinations of effect. To ensure compliance with the ESA, including changes to ESA listed 

species that could occur prior to the start of construction, we recommend that:

Downeast should not begin construction until:

a. the FERC staff completes Endangered Species Act consultation with the 

FWS/NOAA Fisheries; and

b. Downeast has received written notification from the Director of OEP that 

construction or use of mitigation may begin.

A general summary of the information included in the BA is included below, along with a 

detailed assessment of project impacts on state-listed and other special status species. For 

purposes of this environmental analysis, special status species of animals and plants include 

species that are listed by the federal government as endangered, threatened, or candidate species; 

species that are listed by Maine as endangered, threatened, or species of concern; and species 

identified by federal or state agencies as rare or sensitive with the potential to occur in the 

vicinity of the proposed project.

In addition to protection by the ESA, some species are protected by other legislation. The 

MMPA prohibits, with certain exceptions, the take of marine mammals in waters of the United 

States. Six species of federally listed marine mammals have been recorded within the proposed 

Downeast LNG Project area, including North Atlantic right, fin, humpback, sei, blue, and sperm 
4.6 – Threatened, Endangered,

and Other Special Status Species

4-141

whales, while another five species of marine mammals under the protection of the MMPA are 

likely to occur in the project area. The MBTA implements various treaties and conventions for 

the protection of migratory birds. Under this act, taking, killing, or possessing migratory birds is 

unlawful. Species protected by the MBTA include the bald eagle and upland sandpiper, and 

various other species that do not receive other federal or state protection. The Bald and Golden 

Eagle Protection Act (1940; amended 1962) prohibits sale or trade of these eagle species.

In June 2003, Canada enacted the SARA to prevent Canadian indigenous species, subspecies, 

and distinct populations from becoming extirpated or extinct; to provide for the recovery of 

endangered or threatened species; and to encourage the management of other species to prevent 

them from becoming at risk. SARA prohibits killing, harming, harassing, capturing, or taking 

listed species, and destroying their habitats. Regulatory agencies overseeing jurisdictional 

enforcement include Environment Canada, Parks Canada, and Fisheries and Oceans Canada. 

Under SARA, the leatherback sea turtle, Atlantic salmon (inner Bay of Fundy population), North 

Atlantic right whale, blue whale (Atlantic population), and northern bottlenose whale are listed 

as endangered and the fin whale, harbor porpoise, and Atlantic wolffish are listed as species of 

special concern. Note that the northern bottlenose whale and harbor porpoise are addressed in 

section 4.5.2.

Downeast initiated informal consultations with the Maine DIFW, FWS, NOAA Fisheries, and 

Maine NAP (a grant-funded program within the Maine Department of Conservation). Results of 

these consultations identified 46 federal and/or state special status species that could potentially 

occur in the project area. The FERC initiated formal consultation with the FWS and NOAA 

Fisheries on May 19, 2009. This EIS section also evaluates federally designated critical habitat 

for three ESA-listed species.

Based on review of available literature and the results of field surveys conducted by Downeast, 

we believe that the project would have no effect to 34 of these species because the project would 

not be within the known range of the species or because the project would not impact habitat for 

the species (table 4.6-1). Additionally, federally designated critical habitat for three species 

(Atlantic salmon, leatherback sea turtle, and right whale) does not overlap any feature of the 

proposed project. These 34 species and federally designated critical habitats are not addressed 

further in this EIS. The remaining 12 species are listed in table 4.6-2 and discussed below.

TABLE 4.6-1

Federally and State-Listed Endangered and Threatened Species or Critical Habitats Eliminated From Further 

Consideration for the Downeast LNG Project

Species Status a/ Reason for Elimination from

Further Consideration b/

Determination 

of Effect

Fish

Critical Habitat of the Atlantic 

salmon (Salmo salar)

- The sendout pipeline would not cross any waterbodies designated 

as critical habitat

No effect

Reptiles

Loggerhead Sea Turtle

(Caretta caretta)

F-T Project area occurs north of typical range; extremely rare 

occurrence within Gulf of Maine. 

No effect

Atlantic Ridley Sea Turtle

(Lepidochelys kempii)

F-T Project area is beyond known habitat range for the species. No effect

Critical Habitat of the 

Leatherback Sea Turtle

- Vessels carrying LNG to the Downeast LNG terminal are unlikely 

to transit near coastal waters adjacent to Sandy Point, St. Croix, 

No effect
4.6 – Threatened, Endangered,

and Other Special Status Species

4-142

TABLE 4.6-1

Federally and State-Listed Endangered and Threatened Species or Critical Habitats Eliminated From Further 

Consideration for the Downeast LNG Project

Species Status a/ Reason for Elimination from

Further Consideration b/

Determination 

of Effect

(Dermchelys coriacea) U.S. Virgin Islands.

Blandings Turtle

(Emydoidea blandingii)

ME-E Suitable habitat not present in project area. No effect

Spotted Turtle

(Clemmys guttata)

ME-T Suitable habitat not present in project area. No effect

Mammals

Canada lynx (Lynx 

Canadensis)

F-T Suitable habitat not present in project area. No effect

Critical Habitat of the North 

Atlantic right whale (Eubalaena 

glacialis)

- Marine traffic route and LNG terminal would not directly impact 

designated critical habitat for this species

No effect

New England Cottontail

(Sylvilagus transitionalis)

C Suitable habitat not present in project area. No effect

Birds

Least Tern

(Sterna antillarum)

ME-E Marine traffic route and LNG terminal would not directly impact 

the nearshore habitats associated with this species.

No effect

Razorbill

(Alca torda)

ME-T Marine traffic route and LNG terminal would not directly impact 

the nearshore habitats associated with this species.

No effect

Atlantic Puffin

(Fratercula Circticca)

ME-T Marine traffic route and LNG terminal would not directly impact 

the nearshore habitats associated with this species.

No effect

Harlequin Duck

(Histrionicus histrionicus)

ME-T Marine traffic route and LNG terminal would not directly impact 

the nearshore habitats associated with this species.

No effect

Arctic Tern

(Sterna paradisaea)

ME-T Marine traffic route and LNG terminal would not directly impact 

the nearshore habitats associated with this species.

No effect

Golden Eagle

(Aquila chrysaetos)

ME-E Marine traffic route and LNG terminal would not directly impact 

the nearshore habitats associated with this species.

No effect

American Pipit

(Anthus rubescens)

ME-E Marine traffic route and LNG terminal would not directly impact 

the nearshore habitats associated with this species.

No effect

American Pipit

(Anthus rubescens)

ME-E Marine traffic route and LNG terminal would not directly impact 

the nearshore habitats associated with this species.

No effect

Piping plover (Charadrius 

melodus)

F-T Marine traffic route and LNG terminal would not directly impact 

the nearshore habitats associated with this species.

No effect

Roseate tern (Sterna dougallii 

dougallii)

F-E Marine traffic route and LNG terminal would not directly impact 

the nearshore habitats associated with this species.

No effect

Upland Sandpiper

(Bartramia longicauda)

ME-T Suitable habitat not present in project area. No effect.

Plants

Prairie White-fringed Orchid

(Platanthera llecuophaea)

F-T Suitable habitat not present in project area. No effect

Furbish’s Lousewort

(Pedicularis furbishiae)

F-T Suitable habitat not present in project area. No effect

Sparse-flowered Sedge

(Carex tenuiflora)

ME-SC Suitable habitat not present in project area. No effect

Bog Bedstraw

(Galium labradoricum)

ME-SC Suitable habitat not present in project area. No effect

Small whorled pogonia (Isotria 

medeoloides)

F-T Suitable habitat not present in project area. No effect

White Wood Aster

(Aster divaricatus)

ME-T Suitable habitat not present in project area. No effect

Swamp White Oak

(Quercus bicolor)

ME-T Suitable habitat not present in project area. No effect
4.6 – Threatened, Endangered,

and Other Special Status Species

4-143

TABLE 4.6-1

Federally and State-Listed Endangered and Threatened Species or Critical Habitats Eliminated From Further 

Consideration for the Downeast LNG Project

Species Status a/ Reason for Elimination from

Further Consideration b/

Determination 

of Effect

Scarlet Oak

(Quercus coccinea)

ME-E Suitable habitat not present in project area. No effect

Dryland Sedge

(Carex siccata)

ME-SC Suitable habitat not present in project area. No effect

Broad Beech Fern 

(Phegopteris hexagonoptera)

ME-SC Suitable habitat not present in project area. No effect

Awned Sedge

(Cyperus squarrosus)

ME-SC; Ex? Suitable habitat not present in project area. No effect

Showy Lady’s-Slipper

(Cypripedium reginae)

ME-T Suitable habitat not present in project area. No effect

Swamp Fly-Honeysuckle

(Lonicera oblongifolia)

ME-SC Suitable habitat not present in project area. No effect

Invertebrates

Ebony Boghaunter

(Williamsonia fletcheri)

ME-SC Species is to be delisted in the state of Maine. No effect

Juniper Hairstreak Butterfly 

(Callophrys gryneus)

ME-E Suitable habitat not present in project area. No effect

Brook Floater

(Alasmidonta varicose)

ME-T Suitable habitat not present in project area. No effect

Creeper 

(Strophitus undulatus)

ME-SC Suitable habitat not present in project area. No effect

a/ Status: F = Federal, ME = Maine, E = Endangered, T = Threatened, SC = Species of Concern, C=Candidate, Ex?=Possibly 

Extirpated.

b/ Downeast conducted habitat surveys during 2006. 

4.6.1 Current Status of Species

This section describes the federally and state-threatened, endangered, and candidate species that 

have the potential to occur within or adjacent to the proposed project. Note that the BA provides 

detailed discussions of federally threatened and endangered species; whereas ESA candidate and 

state-listed species are only discussed in this EIS. 

TABLE 4.6-2

Federally and State-Listed Wildlife and Plant Species and Designated Critical Habitats that Potentially Occur

Near the Downeast LNG Project

Species Habitat near the Project Facilities with Potential

to Affect Species

Federal

Status a/

State

Status a/

Determination

of Effects b/

Fishes

Atlantic Salmon

(Salmo salar)

Dennys River (ME) and other 

streams within the Gulf of Maine 

DPS Geographic Range

Waterway; LNG Terminal;

Sendout Pipeline

E - NLAA

Atlantic Wolffish

(Anarhichas lupus)

Rocky outcroppings or seaweed 

beds in Georges Bank and 

western Gulf of Maine

Waterway C - NLAA

Shortnose Sturgeon

(Acipenser 

brevirostrum)

Coastal bays, estuaries, and 

rivers

Waterway; LNG Terminal E - NLAA
4.6 – Threatened, Endangered,

and Other Special Status Species

4-144

TABLE 4.6-2

Federally and State-Listed Wildlife and Plant Species and Designated Critical Habitats that Potentially Occur

Near the Downeast LNG Project

Species Habitat near the Project Facilities with Potential

to Affect Species

Federal

Status a/

State

Status a/

Determination

of Effects b/

Atlantic Sturgeon 

(Acipenser oxyrinchus)

Coastal bays, estuaries, and 

rivers

Waterway; LNG Terminal T - NLAA

Mammals

North Atlantic Right 

Whale

(Eubalaena glacialis)

Coastal Waterway; E - NLAA

Fin Whale

(Balaenoptera physalus)

Coastal Waterway; E - NLAA

Humpback Whale

(Megaptera 

novaeangliae)

Coastal Waterway; E - NLAA

Sei Whale

(Balaenoptera borealis)

Coastal Waterway; E - NLAA

Blue Whale

(Balaenoptera 

musculus)

Offshore Waterway; E - NLAA

Sperm Whale

(Physeter 

macrocephalus)

Offshore Waterway E - NLAA

Reptiles

Leatherback Sea Turtle 

(Dermchelys coriacea)

Marine – offshore Waterway; LNG Terminal E - NLAA

Birds

Bald Eagle

(Haliaeetus 

leucocephalus)

Coastal habitat and open 

waterbodies

Waterway; LNG Terminal;

Sendout Pipeline

- T N/A

a/ Candidate (C); Endangered (E); Threatened (T), Special Concern Species (SC),; no listing ( - )

b/ May Affect, Not Likely to Adversely Affect (NLAA); Likely to Adversely Affect (LAA); No Effect (NE) and Not Applicable (N/A). 

c/ Critical habitat for the leatherback sea turtle is described in table 4.6-1.

4.6.1.1 Federally Listed Threatened and Endangered Species

Fish

Atlantic Salmon

In the United States, the Gulf of Maine DPS of Atlantic salmon was federally listed as 

endangered in eight Maine rivers in November 2000 (65 FR 69459). In September 2008, the 

Services determined that naturally spawned and conservation hatchery populations of Atlantic 

salmon whose freshwater range occurs in the watersheds from the Androscoggin River 

northward along the Maine coast to the Dennys River, constitutes a new Gulf of Maine DPS and 

hence a ‘‘species’’ for listing as endangered under the ESA. Effectively, this added populations 

of Atlantic salmon from the Saco, Kennebec, and Penobscot Rivers to the eight rivers previously 
4.6 – Threatened, Endangered,

and Other Special Status Species

4-145

listed by the Services in 2000 (50 CFR Parts 17 and 224). In June 2009, the Services expanded 

the Maine DPS to officially include populations existing in the Androscoggin, Kennebec, and 

Penobscot River basins (74 FR 29344). Additionally, the Atlantic salmon Inner Bay of Fundy 

population is listed by Canada’s SARA as endangered.

On June 19, 2009, the entire occupied range of the Gulf of Maine DPS was designated as critical 

habitat in 45 specific areas occupied by Atlantic salmon, comprising 19,571 kilometers of 

perennial river, stream, and estuary habitat, and 799 square kilometers of lake habitat. These 

areas are part of three salmon habitat recovery units, including the Penobscot Bay, Merrymeeting 

Bay, and Downeast Coastal regions (74 FR 29300). On June 19, 2009, the Services revised the 

Gulf of Maine DPS to include naturally spawning and conservation hatchery populations of 

anadromous Atlantic salmon whose freshwater range occurs in the watersheds from the 

Androscoggin River northward along the Maine coast to the Dennys River (74 FR 29300 29341). 

The DPS also includes wherever listed salmon occur in the marine and estuarine environment. 

Many factors contributed to the listing of Atlantic salmon in the Gulf of Maine DPS, including 

(but not limited to) critically low numbers of adult returns, low marine survival rates, altered 

water quality of freshwater habitat, and disease, among others. In 2005, the Final Recovery Plan 

for the Gulf of Maine Distinct Population Segment of Atlantic Salmon (NOAA Fisheries and 

FWS 2005a) was completed. A new status review for the Gulf of Maine DPS was published in 

July 2006. 

Adult Atlantic salmon live at sea, but return to their natal freshwater streams to spawn. 

Spawning typically occurs during mid-October to mid-November. Typical stream spawning 

areas consist of gravelly substrates within riffle habitat. Eggs develop through the winter and 

hatch as larvae in spring. Newly hatched salmon remain in or near the nest until the parr stage 

(when vertical bars develop along the sides). Habitat used by parr is typically riffle areas 

characterized by adequate cover (gravel and rubble up to 20 cm), moderate water depth (10 to 

60 cm) and moderate to fast water flow (30 to 90 cm/sec). Parr remain in freshwater from two to 

six years, and begin the physiological transformation that prepares them for marine habitats 

when they reach 12 to 24 cm in length. The time at which parr move downstream toward the sea 

varies from late spring to fall, but in Gulf of Maine streams this usually occurs in June and July 

(Baum 1997). In general, salmon prefer cool water temperatures; water temperatures greater 

than 82°F (28°C) is considered harmful, and greater than 75°F (24°C) is thought to inhibit 

growth and contribute to overwinter mortality. The marine stage of the Atlantic salmon life 

cycle is the least understood; however, salmon will spend one to three years at sea before 

returning to spawn in the natal streams. The occurrence of documented Atlantic salmon habitats 

is shown in Appendix F, figure F-35. 

Atlantic Wolffish

The Atlantic wolffish is listed as a species of concern and is undergoing a status review, as a 

candidate species, to determine if ESA listing is warranted; it is listed as a species of special 

concern under Canada’s SARA. The Atlantic wolffish are distributed in the North Atlantic 

Ocean from the Northwest Atlantic Shelf region off North America, to Greenland, Iceland, and 

the waters off of Northern Europe. In the Northwestern Atlantic, it is found in waters off 

western Greenland and southern Labrador, in the Strait of Belle Isle and the Gulf of 

St. Lawrence, off the eastern and western coasts of Newfoundland and over the Grand Banks 

south to the Scotian Shelf, in the Gulf of Maine and on Georges Bank. The Atlantic wolffish is a 
4.6 – Threatened, Endangered,

and Other Special Status Species

4-146

large, slow growing, and late maturing species. In the Gulf of Maine, spawning is thought to 

occur between September and October; incubation lasts three to nine months, depending on the 

water temperature (74 FR 249). Atlantic wolffish appear to prefer bottom substrates such as 

rocky outcroppings or seaweed beds (Collette and Klein-MacPhee 2002). West of the Scotian 

Shelf, wolffish abundance is highest in the southwestern portion of the Gulf of Maine from 

Jeffreys Ledge to Great South Channel at depths of 80 to 120 meters (260 to 330 feet) (NOAA 

Fisheries 2007). While it is believed to be a relatively sedentary and solitary demersal species, 

Collette and MacPhee (2002) suggest that feeding takes place away from its shelter sites. The 

Atlantic wolffish feeds primarily on benthic fauna (e.g., bivalves, gastropods, decapods, and 

echinoderms). Although the diet of this species shows strong regional variation, it consists 

mainly of various species of mollusks, crustaceans, echinoderms and less frequently, fishes. As 

predators, Atlantic wolffish may also be key factors in controlling density and distribution of 

certain benthic invertebrates, such as sea urchin (O’Dea and Haedrich 2000). 

Threats to the Atlantic wolffish include incidental bycatch in otter trawl fisheries (NOAA 

Fisheries 2006a). Trawling and dredging activities are also believed to be responsible for 

degradation of wolffish habitats. The stock is considered to be overexploited and depleted. 

Shortnose Sturgeon

The shortnose sturgeon was listed as endangered throughout its range under the Endangered 

Species Preservation Act of 1966. This species is also listed as a species of concern by the 

Committee on the Status of Endangered Wildlife in Canada (COSECWIC). Shortnose sturgeon 

are typically long lived, and exhibit delayed sexual maturity and high reproductive capacity. The 

maximum known age for females is 67 years, however males seldom exceed 30 years. 

Reproduction and growth characteristics vary with latitude due to the effect of differing 

temperature regimes, with northern populations typically exhibiting slower growth and later 

maturity. In the north, females typically reach maturity at 12 to 18 years of age and males at 

10 to 11 years of age. The first spawning may occur 1 to 16 years after maturity, and continues 

annually at intervals of a few to several years. Spawning occurs in the spring at or above the 

head of the tide in sand to boulder sized substrate with low-medium water flow (0.2 to 

1.8 m/sec). Eggs, which are laid in freshwater, hatch and larvae drift downstream and remain 

there for 3 to 10 years. Shortnose sturgeon then move to the freshwater/saltwater interface. 

Adults may occur in freshwater or tidal areas of rivers during summer and winter, where they 

concentrate in areas of decreased flow thought to be associated with conditions suitable for their 

prey. Shortnose sturgeon prefer the nearshore marine, estuarine and riverine habitat of large 

river systems, and rarely is found offshore. Juveniles feed on benthic macroinvertebrates and 

crustaceans, whereas adults feed on molluscs and large crustaceans. 

The shortnose sturgeon is anadromous, living mainly in the slower moving riverine or nearshore 

marine waters, and migrating periodically into faster moving fresh water areas to spawn. 

However, unlike other anadromous species in the region, shortnose sturgeon do not appear to 

make long distance offshore migrations. Sturgeon are usually most abundant in estuaries, and 

are generally found within a few miles of land when at sea. Nineteen distinct population 

segments of shortnose sturgeon occur in rivers ranging from the Saint John River in New 

Brunswick, Canada, to the St. Johns River in Florida. Within the Northeast, DPSs include the St. 

John River (New Brunswick, Canada), and the Penobscot, Kennebec, and Merrimack River 
4.6 – Threatened, Endangered,

and Other Special Status Species

4-147

watersheds (table 4.6.1.1-1). Primary threats to the shortnose sturgeon are pollution and 

overharvesting for commercial fisheries, including bycatch in the shad fishery.

TABLE 4.6.1.1-1 

Subset of Shortnose Sturgeon Distinct Population Segments in the Northeast

DPS Streams within DPS

St. John River St. John River, New Brunswick, Canada

Penobscot River Dennys, Machias, East Machias, Penobscot, Ducktrap

Kennebec River Sheepscot, Kennebec, Androscoggin, Royal, Presumpscot, Saco, Kennebunk, York

Merrimack River Merrimack River

Atlantic Sturgeon

On January 31, 2012, NOAA Fisheries issued a final determination that lists the Atlantic 

sturgeon as threatened for the Gulf of Maine DPS (77 FR 5880). The remaining four DPSs (New 

York Bight, Chesapeake Bay, Carolina, and South Atlantic) have been listed as endangered.

This species is not listed in Canada. 

The Atlantic sturgeon is a long lived, late maturing, estuarine dependent, anadromous species. It 

spawns in freshwater, but spends most of its adult life in the marine environment. Females may 

live to over 60 years; however, males are thought to live about 30 years. Spawning adults 

migrate upriver from April to May in mid-Atlantic waters and May to July in Canadian waters. 

This species is highly migratory. Atlantic sturgeon spawning is thought to occur in large rivers 

where flow rates are between 1.5 to 2.5 feet per second (ft/s) and depths of 36 to 89 feet. 

Sturgeon eggs adhere to hard bottom substrates (e.g., cobble), and hatch 4 to 6 days later. Newly 

hatched larval fish begin migrating downstream to rearing habitats after 8 to 12 days; as it 

develops into the juvenile stage, it continues moving downstream into brackish waters, and 

eventually become a resident in estuarine waters for months or years. Subadults move to coastal 

waters after reaching lengths of 30 to 36 inches. Despite its extensive migrations, the adult 

sturgeon returns to its natal stream for spawning. Males return first and remain in the natal 

stream for the entire spawning period, whereas females leave the spawning grounds soon after 

eggs are laid (Atlantic Sturgeon Status Review Team 2007). Spawning intervals are irregular; 

males are thought to spawn every one to five years, and females every two to five years.

The growing demand for caviar in the 1870s is largely responsible for the intense pressures on 

this fishery, ultimately causing its collapse by 1901. The Atlantic sturgeon fishery was closed by 

the Atlantic States Marine Fishery Commission in 1998, when a coastwide fishing moratorium 

was imposed. Pollution, habitat degradation (e.g., dewatering of streams, changes in 

physiochemical properties of streams, and physical alteration of in-stream habitats), fishing 

exploitation in spawning habitats, and as bycatch in marine fisheries all represent critical threats 

to this species. Additionally, individuals are susceptible to vessel strikes (Atlantic Sturgeon 

Status Review Team 2007).

The Atlantic sturgeon is currently present in 35 rivers, and spawning occurs in at least 20 of 

these rivers (Atlantic Sturgeon Status Review Team 2007). The geomorphology of most small 

coastal rivers in Maine is not sufficient to support Atlantic sturgeon spawning populations, 

except for the Penobscot and the estuarial complex of the Kennebec, Androscoggin, and 
4.6 – Threatened, Endangered,

and Other Special Status Species

4-148

Sheepscot Rivers. During the summer months, the salt wedge intrudes almost to the site of 

impassable falls in the St. Croix River (river kilometer [rkm] 16), Machias River (rkm 10), and 

the Saco River (rkm 10). The Atlantic Sturgeon Status Review Team note that in the St. Croix

River, spawning habitat is largely lacking because of this salt wedge. Although surveys have not 

been conducted to document Atlantic sturgeon presence, subadults may use the estuaries of these 

smaller coastal drainages during the summer months.

Marine Mammals 

Informal consultation with NOAA Fisheries and Maine DIFW determined that six threatened or 

endangered species of whale, including North Atlantic right, fin, humpback, sei, blue, and sperm, 

are known to or potentially occur within the proposed project area. Toothed whales, such as the 

sperm whale, feed on invertebrates and fish, whereas baleen whales filter zooplankton and small 

fish from the water column. As described in section 4.5.2.1, five other species of marine 

mammal are likely to occur in the project area, including minke whale, gray seal, harbor seal, 

harbor porpoise, and white-sided dolphin and are protected by the MMPA. Depending on the 

species, cetaceans can perceive sounds between 10 and 150,000 Hz. Peak underwater sound 

detection in most baleen whales is within the range of 10 to 10,000 Hz. Toothed whales emit 

various sounds, including tonal whistles, pulsed sounds, and less distinct pulsed sounds. 

North Atlantic Right Whale 

The North Atlantic right whale is the most endangered large whale species in the world. This 

species was originally protected by the 1931 Convention for the Regulation of Whaling, which 

took effect in 1935. It has been further protected from commercial whaling by the International 

Whaling Commission since 1949, Endangered Species Conservation Act since 1970, the ESA 

and the MMPA since 1973 (NOAA Fisheries 2005b). The World Conservation Union (IUCN) 

listed the North Atlantic right whale as endangered in 1986 and it still possesses this status 

(IUCN 2005). In 2008, NOAA Fisheries listed the northern right whale (Eubalaena spp.) as two 

separate, endangered species: the North Pacific right whale (E. japonica) and the North Atlantic 

right whale (E. glacialis) (73 FR 12024). This species is designated as endangered in the state of 

Maine and by SARA. Federal law prohibits approaching a right whale within 500 yards, and as 

of December 2008. Vessels of 65 feet or greater in length are required to restrict speeds to 10 

knots when traversing seasonally managed areas (50 CFR Part 224). In 1994, NOAA Fisheries 

designated three critical habitats for the North Atlantic right whale, including coastal Florida and 

Georgia (Sebastian Inlet, FL to the Altamaha River, GA), the Great South Channel (east of Cape 

Cod), and Massachusetts Bay and Cape Cod Bay. In 2009, NOAA Fisheries and Oceans Canada 

designated critical habitats in Grand Manan Basin (in the Bay of Fundy) and in Roseway Basin 

(off the Scotian Shelf). Recent observations by NOAA’s Northeast Fisheries Science Center 

may be evidence of a wintering ground and potentially a breeding ground over Jordan’s Ledge, 

an area in the Gulf of Maine about 70 miles from Bar Harbor (NOAA 2008). Currently, the 

greatest threats to North Atlantic right whales are vessel collisions and fishing gear 

entanglement.

The North Atlantic right whale is highly migratory. This species ranges between southeastern 

U.S. coastal waters during overwinter and calving and New England waters northward to the Bay 

of Fundy and the Scotian Shelf to visit nursery areas and summer feeding grounds (Waring et al. 
4.6 – Threatened, Endangered,

and Other Special Status Species

4-149

2006). Recent years have seen an increase in reported calf production, peaking at 39 reported 

calves in 2009 with only a single calf mortality (NOAA Fisheries 2010; Waring et al. 2010). 

In spring, peak abundance occurs in the Great South Channel (Kenney et al. 1995; Kenney et al. 

2001), an area east of Cape Cod. In summer and fall, the majority of the right whale population 

occurs in the Bay of Fundy and the Scotian Shelf (Kenney et al. 2001; Winn et al. 1986; Stone et 

al. 1990). Mother/calf pairs are also observed in the Bay of Fundy in the summer and fall, 

whereas juvenile and adult males are primarily observed in the Roseway Basin/Browns Bank 

region (Brown et al. 2001). The western North Atlantic population size was estimated to be at 

least 444 individuals in 2009 (Waring et al. 2012) based on a census of individual whales 

identified using photo-identification techniques.

In the western North Atlantic, right whales feed primarily on copepods, with Calanus 

finmarchicus believed to be the primary prey (NOAA Fisheries 2005b). Right whale food 

resources vary widely through space and time, resulting in multiscale patches of resources 

(EPA 1993); whale movements are thus tied to locations of this preferred prey. In the lower 

Bay of Fundy and in Roseway Basin, the occurrence of right whales was associated with 

discrete layers of C. finmarchicus located in the bottom mixed layer of the water column 

(Baumgartner et al. 2003). 

North Atlantic right whales are known to occur in Head Harbour Passage, Friar Roads, Western 

Passage, and Grand Manan Channel (MacKay 2006; SENES 2007). Designated critical habitats 

for this species includes portions of Cape Cod Bay and Stellwagen Bank, the Great South 

Channel (each off the coast of Massachusetts), and waters adjacent to the coasts of Georgia and 

the east coast of Florida (50 CFR Part 226). The Canadian Department of Fisheries and Oceans 

also designated critical habitat for the North Atlantic right whale, including the Grand Manan 

Basin and Roseway Basin conservation areas. Documented sightings of the North Atlantic right 

whale are shown in Appendix F, figures F-24 through F-29. The SENES Report (2007) also 

provides documented sightings and notes that six North Atlantic right whales were observed in 

2003-2004 within a 10-mile radius of Head Harbour Light11. 

Fin Whale 

The fin whale has been federally listed in the United States as endangered since 1970, and in 

Canada the Atlantic population is listed by COSEWIC as a species of special concern. Threats 

to fin whales include entanglement in gillnets and vessel strikes.

Fin whales are found in temperate zones of the North Atlantic; however, they are known to 

migrate as far south as the Gulf of Mexico and the Mediterranean Sea. Fin whales are the most 

common large baleen whale species along the Atlantic coast between Cape Hatteras and Nova 

Scotia (Waring et al. 2010). They have the largest standing stock and the largest food 

requirements, thus having the largest impact on the ecosystem of any cetacean species (Kenney 

et al. 1997; Hain et al. 1992; Waring et al. 2010). The waters off New England represent a major 

feeding ground for fin whales, and evidence indicates that female whales show site fidelity for 

feeding areas by showing patterns of seasonal occurrence and annual returns (Waring et al. 

2010). Typical prey species include sand lance, capeline, krill, herring, copepods and squid 

(Mitchell 1974; Katona et al. 1977). The distribution of sand lance (Ammodytes spp.) has a 

 11 Head Harbour Light is located on Head Harbour Island, a small island located north of Campobello Island.
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strong influence on the distribution and movement of fin whales along the eastern coast (Reeves 

et al. 1998; Wilson and Ruff 1999; EPA 1993). 

Fin whales are the most abundant and frequently sighted of the endangered great whales known 

to visit the Passamaquoddy Bay area (Waring et al. 2010; SENES 2007). This species is also 

known to occur in the waters of the outer Quoddy region, Head Harbour Passage, Friar Roads, 

and Western Passage (MacKay 2006; SENES 2007). Fin whale observations are common during 

summer and fall; documented sightings were made by the Quoddy Marine Link (a whale 

watching vessel) in Blacks Harbour, Bliss Island, Whitehorse and near Head Harbour Light on 

the northern tip of Campobello Island (Quoddy Marine Link 2008). The comments of Save 

Passamaquoddy Bay note that fin whales are frequently observed in Head Harbour Passage. 

Documented sightings of the fin whale are shown in Appendix F, figures F-21 and F-24. 

Humpback Whale

The humpback whale has been federally listed as endangered since 1970 in the United States; 

however, the western North Atlantic humpback whale population is designated as “not at risk” in 

Canada. 

The humpback whale is found in all the world’s oceans, including (but not limited to) the east 

coast of the United States, the Gulf of St. Lawrence, Newfoundland/Labrador, and western 

Greenland (Katona and Beard 1990). It inhabits waters over the continental shelf and around 

some of the oceanic islands (Wilson and Ruff 1999; NOAA Fisheries 1991, 1993). Abundance 

estimates for the Gulf of Maine humpback whale sub-population has proved to be challenging 

due to the overlap in range of some of the stocks. The best abundance estimate for the Gulf of 

Maine stock is 847, with a minimum estimation of 359 animals (Waring et al. 2010). 

Humpbacks feed in temperate and polar waters in the summer, and mate and calve in tropical 

waters during the winter. Summer feeding takes place mainly while in areas over the continental 

shelf between New Jersey and Greenland. Prey species consist of small schooling fish such as 

sand lance, herring, capelin, and sometimes mackerel. Humpback whales reach peak abundance 

in New England waters during May and June, and remain there until October. Large numbers of 

humpbacks occur around the mouth of the Bay of Fundy from July through October (NOAA 

Fisheries 1991). MacKay (2006) noted occurrence of this species in the outer Quoddy region 

and Head Harbour Passage; however, this species is not expected to occur near the Western 

Passage. Documented sightings of the humpback whale are shown in Appendix F, figures F-23 

and F-24. 

Sei Whale

The sei whale is a federally listed endangered species in the United States. In Canada, the 

Atlantic population of this species is designated as “Data Deficient.”12 Threats to sei whales 

include vessel collisions and physical and acoustic harassment.

The range of the Nova Scotia stock of sei whales includes waters of the Scotian Shelf during the 

feeding season and extends southward into the Gulf of Maine and Georges Bank during spring 

and summer (Waring et al. 2010). Concentrations of sei whales tend to occur in deeper waters as 

 12 Data Deficient is defined by the Committee on the Status of Endangered Wildlife in Canada as a species for which 

there is insufficient scientific information to support status designation.
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in regions of the continental shelf edge, but this offshore pattern also includes travel into more 

shallow and inshore waters (Waring et al. 2010). 

The sei whale appears to prefer temperate, deep offshore habitat more than other species of large 

baleen whales. During times of high prey abundance, this baleen whale may be found in inshore 

waters. Sei whales have been observed in areas that would be transited by vessels along the 

proposed waterway for LNG marine traffic. This species may be present as transient individuals 

near Western Passage. Documented sightings of the sei whale are shown in Appendix F, 

figure F-24 and F-30. 

Blue Whale

The blue whale has been federally listed as endangered in the United States since 1970 and is 

also considered endangered in Canada (COSEWIC 2002). Historic threats to blue whales were 

from whaling activities. The Recovery Plan for the blue whale describes potential anthropogenic 

impacts, including vessel collision; physical and acoustic harassment; fishing gear 

entanglement/entrapment; and degradation of habitat. NOAA Fisheries (1998) indicates that 

blue whales are occasionally killed or injured after colliding with a vessel. Blue whales are 

currently of interest for tour boats in Canada, but not in the United States. 

The distribution of blue whales is thought to be dependent on prey abundance and location. This 

species is frequently sighted in waters off eastern Canada with most of the recent records being 

in the Gulf of St. Lawrence (COSEWIC 2002; NOAA Fisheries 1998; Sears et al. 1987; Waring 

et al. 2002). Blue whales occur in the Gulf of St. Lawrence during the spring, summer, and 

autumn months, mostly along the north shore from the St. Lawrence River estuary to the Strait of 

Belle Isle and off eastern Nova Scotia (Reeves et al. 2005; Waring et al. 2010). In the winter, 

this stock is found off the coast of southern Newfoundland (Waring et al. 2010). In general, little 

is known about the blue whale population size with the exception of this Gulf of St. Lawrence 

area, in which 440 individuals were catalogued from 1979 to 2009 by R. Sears (as reported in 

Waring et al. 2010). 

Sperm Whale 

The sperm whale is a federally endangered species within the United States; however, it is not 

listed in Canada. The greatest threats to sperm whales currently include vessel strikes, 

entanglement in fishing gear, changes in prey populations, habitat degradation, disturbance from 

high frequency noise, and possibly biomagnifications of pollutants (NOAA Fisheries 2006b). 

Sperm whales are found along the continental shelf edge, over the continental slope and into the 

mid-ocean regions. Most sperm whale sightings on the East Coast have occurred along the edge 

of the continental shelf, where dense concentrations of large squid, its preferred prey, occur 

(Wilson and Ruff 1999). During winter months, sperm whales concentrate east and northeast of 

Cape Hatteras, North Carolina (Waring et al. 2007). In spring months, this species migrate 

towards Delaware, Virginia, and the central portion of the mid-Atlantic bight and southern 

section of Georges Bank (Waring et al. 2007). During summer months, sperm whales are also 

found east and north of Georges Bank, into the Northeast Channel region and over the 

continental shelf south of New England (Waring et al. 2007).
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Reptiles

Leatherback Sea Turtle

Leatherback sea turtles are known to occur off the coast of Maine and are listed as endangered 

by the ESA. The leatherback sea turtle is also listed by COSEWIC as endangered. Unchecked 

harvest of leatherback sea turtle meat and eggs, as well as incidental bycatch in commercial 

fishing, are the primary causes for the decline of this population (FWS 2005); other factors such 

as degradation of foraging habitat, marine pollution and debris, and vessel strikes also 

contributed to its decline (FWS 2005; NOAA Fisheries 2006). During summer months, the 

distribution of the leatherback sea turtles includes the Gulf of Maine, along the coast of Maine 

and northward to Nova Scotia and the Labrador coast (Stellwagen Bank 2006; Maine DIFW 

2003a). Recent telemetry studies identified high-use areas in continental shelf and slope waters 

off of eastern Canada and the northeastern United States, including waters off the eastern coast 

of Nova Scotia and in the Gulf of St. Lawrence. In the fall, leatherbacks move offshore and

begin their migration south to wintertime breeding grounds; however, they do not use consistent 

migration corridors. Leatherbacks tagged with satellite transmitters at sea off the coast of Nova 

Scotia were tracked to waters adjacent to nesting beaches along the northeast coast of South and 

Central America (James et al. 2005).

The Gulf of Maine is classified as an important feeding area for leatherback sea turtles. 

Leatherback sea turtles are expected to be present in feeding areas and surrounding habitat, 

including Passamaquoddy Bay and the Bay of Fundy during the summer and fall (typically June 

through October). Critical habitat was designated for the leatherback sea turtle in 1998 for 

leatherback turtles in coastal waters adjacent to Sandy Point, St. Croix, U.S. Virgin Islands.

4.6.1.2 State-Listed and Other Special Status Species 

Birds 

Bald Eagle

The bald eagle is listed as threatened in Maine and was recently delisted as federally threatened 

effective August 8, 2007. The FWS has stated that the best available scientific and commercial 

data available indicates that the bald eagle has recovered, in part, because of actions taken from 

the regional recovery plans for the bald eagle (2007 FR 37346). For each of these regions, the 

bald eagle has achieved or surpassed the federal delisting or recovery criteria. However, there 

are additional state delisting criteria that include maintaining a “safety net” of habitats (i.e., >150 

habitats under conservation ownership, appropriate easements, or cooperative management 

agreements) that are yet to be achieved (Maine DIFW 2004). Bald eagles are still afforded 

federal protection under the Bald and Golden Eagle Protection Act. Bald eagles are not listed in 

Canada. 

The bald eagle is a bird of aquatic ecosystems inhabiting estuaries, large lakes, reservoirs, major 

rivers, and some seacoast habitats. Nesting and breeding habitat requirements include large trees 

and areas that consist primarily of old white pine in Maine; these habitats generally are located 

near water (e.g., waterways including sea coasts, lakes, and rivers) for foraging. Eagles are 

opportunistic feeders, consuming mostly fish and also birds, small mammals and reptiles, and 

carrion. In remote settings, eagle pairs can be sensitive to disturbance during the nesting season, 

typically from February through August. Limited human activity is preferable; however, 
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normally occurring noise has shown to be non-disruptive to eagle behavior (Stalmaster and 

Newman 1978). In winter, bald eagles often congregate in large numbers along streams to feed 

on spawning salmon or other fish species. 

4.6.2 Impacts and Mitigation 

4.6.2.1 Waterway for LNG Marine Traffic

Federally Listed Species

Atlantic Salmon

Atlantic salmon adults are common in Passamaquoddy Bay from May through November, and 

juveniles are common from April through June. Dube (2006) of the Maine ASC reports that 

during 2003 and 2005, a maximum of 42 returning salmon per year were sampled from the St. 

Croix River; of this number, most individuals were determined to be escaped hatchery-reared 

salmon. This relatively low number of documented returning non-hatchery reared salmon to the 

St. Croix River noted by Dube (2006) indicates that, while this species does occur in the 

waterbodies associated with the waterway for LNG marine traffic, its presence would likely be 

low. Migratory salmon present in the waterway may be temporarily displaced to adjacent waters 

by disturbance caused by LNG vessels; however, this displacement is expected to be short term 

and localized. We received a letter from NOAA Fisheries, dated November 16, 2006, that 

concurred with this assessment. Atlantic salmon adults may occur within the waterway for LNG 

marine traffic, but are unlikely to be adversely affected by the proposed project. 

Atlantic and Shortnose Sturgeon 

The Atlantic Sturgeon Status Review Team (2007) notes that a small spawning population of 

large Atlantic sturgeon may be present in the St. Croix River below the hydroelectric dam. Few 

spawning adults are anticipated to be present in the St. Croix River; however, subadults may use 

Passamaquoddy Bay in summer months. The shortnose sturgeon is not documented in the St. 

Croix River system or coastal waters near Passamaquoddy Bay, with the closest documented 

population is in the Penobscot River over 100 miles south of the Project area. However, ongoing 

studies show that at least some population of shortnose sturgeon in Maine undergo coastal 

migrations between river systems, and NOAA Fisheries (2012) suggests that although 

undocumented, the shortnose sturgeon may occur in the same rivers as the Gulf of Maine DPS of 

the Atlantic sturgeon.

It is possible that Altantic or shortnose sturgeon could be present in the waterway during project 

operation and could be temporarily displaced to adjacent waters by disturbance caused by LNG 

vessels; however, this displacement is expected to be short term and localized. It is also possible 

that sturgeon could be susceptible to vessel strikes (see discussion below).

Atlantic Wolffish

The Atlantic wolffish may occur within the waterway for LNG marine traffic, but is unlikely to 

be adversely affected by the proposed project. Impacts on demersal species such as the Atlantic 

wolffish are expected to be similar to those described in section 4.5.2.1 of this EIS. 
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Marine Mammals

Whales have been observed across the mouth of Passamaquoddy Bay from Head Harbour 

Passage up to Blacks Harbour on the coast of New Brunswick in July and August. Whale 

species have also been observed in Friar Roads, Western Passage, and Grand Manan Channel 

(MacKay 2006). However, because of the rarity of documented sightings, the presence of 

whales in the immediate area of the LNG terminal is not expected. Six species of whales 

protected by the MMPA are likely to be present in the waterway for LNG marine traffic. These 

species may be affected by vessel collisions, physical and acoustic harassment, and to a lesser 

extent by the introduction of pollution and artificial lighting. Potential impacts and proposed 

mitigation measures are discussed in further detail below; additional information about 

underwater noise is discussed in section 4.5.2 and 4.11.2 of this EIS. 

Vessel Strikes 

Protected whales are not commonly encountered in the waterway for LNG marine traffic; 

however, the increased vessel passage constitutes an increase in potential for vessel strikes to 

these species. Vulnerability to vessel collisions may result from the whale’s limited ability to 

detect or maneuver around oncoming vessels, or because the species is at the surface feeding, 

resting, mating, and/or nursing. Research associated with vessel strikes and physical harassment 

indicates that most vessel collisions with whales that result in serious injury or death occur when 

a vessel is traveling over speeds of 14 knots (Laist et al. 2001). According to Jensen and Silber 

(2003), Nelson et al. (2007), and Waring et al. (2010), there have been 198 documented 

occurrences of vessel collisions with marine mammals in the Western Atlantic Ocean (including 

the United States East Coast, United States Gulf Coast, and Eastern Canada) between 1905 and 

2008, most of which occurred off the United States East Coast. Table 4.6.2.1-1 lists the vessel 

strikes by mammal species or species group. Of strikes reported from the Western Atlantic 

Ocean, 82 percent occurred along the United States East Coast. Fin, humpback, and right whale 

collisions comprised 75 percent of these documented vessel strikes. Nelson et al. (2007) 

examined mortality and serious injury reports involving baleen whale stocks along the U.S. 

eastern seaboard between 2001 and 2005. According to this study, 11.5 percent of events 

involved vessel strikes, of which 64 percent resulted in mortality. Entanglement with fishing 

gear accounted for 32 percent of events, of which 20 percent resulted in mortality. 

A review of data from the Ocean Biogeography Information System (OBIS) and the North 

Atlantic Right Whale Consortium (NARWC) found that various marine mammal species are 

known to aggregate along portions of the proposed marine transit route (see Appendix F, 

figures F-20 to F-30). As a result, LNG vessels transiting the route have the potential to 

encounter and affect marine mammals.

Fin, humpback, sei, sperm, and blue whales have experienced both injury and mortality as the 

result of vessel strikes within each species’ habitat range (see table 4.6.2.1-1). Between 1999 

and 2008, 13 fin whales of the western North Atlantic stock were killed by vessel strikes; 14 

vessel strikes resulted in humpback whale mortalities; 2 sei whales were struck by transiting 

vessels; and 1 sperm whale was killed after colliding with a vessel (Cole et al. 2006; Waring et 

al. 2006; and Waring et al. 2010). 
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TABLE 4.6.2.1-1

Analysis of Whale Mortality and Serious Injury Reports Associated with Vessel Strikes

from the Period 1905 – 2008 a/ & b/

Species Eastern Canada U.S. East Coast U.S. Gulf Coast Total Individuals

Baleen 0 1 0 1

Blue 0 1 0 1

Fin 7 b/ 46 b/ 1 54

Humpback 1 40 b/ 1 42

Minke 1 17 1 19

Minke/small sei 0 1 0 1

North Atlantic Right 11 39 b/ 2 52

Sei 0 6 b/ 0 6

Sperm 1 3 2 6

Unknown 7 8 1 16

Total Individuals 28 162 8 198

Total Percent by Region 14% 82% 4%

a/ Whale mortality and serious injury reports (1905 through 2005) from Jensen and Silber, 2003, and Nelson et al. 2007. Only 

data associated with vessel strikes are reported in this table.

b/ Numbers updated from 2005 through 2008 Waring et al. 2010, stock assessment reports. Only data associated with vessel 

strikes are reported in this table.

Near the project area in the Bay of Fundy between the years of 1976 and 2006, there were 25 

reported right whale strikes. Of these incidences, 18 resulted in death (Jensen and Silber 2004; 

Marine Connection 2006; Nelson et al. 2007; Waring et al. 2008; and Waring et al. 2010). 

Table 4.6.2.1-2 summarizes right whale vessel strikes in the Bay of Fundy.

The proposed Downeast LNG Project would result in increased marine traffic through the Bay of 

Fundy to the project terminus in the Western Passage by as many as 60 vessels per year. 

Currently, nearby commercial ports (Port of Eastport, Maine; and Port of Bayside in Canada, 

near Calais, Maine) typically receive about 125 vessels each year, including ferries, small- to 

mid-size cruise ships, and cargo vessels. This impact reflects both a permanent increase 

(49 percent) in large vessel traffic and a temporary incremental increase from construction 

vessels to existing vessel activity associated with fishing, commercial transportation, recreational 

boating, and ferries. 

In the project area, the primary issue of concern is the protection of the North Atlantic right 

whale, as the Bay of Fundy and Passamaquoddy Bay are within important habitats for this 

species. The major apparent threat to the North Atlantic right whale and the most probable 

factor preventing recovery of this species is human-caused mortality and serious injury due to 

vessel strikes. The current strategy to minimize impacts on the North Atlantic right whale as 

well as the general conservative approach to protect other marine mammals builds upon the 

mitigation measures developed to protect this species. The greatest protection measures for 

whales are avoidance measures, followed by reduced vessel speed.
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TABLE 4.6.2.1-2

Identified Ship Strikes of North Atlantic Right Whales Near Gulf of Maine and Bay of Fundy

Date Sex Age Location where struck or found Mortality/Injury 

1972 a/ - - 97 km East of Boston, Massachusetts Mortality

04/15/1976 M Calf Massachusetts Mortality

11/05/1976 - - Maine Mortality

05/25/1980 M - Great South Channel, Massachusetts Injury

08/05/1984 UNK a/ - Browns Bank, Canada Mortality

08/14/1986 F - Bay of Fundy, Canada Presumed Mortality

07/09/1987 M Juvenile Nova Scotia, Canada Mortality

08/28/1987 UNK - Browns Bank, Canada Injury

09/05/1992 F Adults Bay of Fundy, Canada Mortality

09/16/1995 M 4 years Bay of Fundy, Canada Injury

10/19/1995 M - Bay of Fundy, Canada Mortality

08/19/1997 F - Bay of Fundy, Canada Mortality

07/08/2000 M - Bay of Fundy, Canada Unknown

09/27/2000 F - Bay of Fundy, Canada Injury

10/02/2003 F - Digby, Nova Scotia Mortality

04/28/2005 F - Monomoy Island, Massachusetts Mortality

07/24/2006 F - Campobello Island, NB Canada Mortality

08/24/2006 F - Roseway Basin, Nova Scotia, Canada Mortality

09/03/2006 F - Nova Scotia, Canada Mortality

04/19/2009 UNK - Stellwagen Bank National Marine Sanctuary Injury observed; fate 

unknown

a/ Presumed North Atlantic right whale

Source: Glass et al. 2008; Jensen and Silber 2003; Nelson et al. 2007; and Waring et al. 2008; Waring et al. 2010; Right Whale 

News 2009.

NOAA Fisheries has established regulations to limit vessel speed of vessels 65 feet or longer that 

transit certain management areas along the U.S. East Coast (Right Whale Ship Strike Reduction 

Rule, 50 CFR Part 224). Evidence suggests that the likelihood of death and serious injury to 

large whales struck by vessels is related to vessel speed. The regulations were issued October 8, 

2008 and went into effect on December 9, 2008. The regulations establish (1) Seasonal 

Management Areas (SMAs), which are predetermined and established areas within which a 

seasonal speed restriction of 10 knots would apply; (2) Dynamic Management Areas (DMAs), 

which are areas temporarily defined around confirmed right whale sightings, within which a 

voluntary speed restriction of 10 knots would apply; and (3) monitoring the use of recommended 

shipping routes13. These measures would apply only to non-sovereign vessels 65 feet or more in 

overall length. NOAA Fisheries has assessed speed restrictions and will likely continue, or 

modify these restrictions through additional rule makings (Silber and Bettridge 2012). 

 13 Vessels may operate at a speed greater than 10 knots only if necessary to maintain a safe maneuvering speed in an 

area where conditions severely restrict vessel maneuverability as determined by the pilot or master.
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On June 1, 2009, the International Maritime Organization (IMO) adopted a proposal that would 

limit interactions between whales and transiting vessels of 300 gross tons or more during times 

of high whale abundance. The Great South Channel Area to be Avoided (ATBA), in waters east 

of Massachusetts, is feeding habitat for the North Atlantic right whale and occurs in designated 

critical habitat for that species. The ATBA would be in effect from April 1 through July 31 of 

any year. This measure is anticipated to reduce the likelihood of vessel strikes to whales by 

63 percent. 

Similar protective measures to whales have been implemented by Canada and adopted by the 

IMO. The Bay of Fundy is an important transit route with traffic lanes for about 800 vessels 

passing to and from Canadian and U.S. ports annually, resulting in significant vessel traffic 

across the Canadian Grand Manan Basin Whale Sanctuary. Over two-thirds of the known 

population of North Atlantic right whale is found in the Bay of Fundy area during June through 

November. A change in the mandatory shipping lanes in the Bay of Fundy was proposed and 

adopted by Canada’s Maritime Safety Committee in 2002 (IMO 2002, 2007); this measure was 

designed to relocate vessel traffic using the traffic separation scheme from an area with a high 

density of right whales to an area with a lower density (3.9 miles to the east), thus reducing the 

relative probability of a vessel strike by approximately 62 percent (Vanderlaan et al. 2008). On 

June 1, 2008, Transport Canada adopted the “Roseway Basin ATBA, South of Nova Scotia,” 

originally proposed by the IMO on April 20, 2007 (IMO 2007). The Roseway Basin ATBA 

would have only a seasonally limited effective period of seven months (June through December) 

each year when the largest percentage of the right whales is known to be in the area, and 

consequently when the risk of vessel strikes is greatest. The voluntary implementation by 

mariners of the ATBA is expected to reduce the probability of a lethal vessel-whale encounter by 

at least 82 percent (van der Hoop et al. 2012).

Because LNG vessels associated with the proposed Downeast LNG Project could transit waters 

designated by the IMO and the NOAA Fisheries as natural habitat of the right whale, the LNG 

vessels would follow the IMO regulations to report any sightings of right whales and to 

undertake precautionary measures to avoid any contact with the species. Specifically, LNG 

vessels would remain 500 yards (457 meters) away from North Atlantic right whales and 

100 yards (91 meters) away from all other whales when navigational limits permit. Vessels 

would comply with IMO regulations to avoid the Great South Channel ATBA during April 

through July. The IMO also recommends voluntary compliance with the Roseway Basin ATBA

and the Bay of Fundy traffic separation scheme. As previously described, mandatory speed

restrictions of 10 knots or less are required in SMAs during times when North Atlantic right 

whales are likely to be present, with certain exceptions. Furthermore, LNG vessels could avoid 

the Canadian designated Grand Manan Basin Whale Sanctuary (see Appendix F, figure F-19) if 

right whales are known to be in the area by transiting along the western side of Grand Manan 

Island. Downeast LNG terminal construction and operation crews would also receive 

environmental training that stresses individual responsibility for marine mammal awareness and 

reporting. All on-board crew members would receive training on marine mammal sighting and 

reporting, as required by IMO standards. Additionally, the captains/pilots of LNG vessels 

associated with the proposed Downeast LNG Project would be responsible for monitoring 

communications and for sighting reports of the North Atlantic right whale, including local Notice 

to Mariners, Navigational Telex (NAVTEX) warnings, NOAA Weather Radio, and any other 

means. Following a received whale sighting warning, LNG vessels would comply with required 
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IMO regulations and federal regulations, and all attempts to avoid contact and reduce the risk of 

vessel strikes to whales would be made. In the event that a vessel strike occurs, the appropriate

NOAA Fisheries Regional Stranding Coordinator would be notified and the crew would follow 

the ensuing procedural guidance.

Downeast continues to consult with the FWS, NOAA Fisheries, and other relevant federal and 

state agencies to discuss appropriate mitigation measures and to develop a complete and 

comprehensive Prevention and Mitigation Manual for the construction and operation of the 

project. Downeast has proposed that the following mitigation measures be implemented during 

all stages of the project, maximizing protection of the listed species by either avoiding adverse 

impacts, or minimizing the potential for adverse impacts: 

• Per NOAA Regulation (50 CFR Part 224.103) all vessels are prohibited from 

approaching closer than 500 yards to any right whale. For all other whales, vessels are 

prohibited from approaching closer than 100 yards.

• If not otherwise required by international law, all LNG vessels, or vessels involved with 

the terminal construction, navigating Grand Manan Channel would establish 

communications upon entering the channel, or when crossing a line drawn between 

Cutler, Maine and the southwestern tip of Grand Manan Island (GMI), or approximately 

44.6° north latitude. Vessels departing the Downeast LNG terminal via the Grand Manan 

Channel would establish communications prior to getting underway and maintain 

communications until south of southwestern tip of GMI.

• As an extension of ship strike rules (50 CFR Part 224.105 ) in U.S. waters, all vessels 

over 65 feet (19.8 meters) involved with construction, or future operations of the 

Downeast LNG Terminal would slow to 10 knots upon entering Grand Manan Channel, 

on a line drawn between Cutler, Maine and the southwestern tip of GMI, or 

approximately 44.6° north latitude. Vessels departing the Robbinston terminal via the 

Grand Manan Channel would not exceed 10 knots until south the previously specified 

latitude.

• All vessels over 65 feet (19.8 meters) navigating the Bay of Fundy (BOF) Traffic 

Separation Scheme that are involved with construction, or future operations of the 

Downeast LNG Terminal would slow to 10 knots upon northwesterly course adjustment 

near 44.5° north latitude. Vessels bound for the Robbinston terminal would remain at 

10 knots or slower until their arrival at the terminal, or until control is relinquished to a 

tug. Vessels departing the Robbinston terminal via the BOF Traffic Separation Scheme 

would not exceed 10 knots until after making the southwesterly course adjustment near 

44.5° north latitude.

• The use of “forward-watching” whale spotters that would be ahead of the LNG vessel 

transitway and on the LNG vessel. The spotters would warn of North Atlantic right 

whale presence, especially in Head Harbour, as well as other observed special status 

species. This practice is used for protected species at the EcoElectrica LNG Import 

Terminal in Puerto Rico and has reportedly been very successful. The intent of the 

forward-watching whale spotters is to notify an LNG vessel in advance of the vessel 

entering an area of the presence of a North Atlantic right whale and to defer entry. 
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A similar practice is already in place in the area relative to the pilots and their advance 

ship radio communication. The Downeast plan would implement a dedicated team of 

whale spotters and a vessel that would be resident to the area (e.g., personnel and 

equipment/vessel located in Eastport-Perry and/or Canada). This team could also be used 

in coordination with local whale observation recorders to regularly monitor and record 

whale sightings. The spotter vessel would precede the LNG vessel by approximately one 

mile so as to warn the larger vessel of any whales in their path.

• Development and implementation of a project-wide training and education program, 

wherein all employees of the project and LNG vessel crews are provided detailed 

information regarding the potential presence of special status species and methods and 

procedures to avoid problematic encounters. 

• Providing specialized equipment that would enhance the identification and locating of 

protected species, especially the presence of North Atlantic right whale. Investigations 

are being conducted regarding this type of equipment, which may include instrumentation 

that uses infrared methods for identification. 

• Funding of enhanced visual observation equipment for placement on whale watching tour 

vessels that would promote customer observation of encountered whales from a greater 

distance than might be practiced at present. 

These measures that Downeast would employ to minimize impacts on North Atlantic right 

whales would minimize impacts on all listed cetateans as well as sea turtle and sturgeon species. 

Downeast has committed to continue its consultation with the FWS, NOAA Fisheries, and other 

relevant federal and state agencies to discuss appropriate mitigation measures. Upon completion 

of ESA consultation and federal and state permitting processes, Downeast would incorporate the 

final approved construction and mitigation measures into a comprehensive Prevention and 

Mitigation Manual for use in training of Downeast’s construction and operational personnel, 

which would be filed with FERC.

Acoustic Take and Harassment 

Marine ocean noise has increased in recent years, due in large part to anthropogenic sources such 

as shipping, seismic profiling for oil/gas exploration or seismic/geologic hazard exploration, and 

drilling and pile driving among others. Some of these sounds are loud enough to cause physical 

injury or elicit behavioral changes in the marine organisms that perceive those sounds, 

particularly marine mammals. The MMPA of 1972 prohibits with limited exceptions the take of 

marine mammals in waters or on lands under U.S. jurisdiction. It also regulates the take of 

marine mammals on the high seas by vessels or persons under U.S. jurisdiction. A “take” is 

defined as “harass, hunt, capture, or kill, or attempt to harass, hunt, capture or kill any marine 

mammal. The MMPA defines ‘harassment’ as any act of pursuit, torment, or annoyance that 

either has the potential to injure a marine mammal or marine mammal stock in the wild (Level A 

harassment, generally assumed to occur at 180 dB re 1 μPA for cetaceans and 190 dB re 1 μPA 

for pinnipeds), or has the potential to disturb a marine mammal or marine mammal stock in the 

wild by causing disruption of behavioral patterns, including, but not limited to, migration, 

breathing, nursing, breeding, feeding, or sheltering (Level B harassment, generally assumed to 

occur at 160 dB re 1 μPA for pulsed noise, or 120 dB re 1 μPA for continuous noise).
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Many marine mammals rely on sound for navigation, communication, and detection of prey (by 

echolocation). Thus, the generation of project-related anthropogenic noise may affect a 

mammal’s ability to perform some or all of these important functions. Specifically, noise created 

by LNG vessels in transit may cause temporary changes in marine mammal behavior. The 

cumulative impact of increased vessel traffic resulting from the marine projects in the area is 

discussed in sections 4.11.2 and 4.13 of this EIS. In the presence of vessels, whales may exhibit 

no response; they may exhibit avoidance response; or they may exhibit behaviors that increase 

their susceptibility to collision, such as startle responses, erratic surface movements, reduced 

surface time, fewer blows per surfacing, shorter intervals between successive blows, and 

increased frequency of dives without raised flukes (Whitehead et al. 1990; Cawthorn 1992; 

Gordon et al. 1992). Of the whale species that could occur in the project area, the fin whale is 

known to react strongly to low-frequency vessel sounds that are near the frequency of its own 

vocalizations, between 15 to 100 Hz (EPA 1993). In 1979 to 1980, fin whales were reported to 

actively avoid approaching vessels within this sound range, especially those that approached 

quickly or changed direction or speed abruptly (Edds and Macfarlane 1987; Macfarlane 1981 as 

reported in Richardson et al. 1995). 

Marine mammals have shown a response to constant low-frequency received sounds with 

broadband intensities of more than about 120 dB re 1 μPa (Richardson et al. 1995). However, 

actual thresholds for behavioral responses to sounds in the natural environment depend largely 

on the level of natural ambient noise, with whales apparently capable of distinguishing sounds in 

their optimum frequency range that are 10 to 20 dB re 1 μPa above ambient noise at the same 

frequency (Richardson et al. 1991). 

To estimate the effects of underwater sound propagation produced during construction and 

operation of the proposed project on marine wildlife, Downeast conducted a comprehensive 

underwater acoustic modeling analysis (Gaboury et al. 2007). Results of this study are discussed 

in detail in section 4.11.2. Vessels and tugs used to transit the waterway for LNG marine traffic 

would likely generate sound source levels in the range of 120 to 160 dB re 1 μPA at 1 meter 

proportionate to vessel size, depth of propeller, speed, engine load and revolutions per minute 

with broadband source levels driven primarily by propeller cavitations, hydrodynamic flow over 

the hull and hull appendages, and operation of machinery onboard. Therefore, sounds generated 

by project vessels transiting could potentially elicit a short-term avoidance response by marine 

mammals in the area. While Level A acoustic harassment is possible, marine mammals are 

unlikely to remain close enough to the transiting vessel or associated tugs to be affected in that 

manner; it is widely assumed that most marine mammals would flee the immediate area adjacent 

to a vessel. However, Level B acoustic harassment caused by transiting vessels and tugs is 

expected to affect marine mammals that are present in the waterway for LNG marine traffic. 

Downeast has consulted with the FWS, NOAA Fisheries, and other relevant federal and state 

agencies to discuss appropriate mitigation measures. Appropriate mitigation measures are also 

part of the FWS and NOAA Fisheries review of the BA. Mitigation measures would be 

implemented during all stages of the project, maximizing protection of the listed species by 

either avoiding adverse impacts, or minimizing the potential for adverse impacts. 
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Physical Harassment 

To date, the overall impacts on marine mammals associated with exposure to toxins are not well 

understood; however, accidental spills and releases of oils, lubricants or other pollutants could 

harm those species that come into contact with the released product. For example, 

biomagnifications of environmental toxins (e.g., ingestion of phytoplankton toxins like 

saxitoxin) have been known to pose threats to whales such as humpback and sperm whales. To 

minimize the potential for accidental spills and/or releases, as well as the associated impacts on 

marine mammals, LNG vessels would comply with Coast Guard regulations (33 CFR § 151, 

155, and 157 regarding implementation of MARPOL 73/78) and VGP requirements. Downeast 

would also adopt marine spill prevention and control measures to expedite containment and 

cleanup in the event of a spill at the LNG terminal. As such, marine mammals are not expected 

to be adversely affected by accidental spills. 

Certain types of anthropogenic debris and refuse have also been documented to cause harm to 

marine species, such as plastic bags swallowed by feeding whales, plastic six-pack straps 

wrapped around the necks of waterfowl, etc. To prevent such impacts, Downeast would provide 

guidance to facility personnel regarding the proper disposal requirements for debris and other 

refuse.

Lights on LNG vessels and support vessels would be necessary to ensure safe operation at all 

times, and could attract potential whale prey species to the area. However, lighting is not 

expected to significantly alter the behaviors of marine mammals in the waterway for LNG 

marine traffic.

In summary, the proposed waterway for LNG marine traffic has the potential to affect each 

federally listed whale species, either through physical or acoustic harassment. LNG vessels 

would comply with IMO regulations and the Ship Strike Reduction Rule when in jurisdictional 

waters to reduce the threat of vessel collisions with North Atlantic right whales. Underwater 

noise generated by LNG vessels and support and construction vessels transiting the area would 

result in an overall increased exposure to anthropogenic noise. However, since the project would 

be located in an area with shipping activity, exposure to noise would be consistent with existing 

conditions. Downeast notes that the noise of marine vessels in the transit area is not uncommon; 

motorized vessel traffic and recreational boating have occurred in this area during the last 

100 years. However, the additional LNG vessels and associated escort and security boats would 

be a change to the type and amount of existing ship traffic along the LNG vessel transit route and 

in Mill Cove. Underwater noise produced by vessels that transit the waterway for LNG marine 

traffic is not likely to adversely affect federally listed whales. Noise associated with project 

construction activity and construction vessel transit, particularly when engine thrusters are 

operating and during pile driving operations, may adversely affect whales by eliciting a startle 

response, masking of marine mammal sounds, or result in area avoidance. 

Impacts and mitigations to federally listed whales are also discussed in the BA (see Appendix C).

Leatherback Sea Turtle 

Along the waterway for LNG marine traffic, the greatest potential impacts on leatherback sea 

turtles are vessel strikes and acoustic harassment, followed by pollution. Sea turtles are difficult 

to spot from transiting vessels and are especially prone to propeller strikes. Downeast has 
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indicated that it would provide environmental training to vessel crews to identify threatened and 

endangered species; during inclement weather and periods of low visibility, LNG vessels would 

be required to reduce speed to allow for safe operation of the vessel and crew. In addition, 

mitigation measures that Downeast would implement to protect North Atlantic right whales 

would also be applied to sea turtles. Downeast’s implementation of reduced vessel speed would 

act to reduce both the noise emitted from the vessel as well as the potential for turtle-vessel 

encounters. With these mitigations in place, the waterway for LNG marine traffic is not likely to 

adversely affect leatherback sea turtles. 

State-Listed and Other Special Status Species 

Bald Eagle and Bald Eagle Essential Habitat

Review of Maine GIS habitat maps for the bald eagle indicates eight current or historic nesting 

sites near the waterway for LNG marine traffic (Appendix F, figures F-14 through F-16). During 

normal conditions, passing LNG vessels would not affect nesting bald eagles, bald eagle nesting 

habitat, or potential food sources. 

4.6.2.2 LNG Terminal 

Federally Listed Species 

Leatherback Sea Turtles 

Leatherback sea turtles have the potential to be affected by construction and operation of the 

proposed LNG terminal. As discussed in section 4.6.2.1, measures to avoid impacts on whales 

would also benefit leatherback sea turtles. 

Downeast would employ at least one full-time EI during construction. Downeast has stated that 

this individual would be experienced with offshore and onshore construction and would have 

experience with marine mammal and sea turtle mitigation measures. Prior to commencing 

construction activities, Downeast has stated that the EI would search the work area for the 

presence of sea turtles. If a sea turtle were sighted, work would be delayed until the EI provided 

procedures to the work crew to avoid harassment of the animal. Given the rarity of sea turtle 

sightings within the immediate vicinity of the proposed project, it is unlikely that acoustic 

harassment caused by construction and operation of the LNG terminal (described below) would 

adversely affect leatherback sea turtles. 

Atlantic Salmon

The proposed LNG terminal is located in the vicinity of the migratory corridor for adult salmon 

and juvenile salmon smolts moving to and from the St. Croix River. Within the project region, 

Atlantic salmon use Passamaquoddy Bay, the St. Croix, Dennys, and Pennamaquen rivers as a 

migratory corridor. Within the Dennys River, this species spawns and rears its young. Comment 

letters during the scoping process have expressed concern for migrating smolts in the vicinity of 

the LNG terminal. In a communication to the FERC on November 16, 2006, the FWS and 

NOAA Fisheries indicated that transient Atlantic salmon may occur in the vicinity of the 

proposed LNG terminal. 
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Atlantic Sturgeon

The Atlantic Sturgeon Status Review Team (2007) notes that a small spawning population of 

Atlantic sturgeon may be present in the St. Croix River below the hydroelectric dam; however, it 

also notes that spawning habitats are largely lacking because the salt water wedge intrudes nearly 

to the impassable falls at river mile 9.94. Few spawning adults are anticipated to be present in 

the St. Croix River; however, subadults may use Passamaquoddy Bay in summer months. 

Downeast has consulted with the FWS, NOAA Fisheries, and other relevant federal and state 

agencies to discuss appropriate mitigation measures. Appropriate mitigation measures are also 

part of the FWS and NOAA Fisheries review of the BA. Mitigation measures would be 

implemented during all stages of the project, maximizing protection of the listed species by 

either avoiding adverse impacts, or minimizing the potential for adverse impacts. Downeast has 

proposed that underwater noise levels must be mitigated for to ensure that the extent of the 

150 dB re 1μPa RMS isopleth (i.e., the level of underwater noise believed to cause behavioral 

modification in sturgeon) does not prevent passage of listed Atlantic sturgeon within the affected 

waterbody. While individuals may be displaced from, or avoid, the ensonified area, there must 

always be a zone of passage where noise levels remain below 150 dB re 1μPa RMS.

Shortnose Sturgeon

The shortnose sturgeon is not documented in the St. Croix River system or coastal waters near 

Passamaquoddy Bay. The closest documented population is in the Penobscot River over 100 

miles south of the Project area. However, ongoing studies show that at least some population of 

shortnose sturgeon in Maine undergo coastal migrations between river systems, and one 

individual was detected in 2010 in the Narraguagus River, about 60 miles south of the Project 

area (Zydlewski et al. unpublished). NOAA Fisheries (2012) also suggests that although 

undocumented, the shortnose sturgeon may occur in the same rivers as the Gulf of Maine DPS of

the Atlantic sturgeon. The historic and current status of the St. Croix Atlantic sturgeon 

population is largely unknown, but a small population of large sturgeon may be spawning 

annually below the hydropower dam on the St. Croix River (Atlantic Sturgeon Status Review 

Team 2007, see also discussion of Atlantic sturgeon above).

Marine Mammals

Marine mammals occurring in the vicinity of the proposed LNG terminal may be affected by 

vessel collisions and physical and acoustic harassment during construction and operation of the 

LNG terminal. Dolphins, seals, and porpoises are more likely than whales to be found in the 

area of the LNG terminal. 

Vessel Strikes

During construction of the pier, there would be multiple vessels, tugs, barges, and lay vessels 

present in the Downeast LNG terminal area. These vessels would be required to operate in 

accordance with NOAA Fisheries regulations and requirements as discussed in section 4.6.2.1.

Acoustic Harassment 

Sounds emitted during construction and operation of the LNG terminal would be classified as 

either pulsed or continuous sounds. Continuous sounds include those produced by construction 

vessels, tugs, barges, and lay vessels present in the Downeast LNG terminal area. The barges, 
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which should be the largest vessel used during construction, would not produce engine noise 

because they would be towed by tugs. The tugs themselves would also increase the amount of 

underwater noise when they are towing the barges and positioning anchors. The intensity of 

noise tends to increase as the load that the tug pulls increases (Richardson et al. 1995). The 

marine mammals in the vicinity of the LNG terminal may habituate to low-level (Level B) 

underwater sounds and would accordingly be able to distinguish the sounds they generate for 

communication from those produced by human activities (Richardson et al. 1995). Downeast’s 

adherence to restricted vessel speeds, both within the waterway for LNG marine traffic and in the 

LNG terminal area, would reduce the amount of noise emitted from vessel engines.

Downeast proposes to use drilled, rock socket pile installation that eliminates the need for 

blasting, therefore reducing noise impacts on local fauna. Downeast’s analysis of acoustic 

impacts describes noise that ranges from 120 dB to 170 dB re 1 μPa for this type of continuous 

sound emission. No underwater blasting is expected to be required for installation of the 

terminal pier. Section 4.11.2 of this EIS discusses in greater detail the impacts of noise from 

construction and operation of the Downeast LNG Project. 

NOAA Fisheries has identified measures that would be required to minimize underwater noise 

and ensure listed species under its jurisdiction would not likely be adversely affected by the 

Downeast LNG Project. Downeast has accepted these requirements and proposes to implement 

them, as listed below. 

• Sound generated by impact pile driving in the wet would be mitigated by inserting 

wooden cushioning blocks between the hammer and pile, and by enclosing the pile(s) 

within a confined bubble curtain. Sound generated by vibratory pile driving would be 

mitigated by reducing power settings on the hammer, and by enclosing the pile(s) within 

a confined bubble curtain.

• In a filing with FERC on May 3, 2013, Downeast states that its current design could be 

constructed using only vibratory hammering, such that impact pile driving would not be 

required, and committed to using only vibratory hammering for pile driving.

• Downeast would model mitigated pile driving sound levels throughout the ensonified 

area and provide an updated isopleth map to NOAA Fisheries prior to the issuance of a 

concurrence letter.

• All pile installation, regardless of technique or equipment would conform to existing 

thresholds for Level A (i.e., sound pressure level of 180 dB RMS re: 1μPa) for injury to 

cetaceans, and Level B harassment (160 dB RMS re: 1μPa) for impulse noise and 

continuous sound (120 dB RMS re: 1μPa) as they pertain to listed marine mammals.

• Downeast would record PEAK sound pressure level and calculate Cumulative Sound 

Exposure Level (CSEL) and Root Mean Squared (RMS) from the SPL waveform and 

report results to NOAA Fisheries staff on a daily basis.

• During rock socket drilling and pile driving, Downeast would monitor sound pressure 

level (SPL) with hydrophones and a digital recorder capable of operating at a minimum 

of he hydrophone needs to operate at a minimum 30,000 samples per second for a 

minimum of one second, with an adjustable trigger level, and a range of at least 30 psi. 
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Based on protocol for measuring in-water acoustic fields and natural noise attenuation of 

3-6 dB per doubling of distance, a minimum of three locations would be monitored, 

located approximately 10, 20, and 40 meters from the sound source. 

• An acoustic monitoring plan (e.g., locations, personnel, and equipment) would be 

provided to Max Tritt at NOAA Fisheries at 17 Godfrey Drive, Suite 1, Orono, Maine 

04473 or to max.tritt@noaa.gov at least 30 days prior to implementation.

• If any listed species are encountered in the action area, FERC and NOAA Fisheries 

Maine Field Station would be contacted immediately at (202) 502-6257 and (207) 866-

3756, respectively.

• A post-project report, confirming completion of construction and the successful 

application of all terms and conditions of the permit, would be submitted to NOAA 

Fisheries and FERC within four weeks of project completion.

• Due to the water depth and vessel draft, the use of ship’s bow thrusters would be 

prohibited during low tide when approaching/departing the pier or while docked.

The measures that Downeast would employ would minimize acoustic harassment impacts on all 

listed cetatean and sea turtle species. Downeast has committed to continue its consultation with 

the FWS, NOAA Fisheries, and other relevant federal and state agencies to discuss appropriate 

mitigation measures. Upon completion of ESA consultation and federal and state permitting 

processes, Downeast would incorporate the final approved construction and mitigation measures 

into a comprehensive Prevention and Mitigation Manual for use in training of Downeast’s 

construction and operational personnel, which would be filed with FERC. 

Pollution and Sediment Suspension

Construction debris and human debris could potentially enter the marine environment. 

Downeast would provide environmental training to construction personnel that would give 

guidance on proper disposal requirements for debris and other refuse created during construction. 

Increased sediment suspension and turbidity are expected to temporarily increase during 

construction of the pier. Increased suspended sediments may temporarily inhibit seals from 

foraging in or entering Mill Cove during construction. Marine mammals would experience 

increased turbidity in Passamaquoddy Bay; however, given that whale occurrence in this area is 

low, marine mammals are highly mobile, and that the duration of underwater construction is 

temporary, it is unlikely that marine mammals would be adversely affected by temporary 

increases in turbidity. 

Alteration of Prey Base

Water withdrawals for hydrostatic testing, vessel engine cooling, vessel ballasting, vessel 

hoteling, and fire suppression pump testing would result in the entrainment of phytoplankton and 

zooplankton in the area surrounding the intake pipe or sea chest. Species that feed on 

phytoplankton and zooplankton (e.g., whales) would likely disperse from the area directly 

around the intake in search of food. Considering the minimal effect to phytoplankton and 

zooplankton from entrainment, the loss is expected to have a minimal impact on marine 

mammals as they search for prey in adjacent areas. Screens located on intake pipes and sea chest 
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strainer plates would minimize entrainment of adult fish; however, juveniles may be subject to 

impingement. We believe any resulting loss would be minor and not likely in numbers to affect 

the prey base for marine mammals. 

Accidental Spills and Releases

Impacts and mitigations associated with accidental spills and releases are similar to those 

described in section 4.6.2.1.

State-Listed and Other Special Status Species 

Surveys of the land-based portion of the proposed LNG terminal were conducted by Downeast 

on July 12 to July 15, 2006. The survey focused on identifying particular natural communities 

and ecological conditions in which threatened, endangered, and rare species would likely occur 

and, when possible, to conduct specific field investigations for target species that could be 

observed. Threatened, endangered, and rare species were not identified during these surveys.

Bald Eagle

In a letter dated March 23, 2006, the FWS indicated that the bald eagle could occur within the 

vicinity of the proposed LNG terminal in Mill Cove. Information from Maine DIFW was 

reviewed for locations of historic and currently active eagle nests in the vicinity of the proposed 

LNG terminal. Aerial nest surveys were also conducted to augment the information provided by 

Maine DIFW. Although historic or active bald eagle nests were not observed in the vicinity of 

the proposed LNG terminal, the area associated with the LNG terminal contains habitat that may 

be used by transient individuals for foraging, loafing, and roosting. Downeast has agreed to 

conduct pre-construction clearance surveys for bald eagles. In the event that confirmed nesting 

bald eagles are discovered, Downeast would consult with Maine DIFW to establish a 

comprehensive bald eagle mitigation plan. 

4.6.2.3 Sendout Pipeline 

Federally Listed Species 

Atlantic Salmon

The DPS comprises all naturally reproducing remnant populations of Atlantic salmon from the 

Kennebec River downstream of the former Edwards Dam site located in Augusta north to the 

mouth of the St. Croix River. In August 2006, Downeast LNG assessed fishery habitat using a 

technique recommended by the Maine ASC. At each stream crossing sampled, discrete habitat 

units were delineated on the basis of one or more physical characteristics that separated them 

from adjacent habitat types. Once a habitat unit was defined, appropriate attribute data were 

measured and recorded for the unit. These investigations indicated that for all but the St. Croix 

River and Magurrewock Stream outlet and the Wapsaconhagen Brook, there are no suitable 

spawning habitats for Atlantic salmon in the stream reaches crossed by the proposed sendout 

pipeline. For crossings at the St. Croix River and Magurrewock Stream outlet and the 

Wapsaconhagen Brook, spawning habitat of Atlantic salmon is likely based on the EFH 

description (NEFMC 1998) and the parameters measured in the field survey. Although 

conditions in some streams may be suitable for Atlantic salmon in various life stages, it is also 

important to note that few Atlantic salmon individuals are likely to be present in waters crossed 

by the sendout pipeline at any given time. Fay et al. (2006) notes that the wild St. Croix 
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population of Atlantic salmon is considered extirpated, and that there is little to no natural 

reproduction within the St. Croix main stem and most of its tributaries. Despite stocking efforts,

few returns are documented; and of those returns, many are of hatchery origin (Fay et al. 2006). 

In weir and fishway trap catches of Atlantic salmon in the St. Croix River, abundance has 

steadily declined from 1994 (181 captures) to 2004 (14 captures) (Fay et al. 2006). No mapped 

Atlantic salmon habitat occurs within the corridor of the Downeast pipeline route; however, there 

is undocumented salmon habitat downstream of the proposed crossing of the Wapsaconhagen 

Brook at MP 21.3 (located downstream of the proposed crossing in the Town of Woodland south 

of U.S. Route 1). Salmon presence was documented several years ago at this location, though 

current status is unknown. According to Dubé (pers. comm. 2008), this habitat is located well 

downstream of the proposed sendout pipeline crossing and would be adequately protected by the 

dam-and-pump dry crossing method proposed for this stream (see table 4.5.2.3-1). 

In its February 1, 2008 letter to Downeast, the Maine DMR indicated that migrating Atlantic 

salmon may be present in the St. Croix River and Magurrewock Stream. Although Downeast 

indicated that no instream work would be conducted (see table 4.3.2.2-1), the Maine DMR 

requested additional information about the length of time Downeast expects the HDD of this 

crossing to be complete; information about noise or vibration caused by drilling activities; and 

requested that the HDD be conducted during the months of July and August. Similar concerns 

were raised by the FWS in its letter dated March 14, 2008. Downeast anticipates that the 

crossing would be complete in 75 to 90 days, where work would typically be conducted 24 hours 

per day. Downeast does not anticipate any disruption to surface water flows during this HDD 

and does not anticipate that blasting would be required. The tailings and mud from the drilling 

activity would be pumped into temporary storage tanks and hauled to an approved disposal site. 

Downeast has committed to implementing the FERC’s Plan and Procedures as well as the Maine 

Land and Water Quality Bureau’s Erosion and Sediment Control Best Management Practices to 

protect water quality and wildlife during construction and operation of the sendout pipeline. 

Noise associated with HDD activities of the St. Croix River would be generated at the HDD 

entry point from diesel engines, which have sound mitigation devices installed. Vibration effects 

in the waterbody are expected to be minimal to absent because of the minimum vertical distance 

of 60 feet that would separate the bore shaft from the river bed. Downeast indicated that it 

continues to discuss with Maine DMR about construction schedules to avoid impacts on fisheries 

of interest, including Atlantic salmon. Downeast believes that a construction window of June 

through August would best avoid potential impacts on a suite of species, including Atlantic 

salmon, alewife, American shad, American eel, rainbow smelt, and blueback herring; however, it 

will continue to consult with Maine DMR about timing. Because the HDD would be timed to 

avoid critical life stage periods for Atlantic salmon present in the St. Croix River, direct impacts 

on this species caused by HDD are unlikely. 

State-Listed and Other Special Status Species 

Bald Eagle 

Downeast reviewed information from 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). Using this information as reference, aerial surveys 

were conducted on June 12, 2006 and again on May 5, 2008, in cooperation with Maine DIFW, 
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to identify new and historic bald eagle nest sites. During the aerial surveys, no new eagle nests 

were observed within the study corridor or within the 0.25-mile zone on either side. Eagles were 

observed during the 2008 overflight but did not appear to be associated with nest sites within 

0.25 mile of the sendout pipeline. Based on these surveys, active bald eagle nest sites would not 

be affected by construction of the sendout pipeline. A single historic nest was identified near 

MP 9.5; in this location, 1.7 acres of inactive nesting habitat would be affected during 

construction of the sendout pipeline. In addition, construction would affect eagle foraging and 

roosting/loafing habitats. 

Construction activities that have the potential to disturb foraging bald eagles or known roosts are 

expected to be minimal, localized, and temporary. Prior to construction, locations of historic and 

active bald eagle nesting sites and buffer zones within the workspace would be surveyed and 

identified with signage as environmentally sensitive resources. To avoid and minimize adverse 

impacts on nesting bald eagles, Downeast has stated that construction activities would not occur 

within 0.25 mile of all identified bald eagle buffer areas between March 1 and August 31. To 

avoid disturbance to existing nests and the allocated 0.25-mile buffer, each portion of the 

proposed sendout pipeline that is near an active eagle nest would be reviewed for (a) minor 

rerouting; and/or (b) mitigation measures including seasonal prohibitions on construction. 

Downeast indicated it may also modify the timing of periodic inspections and/or repair of the 

sendout pipeline to ensure avoidance and minimization of disturbance during sensitive periods if 

a pipeline section occurs within the protected buffer of any active bald eagle nesting/breeding 

site. 

In its March 14, 2008 letter, the FWS expressed concern about potential effects of noise and 

materials storage associated with the HDD operations proposed in the vicinity of the bald eagle 

nest located in the Moosehorn NWR at Magurrewock Marsh. Downeast indicated that the HDD 

site is located more than 0.5 mile away from the location of the bald eagle nest in question. 

While the drilling activity would produce noise, the drilling activities would be outside of the 

buffer area that the FWS suggests be implemented. Equipment and materials storage associated 

with the project would be located outside of the 0.25-mile buffer around the eagle nest site. 

Construction and operation of the proposed Downeast LNG Project is not anticipated to cause 

adverse impacts on bald eagle prey species (e.g., sculpin, eel, common eider). A significant 

reduction in anticipated affected habitat of the bald eagle was made by modifying the sendout 

pipeline route. Downeast continues to coordinate with the FWS and Maine DIFW regarding 

preferred avoidance and minimization for this species.

Downeast has stated that the sendout pipeline corridor would be resurveyed prior to the 

commencement of construction activities to detect the presence of federal- or state-listed species. 

Downeast would coordinate any necessary mitigation with FWS, Maine NAP, and Maine DIFW.
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4.6.3 Conclusions and Recommendations for Threatened, Endangered, and Other 

Special Status Species 

Effects on Whales and Sea Turtles

The proposed Downeast LNG Project has the potential to adversely affect the leatherback sea 

turtle and each of the six whale species identified within the project area, either by acoustic take 

or whale-vessel (or turtle-vessel) strikes. Federally designated critical habitat does not occur 

within the proposed project area, and thus would not be affected by the proposed action. The full 

extent to which long-term low-level anthropogenic sound impacts marine mammals and sea 

turtles is not well understood. However, adverse acoustic impacts during pile driving would be 

mitigated through Downeast’s use of a vibratory hammer and engagement of a NOAA Fisheries 

approved mammal and marine spotter to ensure no listed species are within the designated 

NOAA Fisheries Acoustic Safety Zone during this activity. The density of whales and 

leatherback sea turtles in the proposed transit route, combined with the proposed increase in 

vessel traffic resulting from delivery of LNG to Robbinston, Maine, increases the potential for 

vessel-whale encounters to occur. Any injury or fatality that results from a whale-vessel (or 

turtle-vessel) encounter would be an adverse effect. To mitigate for this adverse effect, LNG 

vessels would adhere to NOAA Fisheries regulations to reduce the threat of vessel strikes. 

Based on the mitigative measures that Downeast has proposed for the North Atlantic right whale, 

which would also act to mitigate impacts on other cetaceans and the leatherback sea turtle, we 

believe that construction and operation of the proposed Downeast LNG Project is not likely to 

adversely affect, leatherback sea turtles, blue, fin, humpback, North Atlantic, sei, or sperm 

whales. More specific information about impacts and mitigations are discussed in the BA (see 

Appendix C). 

Effects on Atlantic Salmon

The proposed project has the potential to adversely affect Atlantic salmon; however, Downeast 

has agreed to implement a variety of mitigation measures that would minimize or avoid impacts 

on this species. These mitigative measures include timing construction to avoid times of year 

when migrating salmon smolts or adult salmon are likely to be present; employing construction 

methods in stream crossings that are least damaging to the aquatic habitat; and preserving and 

restoring riparian buffers. Implementation of these measures would be sufficient to prevent 

adverse impacts on Atlantic salmon. Construction and operation of the proposed project is not 

likely to adversely affect Atlantic salmon.

Effects on Atlantic and Shortnose Sturgeon

The proposed project has the potential to adversely affect Atlantic sturgeon and shortnose 

sturgeon; however, Downeast has agreed to implement a variety of mitigation measures that 

would avoid or minimize impacts on these species. These mitigation measures include timing 

construction to avoid times of year when migrating sturgeon are likely to be present and 

implementing construction methods that preserve habitat (e.g., use of HDD). Construction and 

operation of the proposed project is not likely to adversely affect Atlantic sturgeon and shortnose 

sturgeon.
4.7 – Land Use, Recreation, and Visual Resources 4-170

4.7 LAND USE, RECREATION, AND VISUAL RESOURCES

The Downeast LNG Project would be located in Washington County, Maine. The proposed 

LNG terminal would be located on 80 acres of privately owned land located between 

U.S. Route 1 and Passamaquoddy Bay in Robbinston, Maine. Downeast holds an option to 

purchase the entire land parcel. The site would be located on the south side of Mill Cove, south 

of the confluence of the Passamaquoddy Bay and St. Croix River between the larger towns of 

Eastport, Perry, and Calais, Maine. The proposed pier would extend 3,862 feet northeast from 

the terminal site and would be located on Maine public submerged lands.

Downeast proposes to construct and operate a 29.8-mile-long, 30-inch-diameter natural gas 

sendout pipeline, which would extend from the LNG terminal to the existing M&NE pipeline 

system at the Baileyville Compressor Station in Baileyville, Maine. About 12 miles (40 percent 

total) of the sendout pipeline from MP 17.7 to MP 27.2 and MP 27.3 to MP 29.8 would be 

immediately adjacent to the existing EMEC electric transmission line right-of-way (32 percent) 

and the existing M&NE pipeline right-of-way (8 percent). ATV trails would parallel the sendout 

pipeline from MP 0.7 to MP 3.7 and MP 21.6 to MP 28.3. Additionally, it is anticipated that the 

nonjurisdictional EMEC transmission line right-of-way would be collocated with approximately 

11.4 miles (38 percent) of the sendout pipeline between MP 0.2 and MP 11.6. See section 2.9 of 

this EIS for further information on nonjurisdictional facilities.

4.7.1 Land Use

Most of the land affected by construction and operation of the Downeast LNG Project would be 

forest land at the LNG terminal and along the sendout pipeline. Other land uses affected by the 

project would be submerged lands, developed land, agricultural land and grassland. 

Construction would affect a total of 313.2 acres of land, 55 acres for the LNG terminal and 

laydown areas, 3.6 acres for the pier, 201.3 acres for the pipeline, 0.8 acre for the valve station 

and pigging and metering facilities, 10.1 acres for access roads, 23.7 acres for off-site pipe 

laydown and storage areas, and 18.7 acres for ATWS, including HDD ATWS. Operation of the 

project would affect 188.8 acres of land, of which 50.6 acres would be permanently converted 

for operation of the terminal facilities, and the remaining 138.2 acres would be maintained as 

permanent right-of-way for the sendout pipeline, valve station, pig receiving facility, and access 

roads. Table 4.7.1-1 summarizes the acres of each land use category that would be affected by 

construction and operation of the proposed project. 

4.7.1.1 Waterway for LNG Marine Traffic

The marine traffic route would consist of passage through the Bay of Fundy to Head Harbour 

Passage, to Western Passage, to Passamaquoddy Bay to the LNG terminal. The LNG vessels 

would enter the Head Harbour Passage approximately 1.5 miles from Quoddy Head at the 

northern end of Campobello Island. From the entry point, the LNG vessels would travel 

16.6 nautical miles along 13 different legs to the LNG terminal. The longest leg of the passage is 

in Passamaquoddy Bay, which follows the United States and Canadian border. Additional 

details on the marine traffic route are included in sections 2.1.1 and 4.12 of this EIS. 
4-171

4.7 – Land Use, Recreation, and Visual Resources

TABLE 4.7.1-1

Acres of Land Affected by Construction and Operation of the Proposed Downeast LNG Project

Facility

Forest

Land

Developed 

Land

Agricultural

Land Grassland

Submerged

Land Total

Con. Op. Con. Op. Con. Op. Con. Op. Con. Op. Con. Op.

LNG Terminal a/ 47.0 47.0 0 0 0 0 0 0 0 0 47.0 47.0

Off-site laydown areas 0 0 3.0 0 0 0 5.0 0 0 0 8.0 0

Pier 0 0 0 0 0 0 0 0 3.6 3.6 3.6 3.6

Subtotal LNG Terminal 47 47 3.0 0 0 0 5.0 0 3.6 3.6 58.6 50.6

30-inch-diameter Sendout Pipeline b/, c/ 173.0 110.5 14.2 8.4 1.8 1.1 12.3 7.6 0 0 201.3 127.6

Off-site pipe laydown and storage areas 22.1 0 0.9 0 0.7 0 0 0 0 0 23.7 0

Valve Station (MP 17.17) 0.3 0.3 0 0 0 0 0 0 0 0 0.3 0.3

Pig Receiving and Gas Metering Facility at 

Baileyville Terminus (MP 29.8) d/ 0 0 0.5 0.3 0 0 0 0 0 0 0.5 0.3

Additional Temporary Workspace and HDD 

Additional Temporary Workspace 13.7 0 2.4 0 1.6 0 1.0 0 0 0 18.7 0

Access Roads e/ 0.6 0.5 9.5 9.5 0 0 0 0 0 0 10.1 10.0

Subtotal Sendout Pipeline 209.7 111.3 27.5 18.2 4.1 1.1 13.3 7.6 0.0 0.0 254.6 138.2

Project Total 256.7 158.3 30.5 18.2 4.1 1.1 18.3 7.6 3.6 3.6 313.2 188.8

a/ Includes the pig launching facility inside the terminal property.

b/ Includes nominal 75-foot-wide construction right-of-way and a 50-foot-wide operation right-of-way.

c/ This table only shows the land that actually would be physically disturbed by the terminal and pipeline construction and operation. Areas where HDD is being proposed, including 

under the St. Croix River, are excluded because these areas would not be disturbed by construction or operation of the pipeline facilities.

d/ Pigging facilities at the Baileyville Compressor Station would be constructed in previously disturbed areas within the station property.

e/ Only the access road at MP 15.4 would require clearing for a new road base. The other three temporary access roads have existing road bases; however, they would need to be 

upgraded prior to construction of the sendout pipeline and would not be restored to pre-existing conditions.
4.7 – Land Use, Recreation, and Visual Resources 4-172

4.7.1.2 LNG Terminal 

The LNG terminal would consist of an onshore LNG terminal and an offshore pier. The 

northern portion of the site once contained a homestead and farmland up until the 1960s. 

Currently, there are no residences located on the parcel. Some of the former agricultural fields 

remain relatively open, although they are reverting to wooded uplands and forested/scrub-shrub 

wetlands. Scattered household wastes, remnant fencing, and apple trees are the only remaining 

evidence of the former homestead. The remainder of the site consists of wooded uplands and 

two wetlands. Of the 80 acres, 68 acres are classified as forest land and 12 acres are classified as 

wetlands (FWS 1998; Maine Office of GIS 2006b; Woodlot 2005). Both the uplands and 

wetlands have been historically harvested, with the most recent harvesting occurring in the mid 

1990’s (Krug 2005). Harvesting over much of the site was intensive and numerous remnant 

skidder trails are evident. There are also several large slash piles, particularly on the southern 

side of the site associated with a former log landing (Woodlot 2005).

Land use impacts associated with the LNG terminal would include temporary disturbance of 

58.6 acres of existing land uses during construction of new permanent facilities and pier. About 

50.6 acres of the terminal site would be affected by operation of the LNG terminal (47.0 acres of 

forest land, and 3.6 acres of submerged land for the pier). The remaining portion of the 80-acre 

parcel would be left undeveloped. Three off-site areas would be used for terminal equipment 

and pipeline laydown, temporarily disturbing 8.0 acres of developed land and grassland during 

construction.

The 3,862-foot-long pier would be constructed over the Passamaquoddy Bay submerged lands. 

The pier would have a surface area of 3.6 acres, mostly over open water. Only 0.1 acre of the 

submerged land would be directly affected by the footing of the pilings. Construction of the pier 

abutment would necessitate the removal of rock ledge within the regulated coastal zone. Pier 

construction would require a lease or easement from the State of Maine for activities conducted 

on submerged land. Maine defines submerged lands as all coastal land (including islands) from 

the mean low-water mark out to the 3-mile territorial limit. Where intertidal flats are extensive, 

the shoreward boundary begins 1,650 feet seaward from the mean high-water mark. Structures 

located on submerged land require a lease or easement when the existing use is being changed or 

the size of an existing structure is being changed. Leases or easements are also required for 

pipelines, utility cables, outfall/intake pipes, and dredging. Downeast will submit its Submerged 

Lands Lease application to the Maine Department of Conservation, Bureau of Parks and Land, in 

conjunction with its Maine DEP permit, after issuance of the final EIS. In its comments on the 

draft EIS, the Bureau of Parks and Land stated that impacts of the security zone around the 

facility as well as the moving security zone for LNG vessels will be a primary concern raised by 

recreational boaters, other waterway users, and those promoting public access and eco-tourism 

during its review of the submerged lands lease application. The Bureau of Parks and Land also 

recommended that Downeast explore options for allowing small watercraft to transit under the 

pier in order to maintain near-shore navigation options. It would be up to the Coast Guard

COTP, under the authority of the Ports and Waterways Safety Act, to determine whether to allow 

small watercraft into the 500-yard, fixed safety/security zone around the moored LNG vessel, 

which would include a portion of the pier.

The COE, New England District, has published guidelines for the placement of fixed and 

floating structures in navigable waters of the United States that are regulated by the New 
4-173 4.7 – Land Use, Recreation, and Visual Resources

England District (COE 1996). The guidelines were developed to provide common sense 

guidance for structures in navigable waters. The guidelines suggest that no structures built on a 

linear waterway should extend more than 25 percent of the waterway width at mean low water. 

The 3,862-foot pier design as proposed by Downeast appears to extend just over 25 percent of 

the width of the St. Croix River/Passamaquoddy Bay at the project location. However, it is 

difficult to assign an exact percentage because of the irregular shoreline on both the United 

States and Canadian sides of the waterway near the project location. The guidelines do not 

constitute policy or regulation, and in themselves are not enforceable. However, as suggested by 

the COE, they provide guidance for project design that typically would not generate adverse 

public comment or result in permit denial. In its review of the Section 10 permit for the project, 

the COE will take into consideration how much of the linear waterway would remain open, in 

addition to obtaining feedback from the Coast Guard, pilots, and harbormasters, and would 

determine if the proposed pier is acceptable for the site-specific conditions. In addition, we have 

evaluated alternative pier designs in section 3.5 of this EIS, two of which would include a shorter 

pier that would meet this guideline.

4.7.1.3 Sendout Pipeline

The valve station would be located at MP 17.17 in Baring and would affect 0.3 acre of forest 

land outside the pipeline construction right-of-way during construction. Of this area, 0.3 acre 

would be maintained for operation of the valve station. The pig launching facility would be 

located on the LNG terminal property. Land use impacts from the construction and operation of 

this facility are included in table 4.7.1-1. The pig receiving and gas metering facility would be 

located at MP 29.8 in Baileyville and would affect 0.5 acre of developed land during 

construction and 0.3 acre of developed land during operation.

Most of the land affected by the construction and operation of the sendout pipeline would be 

forest land (20.7 miles or 69.6 percent). Other land uses affected along the sendout pipeline 

would include open water (e.g., St. Croix River) (0.3 mile or 1.1 percent), developed land 

(2.0 miles or 6.6 percent), agricultural land (0.9 mile or 2.9 percent), wetlands (forested, 

herbaceous, and scrub-shrub) (5.7 miles or 19.1 percent), and grassland (0.2 mile or 0.7 percent). 

Construction of the sendout pipeline would affect a total of 254.6 acres of land, 201.3 acres for 

the pipeline construction right-of-way, 0.3 acre for the valve station, 0.5 acre for the pig 

receiving facility, 10.1 acres for access roads, 23.7 acres for off-site pipe laydown and storage 

areas, and 18.7 acres for temporary workspace areas and staging areas. Operation of the sendout 

pipeline would affect a total of 138.2 acres of land, of which 127.6 acres would be permanently 

converted to maintain the sendout pipeline, 0.3 acre for operation of the valve station, 0.3 acre 

for the pig receiving facility, and 10 acres for access roads.

We received a comment from the Maine Bureau of Parks and Lands, Submerged Lands Program, 

advising that a Submerged Lands Lease would be required for the portion of sendout pipeline to 

be drilled under the St. Croix River. This lease has been added to table 1.3-1, Major Permits, 

Approvals, and Consultations for the Downeast LNG Project. 

It is anticipated that the new nonjurisdictional EMEC electric transmission line would parallel 

approximately 11.4 miles (38 percent) of the sendout pipeline from MP 0.2 to MP 11.6. 

Additionally, ATV trails would parallel the sendout pipeline from MP 0.7 to MP 3.7 and MP 

21.6 to MP 28.3 for a total of about 9.55 miles. Approximately 12.0 miles (40 percent) of the 

pipeline would be installed in or adjacent to other existing utility or road rights-of-way between 
4.7 – Land Use, Recreation, and Visual Resources 4-174

MP 17.7 and MP 27.2 and MP 27.3 and MP 29.8. Downeast is currently coordinating with 

EMEC on the use of their existing transmission line right-of-way for a portion of the pipeline 

right-of-way. If feasible, where the pipeline would be directly adjacent to EMEC’s existing 

right-of-way, the new pipeline would be offset about 5 to 10 feet from the outside edge of the 

existing right-of-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-of-way. If this is agreed upon, approximately 15.7 acres of the sendout pipeline 

construction right-of-way and 2.2 acres of the permanent right-of-way would overlap the EMEC 

transmission line right-of-way. See sections 2.2.2.1 and 2.9 for further discussion of the existing 

transmission line and proposed nonjurisdictional facility.

The sendout pipeline centerline would be offset from the M&NE pipeline right-of-way by 

approximately 50 feet between MP 27.35 and MP 29.8. Approximately 5.9 acres of the M&NE 

right-of-way would be utilized for the sendout pipeline construction right-of-way and pipeline 

laydown areas and ATWS. None of the sendout pipeline permanent right-of-way would overlap 

the M&NE pipeline right-of-way.

Land use impacts associated with the sendout pipeline would include temporary disturbance of 

existing land uses within construction work areas along the right-of-way during construction and 

creation of new permanent right-of-way for operation and maintenance of the pipeline. 

Downeast generally would use a 75-foot-wide construction right-of-way to fabricate and install 

the 30-inch-diameter pipeline. Following construction, a 50-foot-wide permanent right-of-way 

would be maintained in an herbaceous/shrub state during operation of the sendout pipeline. 

A 55-foot-wide construction right-of-way would be used where the proposed route crosses 

residential areas and in several wetlands. Following construction in these areas, a 30-foot-wide 

permanent right-of-way would be maintained in an herbaceous/shrub state during operation of 

the sendout pipeline.

Construction of the sendout pipeline, valve station, and pig receiving facility would affect a total 

of 254.6 acres, of which 138.2 acres would be maintained as permanent right-of-way following 

construction. About 111 acres of forest land, including forested wetlands, would be permanently 

converted to industrial use for operation of the sendout pipeline and valve station. Disturbance 

to forest land would be minimized by locating the majority of the sendout pipeline right-of-way 

adjacent to existing maintained utility rights-of-way and ATV trails. Other land uses affected 

permanently along the sendout pipeline right-of-way would include developed land (18.2 acres), 

agricultural land (1.1 acres), and grassland (7.6 acres). Land that would be retained as 

permanent right-of-way for the sendout pipeline would be allowed to revert to former use with 

certain restrictions. Following construction, the temporary right-of-way and additional work 

areas would be reverted to their previous land use.

Pipeline construction would require the use of extra workspace areas and staging areas, which 

would be short-term and temporary. There are 146 potential staging areas that have been 

identified along the proposed sendout pipeline route. Table 2.2.2.1-1 lists the location and land 

use for each additional temporary workspace. The combined total approximate acreage of the 

staging areas is 50.2 acres. These staging areas would be restored to their pre-construction 

conditions upon completion of construction. 
4-175 4.7 – Land Use, Recreation, and Visual Resources

4.7.2 Existing and Planned Residences and Structures 

4.7.2.1 Waterway for LNG Marine Traffic

There are concentrated developments in a few locations along the marine traffic route such as 

Eastport, Maine and St. Andrews, New Brunswick. Eastport is located southeast of the LNG 

terminal, and along Friar Roads where the LNG vessels would turn northwest between Eastport, 

Maine and Indian Island, New Brunswick. St. Andrews is a Canadian resort town located 

opposite the LNG terminal. A more detailed discussion of populated areas and population 

density along the waterway for LNG marine traffic route is discussed in section 4.8.1.

The waterway for LNG marine traffic would pass by developed areas in Eastport, Maine and 

St. Andrews, New Brunswick, and scattered seasonal and permanent residences along the route. 

The impact on these areas during normal operation is primarily a visual impact, which is 

discussed in section 4.7.4. 

4.7.2.2 LNG Terminal

No existing or planned residences or structures are within 50 feet of the proposed LNG terminal. 

Several residential properties are located to the south and west of the site generally along 

U.S. Route 1. The nearest residences to the proposed LNG terminal are located along 

U.S. Route 1 across from the LNG terminal site. The closest residence is located approximately 

125 feet from the LNG terminal site entrance. To the south, there are a few residences located 

1,500 feet or more from U.S. Route 1 moving toward the shoreline. These residences are located 

over 2,000 feet from the project site. To the northwest, there is a cluster of residential properties 

along Ridge Road near the intersection of U.S. Route 1. There is also a local utility station and 

small retail store in this area. North of the site, several residential properties are located along 

U.S. Route 1, along with other properties including a church (approximately 0.6 mile from the 

LNG terminal site entrance), elementary school (approximately 0.8 mile from the LNG terminal 

site entrance), and fire station (approximately 0.8 mile from the LNG terminal site entrance). 

There are also several waterfront homes located on Passamaquoddy Bay northeast of the site.

Residents in proximity to the LNG terminal site may experience temporary effects associated 

with construction and permanent effects associated with operation of the LNG terminal. 

Temporary impacts due to construction include noise and dust from construction equipment, 

particularly pile-driving equipment. Because of the temporary nature of noise from vibratory 

and impact pile driving, no adverse or long-term effects are anticipated. Noise from other 

construction activity may be noticeable at nearby residences, especially during periods of 

extensive earthwork using heavy equipment. Local traffic during the construction phase is also 

expected to increase, along with associated vehicle noise. Potential adverse effects associated 

with construction and operational noise are discussed further in section 4.11.2 of this EIS.

Given the distance between proposed construction activity and the nearest residences noted 

above and the proposed dust control measures, impact on residences from dust generated during 

construction would not be significant.

During operation of the proposed LNG terminal, the primary impact on those residences 

discussed above would be visual. The LNG storage tanks would be about 160 feet tall and the 

pier would be 3,862 feet long; both would be visible from the Mill Cove area. See section 4.7.4 

for further information on visual resources.
4.7 – Land Use, Recreation, and Visual Resources 4-176

4.7.2.3 Sendout Pipeline

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 two residences located 

approximately 50 feet from the construction right-of-way. Table 4.7.2.3-1 shows the locations of 

these residences and distance from the construction right-of-way and the pipeline centerline. 

Appendix P includes the revised site-specific residential construction plans for all 19 residences.

TABLE 4.7.2.3-1

Residences within 50 Feet of the Construction Right-of-way for the Proposed

Downeast Sendout Pipeline

Milepost Number of 

Residences

Distance from

Construction ROW (feet)

Distance from

Pipeline Centerline (feet)

0.63 1 54 74

0.91 1 >50 31

Based on Downeast’s communications with town managers and real estate professionals, neither 

Robbinston nor the surrounding communities are planning to construct or have been notified of 

planned residential or commercial/business developments or subdivisions that would be crossed 

or within 0.25 mile of the sendout pipeline (Howard 2006a; Porter 2006; Moholland 2006).

In a letter filed March 17, 2008, Ms. King expressed concerns with the proposed pipeline route 

that would pass through the community of Baring Plantation and near her residence. The King 

residence is located at approximately MP 16.9. The nearest proposed workspace is more than 95 

feet from the residence. Downeast has not prepared a site-specific plan for this residence

because it is more than 50 feet from the construction workspace. Ms. King disputed that location 

in a subsequent letter dated May 19, 2008, and we have determined that the house is located 

more precisely between MP 16.9 and MP 17.0; this does not alter the distance between the 

workspace and the residence. Ms. King also identified a potential route variation in this area 

which is discussed in section 3.8.2.1 of this EIS.

Between MP 16.2 and MP 16.4, there is a residential townhouse complex that has been 

developed and may be expanded. At its closest point, the townhouse complex is 80 feet from the 

pipeline right-of-way. There are no ATWS areas within 50 feet of this complex. According to 

Downeast, the routing of the pipeline has been coordinated with the landowner to avoid future 

development plans.

In residential areas, the two most significant impacts associated with construction and operation 

of natural gas pipelines are disturbance during construction and encumbrance of property for 

future uses (e.g., the limitation on future permanent structures within the permanent pipeline 

right-of-way). Residences within 50 feet of construction work areas are considered to be the 

most likely to experience the effects of pipeline construction. Temporary construction impacts 

on residential areas could include inconvenience caused by noise and dust generated by 

construction equipment; trenching through roads or driveways; ground disturbance of lawns; 

removal of landscaping or natural vegetative screening; potential damage to existing septic 

systems or wells; and removal of aboveground structures, such as sheds or trailers, from within 

the right-of-way.
4-177 4.7 – Land Use, Recreation, and Visual Resources

Downeast filed site-specific plans for residences within 50 feet of the permanent right-of-way 

(see Appendix P). In October 2009, Downeast filed modified site-specific plans, and 

subsequently revised those plans in January 2010. The January 2010 plans are included in 

Appendix P in this EIS. We have not received any landowner comments about these plans. 

These site-specific plans include a number of standard construction practices such as the 

installation of a safety fence 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 BMPs; immediate restoration of driveway, lawn areas, and 

landscaping within construction work areas, except where required for continued construction 

access; and immediate restoration of all remaining areas following final restoration. In addition, 

Downeast previously stated that it would provide site-specific plans for residences within 50 feet

of construction work areas and that the plans would include such safety measures as the 

installation of a safety fence along the construction right-of-way boundary to restrict public 

access in the work area; preserving mature trees and landscaping where possible while 

maintaining construction safety; welding, inspecting, and installing pipe as rapidly as possible to 

minimize construction time in residential areas; limiting active work hours; and backfilling the 

trench as soon as the pipe is laid or placing steel plates and/or mats in areas where the trench 

must remain open overnight. Section 3.8.2 of this EIS describes pipeline route variations 

Downeast incorporated into its proposed route to minimize impacts on the residences within 

50 feet of the permanent right-of-way. Section 3.8.2 includes a table comparing the impacts of 

the proposed route (without the route variations) and the proposed route with the route 

variations. We believe these route variations would minimize impacts on these residences.

Downeast would obtain an easement from the landowner in order to construct the sendout 

pipeline. An easement would be used to convey both temporary (for construction) and 

permanent (for operation and maintenance) rights-of-way to Downeast. The easement would 

give Downeast the right to construct, operate, and maintain the sendout pipeline, and establish a 

permanent right-of-way. In return, Downeast would compensate the landowner for use of the 

land. The easement agreement between the company and the landowner typically specifies 

compensation for the loss of use during construction, loss of nonrenewable or other resources, 

and allowable uses and restrictions on the permanent right-of-way after construction. These 

restrictions can include prohibition of construction of aboveground structures, including house 

additions, garages, patios, pools, or any other object not easily removable; roads or driveways 

over the sendout pipeline; or the planting and cultivating of trees or orchards within the 

permanent easement. The areas used as temporary construction right-of-way and temporary 

extra workspace would be allowed to revert to pre-construction uses with no restrictions.

The acquisition of an easement is a negotiable process that would be carried out between 

Downeast and individual landowners. If the necessary land cannot be obtained through good 

faith negotiations with property owners and the project has been certificated by the Commission, 

Downeast may use the right of eminent domain granted under Section 7(h) of the NGA and the 

Federal Rules of Civil Procedure (Rule 71A) to obtain easements. Downeast would still be 

required to compensate the landowner for the right-of-way and damages incurred during 

construction; however, according to state or federal law, a court would determine the level of 

compensation. 
4.7 – Land Use, Recreation, and Visual Resources 4-178

4.7.3 Existing Public, Recreation, and Special Land Uses 

4.7.3.1 Waterway for LNG Marine Traffic

The waterway for LNG marine traffic follows two different routes from entering the Bay of 

Fundy to Quoddy Head. The route chosen by the LNG vessel captain would be determined in 

consultation with pilots, Transport Canada, and COTP and would depend on visibility, wind, tide 

cycle, and other such constraints. The eastern route follows an established navigational route 

that was modified in 2003 to reduce the likelihood of vessel strikes of whales. However, this 

route most likely would be used when the chance of encountering whales is low (see 

Appendix F, figure F-1). Lobster fishing is seasonal on this route (from the second Tuesday in 

November to January 15 and April 15 to June 30). There is no fishing from June 30 through 

November. Commercial shipping traffic occurs on this route, and according to Downeast, there 

is very little recreational traffic on this route from June through September. There are 

approximately 60 passenger ships and approximately three right whale tour boats along the 

eastern route. However, the whale boat tours generally do not operate in the designated shipping 

channel east of Grand Manan Island.

Year round and seasonal ferry passenger ships and small car ferries transit this area. The 

Princess of Acadia ferry travels between St. John, New Brunswick and Digby, Nova Scotia on a 

year round schedule, with more frequent trips between May and October. A conventional ferry 

and a high-speed ferry travel between Bar Harbor and Portland, Maine and Yarmouth, Nova 

Scotia from May to October. There is a daily ferry departing from Blacks Harbour, New 

Brunswick, to North Head, Grand Manan, with a connecting ferry to White Head Island. The 

Deer Island Princess and the John E. Rigby ferries travel year round in Passamaquoddy Bay. 

The waterway is a known navigation route and should have minimal impact on recreational and 

commercial users.

While no mandatory deep draft vessel routing is currently prescribed, during other times of the 

year, the LNG vessels most likely would use the route to the west of Grand Manan (see 

Appendix F, figure F-1), which does not have a designated shipping lane. Although there is less 

of a chance of encountering whales using the western route, the vessel would encounter more 

commercial fishing and possibly recreational activities along this route. Downeast consulted 

with local fishermen and found that, generally, the fishermen try to avoid placing their gear in 

designated shipping lanes in order to prevent loss of their equipment. Because there is no 

designated shipping lane along the western route, it is likely that more fishing gear may be 

encountered. Downeast stated that in hearings conducted by the Maine BEP, fishermen stated 

that they do not have a problem with LNG vessels being able to transit the area to the LNG 

terminal. However, they did indicate that a specific transit routing on the western route, for both 

existing traffic and LNG vessels, would assist fishermen in avoiding the placement of traps in the 

way of commercial vessels. On this route, lobster fishing takes place from June 1 to 

November 30. Additionally, Downeast consulted with Fundy Traffic and found that most 

passenger ships and whale boat tours do not transit this route; however, seasonal ferries do use 

this route. 

From Quoddy Head, the route would traverse Head Harbour, Western Passage, and 

Passamaquoddy Bay to Mill Cove. Recreational boating occurs in the Western Passage and 

Passamaquoddy Bay and includes whale-watching tours in Passamaquoddy Bay, which typically 
4-179 4.7 – Land Use, Recreation, and Visual Resources

occur between May and October. Downeast contacted the Quoddy Pilots Association, which 

stated that recreational boating activity is light in the Western Passage (Peacock 2006).

Recreational fishing is light in Passamaquoddy Bay, and activities include lobstering, scalloping, 

and fin fishing. Shellfishing is considered an important recreational resource in Passamaquoddy 

Bay. Observations taken by Downeast from 2004 through 2006 indicate that recreational activity 

is extremely limited, most likely because of the large extent of the intertidal area exposed at lowwater and the strong tidal currents. According to Downeast, local harbor pilots (Peacock 2006) 

confirmed the limited use of the area, as well as several field surveys taken during trips with the 

Quoddy Pilots Association during the summers of 2005 and 2006. However, during the tourist 

season (late spring, summer, and early fall), recreational boating and fishing could see an 

increase. The City of Eastport, St. Andrews, New Brunswick, and other municipalities along the 

shoreline are exploring eco-tourism as a source of income and employment. Eco-tourism 

activities could include kayaking, recreational fishing, canoeing, sightseeing, and whale 

watching.

Eight state-owned parcels would be along the waterway for LNG marine traffic route. These 

include Gleason Point Park, Frost Island, an unnamed island in Perry, Carlow Island/Moose 

Island Scenic Area, Shackford Head State Park, Sumac Island, an unnamed island in Eastport, 

and Quoddy Head State Park in Lubec (see Appendix F, figure F-31 and F-32). No federal parks 

are located along the transit route. The southern portion of Roosevelt Campobello International 

Park, approximately 335 acres, is along the waterway. Liberty Point is the largest vehicle 

parking area in the Roosevelt Campobello International Park’s Natural Area. At this location, 

there are two decks for observation of scenic vistas, marine mammals, and birds. Liberty Point 

is a popular hiking area and is the beginning of hiking trails that parallel the shore to Lower 

Duck Pond and to Raccoon Beach. 

Table 4.7.3.1-1 lists the parks and state-owned lands that are along the waterway for LNG 

marine traffic. 

TABLE 4.7.3.1-1

Parks and State-Owned Land Along the Waterway for LNG Marine Traffic

Parcel Name Town Total Area

(acres) 

Roosevelt Campobello International Park New Brunswick 335 

Gleason Point Park Perry 32 

Frost Island and Unnamed Island Perry 1.6 

Carlow Island and Moose Island Scenic Area Eastport 31

Shackford Head State Park Eastport 90 

Unnamed Island Eastport 0.8 

Sumac Island Eastport 1 

Quoddy Head State Park and West Quoddy Lighthouse Lubec 524 

We received comments during the scoping period regarding project impacts on in-stream tidal 

power projects in the towns of Eastport, Lubec, and Perry, Maine. Several renewable energy 

tidal power projects are proposed in the general project area, located in Passamaquoddy Bay and 

Cobscook Bay. Preliminary permits were issued for the following tidal energy projects by the 

Secretary of FERC: Ocean Renewable Power Company’s Western Passage Tidal Energy Project 
4.7 – Land Use, Recreation, and Visual Resources 4-180

(FERC Docket No. P-12680), Tidewalker Associates’ Half-Moon Cove Tidal Power Project 

(FERC Docket No. P-12704), and the Passamaquoddy Tribe’s Pleasant Point/Western Passage 

Tidal Energy Project (FERC Docket No. P-12710) and Cobscook Bay Tidal Project (FERC 

Docket No. P-12711). The Pleasant Point/Western Passage permit was terminated on May 27, 

2010 at the request of the Passamaquoddy Tribe. We are aware of only one of the tidal projects 

that has advanced; Ocean Renewable Power Company placed its first prototype turbine generator 

unit online in September 2012, and will evaluate production for about three years to determine 

the potential for large scale power production.

These projects would consist of underwater turbines positioned within the water column and 

anchored to the bay/ocean bottom. Based on public information provided by the tidal energy 

companies, the top of the turbine units would be below the maximum depth of any commercial 

vessel transiting during low tide. Since the LNG vessels would be transiting the Western 

Passage at slack high tide, the turbines would be considerably below the LNG vessel hull. 

We also received comments during the scoping period from Huntsman Marine Science Center 

(HMSC), a not-for-profit research and teaching facility located in St. Andrews, New Brunswick, 

regarding access to the Western Passage for education programs. A new aquarium was opened 

on the HMSC campus in 2011, which adds to the year round attraction of the campus to tourists 

and researchers. A key component of the HMSC’s education programs is trawling for 

invertebrates and fish within the Western Passage. This area is rich in marine life, and is easily 

and cost-effectively accessible to their vessels. If HMSC is excluded from this area for 

operational or security reasons associated with the LNG facility, they feel it would negatively 

impact the quality of their programs and greatly increase the cost and time commitments of their 

clients as they would have to undertake much longer trips to alternate sites.

Similarly, HMSC’s operations depend on the maintenance of a healthy marine environment 

within the region. Should the operations of the LNG facility drive away marine mammals, sea 

birds, marine fishes, and tourists, it would directly and negatively impact their activities and 

viability.

Operation of the project facilities would impact recreational boating, fishing, and sightseeing, 

and possibly restrict HMSC research vessels throughout the LNG vessel transit route as a result 

of the moving safety/security zones around the LNG vessels. Downeast estimates that an LNG 

vessel would arrive once every five to seven days in the winter, and once every eight to ten days 

in the summer. Currently there are other terminals in the area that accommodate both industrial 

and commercial vessels, including vessels associated with the Bayside terminal to the north of 

the proposed LNG project on the St. Croix River. As a result, marine traffic associated with the 

project would not introduce any significant new type of impacts on recreational boating or 

fishing. However, as part of its WSR, the Coast Guard has recommended that comprehensive 

safety and security zones be established around LNG vessels during transit up Head Harbour 

Passage, Western Passage, and Passamaquoddy Bay for the protection of the LNG vessels, 

alternate waterway users, and area residents. This is discussed further in section 4.12. The WSR 

recommends a moving safety/security zone for Passamaquoddy Bay of 2.0 nautical miles ahead, 

1.0 nautical mile astern, and 0.25 nautical mile abeam of the vessel.

The moving safety zone is enforced around each LNG vessel as it proceeds along the marine 

traffic route, and the moored vessel security zone is enforced around the vessel unloading facility 

while a vessel is docked. This could cause impacts on recreational boating, fishing, sightseeing, 
4-181 4.7 – Land Use, Recreation, and Visual Resources

and HMSC research vessels, but the impacts would be temporary while the vessel is in transit or 

moored at the vessel unloading facility. Because the safety zone would move with the vessel, the 

impacts would be of short duration at any given point along the shipping route. In most cases 

there will be ample room for boaters to freely navigate the waterway along the outer periphery of 

the channel and ahead and astern of any LNG vessel present. Many recreational boats should be 

able to go around the LNG vessels at points in the marine traffic route that are sufficiently wide 

for them to be outside of the safety zone. In locations where the waterway is narrow, boaters 

attempting to travel in the opposite direction of an LNG vessel traveling at 10 knots may need to 

wait up to 18 minutes for the LNG vessel to pass before proceeding on its way. The delay would 

increase up to 36 minutes when the LNG vessel is traveling at 5 knots and up to 60 minutes 

when the LNG vessel is traveling at 3 knots. For boaters near or upstream of the facility, an 

additional 60-minute delay may be experienced while the LNG vessel is berthed or turned. 

Because of the relatively low volume of recreational boating in the immediate project area, 

impacts are expected to be minor. Other vessels may be allowed to transit through these security 

zones with the specific permission of the COTP determined on a case-by-case basis.

Normal transit of the LNG vessels would not affect any parks or state-owned lands listed in 

table 4.7.3.1-1. Individuals visiting Gleason Point Park, Frost Island, Carlow Island and Moose 

Island Scenic Area, Quoddy Head State Park and West Quoddy Lighthouse may be able to view 

the LNG vessels during their transit. Additionally, viewers onshore would be 1 mile or more 

from the LNG vessels, but in some locations (such as the northwest shore of Campobello Island), 

the viewing distance could be as little as 0.5 mile. Roosevelt Campobello International Park is 

located on the southern portion of Campobello Island and would be approximately 1.7 miles 

from the LNG vessels. See section 4.7.4 for a complete discussion of visual impacts.

The St. Croix Estuary Project commented that the Ganung Nature and Marine Park is located on 

a 350-acre peninsula within sight of the Downeast terminal. The Quoddy Learning Center is 

currently being constructed at the Ganung Nature and Marine Park to provide energy and 

sustainability learning. The Ganung Nature and Marine Park is located approximately 8.5 miles 

north of the Downeast terminal and would not be affected by the LNG vessel traffic or terminal 

operation.

The FWS commented that the islands that make up the Maine Coastal Islands National Wildlife 

Refuge in Washington County, Maine, may be affected by the construction and operations of the 

project. They are mainly concerned that there would be impacts on birds during nesting season 

and to other wildlife that use these islands for habitat. The Refuge consists of both mainland 

properties and a group of islands, among which are five national wildlife refuges—Petit Manan, 

Cross Island, Franklin Island, Seal Island, and Pond Island. The islands are in the Gulf of Maine 

south of Grand Manan Island. The islands would not be affected by vessel transit and would not 

be affected by the project.

The Nature Trust of New Brunswick, Canada, commented that there are Nature Preserves in 

Head Harbour Passage. They are concerned that LNG vessel traffic through the passage would 

affect the Nature Preserves’ ecological value. The only Nature Preserve that could be potentially 

affected by LNG vessel traffic is Chocolate Cove Nature Preserve on Deer Island. This preserve 

would be located about 1.3 nautical miles from the LNG vessels. The Chocolate Cove Nature 

Preserve is a public park, with cliffs, headlands on either side of Chocolate Cove, two different 

types of forest, a wetland, a meadow, and a wide range of botanical species, including wild pear 
4.7 – Land Use, Recreation, and Visual Resources 4-182

bushes. Because of the distance between the LNG vessel route and the preserve, no impacts on 

the preserve are anticipated.

The U.S. Department of the Interior expressed concern that the Machias Seal Island, which is 

managed by the Maine Coastal Islands National Wildlife Refuge, may be affected by LNG 

vessel traffic along the transit route. This island is noted for its significant seabird populations, 

including the largest tern and alcid breeding colonies in the Gulf of Maine. As indicated above, 

the islands in the Refuge, including Machias Seal Island would not be affected by the project.

4.7.3.2 LNG Terminal 

There are no public lands or other designated federal, state, or local recreation areas located on or 

within 0.25 mile of the LNG terminal site. The proposed pier would be constructed on 

submerged lands that are owned by the State of Maine.

Recreational use of the LNG terminal site associated with walking and sightseeing is minimal 

because it is privately owned and access is limited by steep slopes and rapidly rising tides that 

inundate the shoreline up to the bluffs on the northern and eastern portions of the terminal site. 

The shoreland and offshore waters of Mill Cove receive light recreational use for clamming, 

lobstering, boating, and fishing. 

Mill Cove was closed to clamming by the Maine DMR for 30 years due to bacteriological 

contamination; the Mill Cove shallows was reopened in 2006 and intermittent observations 

indicate that the northern mud flats are the most visited area of the Cove, with the area in the 

immediate vicinity of the pier footprint being rarely visited (Moholland 2006). Maine does not 

have a regulated lobstering season, and fishermen can fish year-round, but they generally only 

fish when lobsters are catchable (e.g., June/July through November/December, although some 

lobstermen fish year-round).

Bear Creek Investments announced the development of the Wabanaki Trails and Interpretive 

Center, to be known as The Trails. The Trails is planned to be located off U.S. Route 1 south of 

Mill Cove near Pulpit Rock in Robbinston, Maine. The first phase of this project has been 

designed to include a 6,000-square-foot Interpretive Center, walking trails, and access to the 

beach. According to Lewis and Malm Architecture (pers. comm., 2008), the designers of the 

Center, there are no immediate plans to commence construction of the project. We have no 

additional information since issuance of the draft EIS regarding the status of this project.

Other recreational areas in the vicinity include two Maine DOT scenic turnouts that are located 

within 0.25 mile of the LNG terminal site along U.S. Route 1. Access to these turnouts would 

not be affected by construction or operation of the proposed project; however, the tanks and pier 

would be visible to future visitors of these scenic turnouts.

Construction and operation of the LNG terminal and pier would not significantly affect access to 

or over state waters and public trust rights (State of Maine submerged lands). Recreational 

boating, fishing, and shellfishing in the immediate vicinity of the terminal likely would be 

restricted during construction due to safety concerns. During operation, shoreline fishing and 

clamming from the immediate vicinity of the LNG terminal site may be prohibited based on the

safety and security provisions at the facility that could be established by the Coast Guard. While 

the exact area of prohibited activities near the project pier has not yet been determined, it would 

be included by Downeast in its Operations and Emergency Manuals and Facility Security Plan, 
4-183 4.7 – Land Use, Recreation, and Visual Resources

which are required by federal law and must be submitted to the COTP Sector Northern New 

England for review and approval at least six months before the terminal is operational. This is 

reiterated in section 4.6, Risk Mitigation Measures, of the Coast Guard’s WSR (Appendix B). 

The prohibition of shoreline fishing or clamming in the immediate vicinity of the project’s pier is 

not anticipated to be a significant adverse impact.

4.7.3.3 Sendout Pipeline

The sendout pipeline would be within 0.25 mile of the Moosehorn NWR and would cross a 

network of ATV trails. It also would affect approximately 7.0 acres of state-owned land and 

cross the land of a proposed racino between MP 11.5 and MP 11.9.

In its initial application to FERC, Downeast proposed crossing approximately 3.5 miles of the 

Moosehorn NWR in the Baring Division. Recreational opportunities at the Moosehorn NWR 

include both consumptive (e.g., fishing and hunting) and non-consumptive (e.g., sightseeing) 

uses. Recreational use is permitted during daylight hours only. Moosehorn NWR has more than 

50 miles of dirt roads and trails available for non-motorized activities (e.g., walking, biking, 

cross-country skiing). Trails include three self-guided interpretive nature trails, and two 

observation decks offer wildlife watching. In the spring and fall, the public is invited to attend 

woodcock and waterfowl banding operations. Refuge personnel offer free tours and programs 

throughout the year, with many events occurring in the summer. Annual events include the 

Children’s Fishing Derby in June and NWR Week in October (FWS 2006).

In a scoping letter to the FERC dated October 18, 2006, the FWS raised several concerns about 

the sendout pipeline crossing of the Moosehorn NWR. Their concerns included the timing of 

construction to avoid eagle nesting season; the location of a construction staging area in the 

Wilderness Area; the disturbance to recreational activities such as hunting, hiking, and 

snowmobiling during construction; and the potential disturbance to eagle nesting areas in case 

emergency repair is required during nesting season. Additionally, the FWS was concerned that 

substantial freezing and thawing during construction could result in considerable damage to 

refuge roads and habitat.

Downeast submitted a Request for a Special Use Permit for Pipeline Right-of-Way to the 

Moosehorn NWR on January 25, 2007. Because construction of the sendout pipeline would 

create short-term impacts on sensitive wetlands, wildlife habitat, and recreational use within the 

Moosehorn NWR, the FWS denied the Special Use Permit on September 27, 2007.

In January 2008, Downeast submitted an amended application to FERC to revise their proposed 

sendout pipeline route to avoid the Moosehorn NWR. At its closest point, the proposed sendout 

pipeline route would be more than 0.25 mile away from the Moosehorn NWR between MP 10.0 

and MP 10.5, MP 12.3 and MP 14.3, MP 15.1 and MP 15.2, and between MP 17.3 and MP 17.8, 

for a total of about 3.1 miles. 

Construction is not expected to permanently impact public use of the Moosehorn NWR. It is 

expected that construction through the area proximate to the Moosehorn NWR would occur in 

the late summer and is not expected to impact recreational activities any more than other 

construction activities common in the area (e.g., construction of the Calais International Bridge 

crossing, flood control dike at the Refuge, improvements to U.S. Route 1). Construction 

activities are not within or adjacent to those areas within the Moosehorn NWR that the public 

uses on a regular basis, and thus, construction is not expected to impact recreational users. 
4.7 – Land Use, Recreation, and Visual Resources 4-184

Downeast has consistently worked with the Moosehorn NWR to review timing issues and impact 

mitigation.

In an interagency teleconference call conducted by Downeast on February 15, 2008, the FWS 

and the COE discussed parcels of land adjacent to the Moosehorn NWR that would be preserved 

in perpetuity to minimize impacts from future development as mitigation for environmental 

impacts associated with the Maine DOT’s Calais Border Crossing Project. Downeast and Maine 

DOT representatives met again on May 12, 2008. At that meeting, the Maine DOT confirmed 

that the land in question, specifically parcel 26-15, which is on the northern border of the 

Moosehorn NWR between approximately MP 13.0 and MP 13.7, is part of the mitigation plan in 

the 2006 COE permit for the Calais Border Crossing Project. The Maine DOT indicated that it 

did not yet have a formal agreement with the FWS for the property transfer. Downeast explained 

that the amended sendout pipeline route is sited along the eastern boundary of parcel 26-15. 

During the May 12, 2008 meeting, the Maine DOT indicated that it would be able to provide 

more detailed mapping of this parcel and feedback on the sendout pipeline route specifically as it 

relates to Maine DOT properties and activity. Downeast sent pipeline alignment maps to the 

Maine DOT in July 2008. On December 19, 2011 Downeast filed information with the FERC 

stating that Downeast has moved forward with securing a property option on private lands 

outside of the Maine DOT-owned land in question. 

A pipeline crossing agreement on lands held by the Washington County Community College (via 

the Maine Community College System) was reviewed by the System President and the Executive 

Committee of Trustees. Downeast coordinated the sendout pipeline alignment with the President 

of Washington County Community College and responded to questions raised by the System 

Counsel. In June 2008, the System Counsel informed Downeast that the Board of Trustees 

opposed the pipeline crossing of its property but had indicated that if Downeast were to acquire 

the right to cross the property (via eminent domain), the System would be willing to review 

potential pipeline routes in order to ensure minimal disruption to its property. 

On January 16, 2006, The Humane Society of the United States Wildlife Land Trust (the Trust) 

contacted the FWS at the Moosehorn NWR regarding the proposed sendout pipeline. William 

Kolodnicki, the Moosehorn NWR manager, contacted Downeast on January 17, 2007 to identify 

the Trust’s concerns regarding the sendout pipeline crossing the Gardner Wildlife Sanctuary. 

Downeast provided a figure of the property depicting the proposed sendout pipeline right-of-way 

to the Trust and asked that the Trust contact Downeast with additional information. Downeast’s 

January 2008 amendment to its Application rerouting the sendout pipeline to avoid crossing the 

Moosehorn NWR has effectively resolved the Trust’s concern. The modification of the pipeline 

route would avoid impacts on the Gardner Wildlife Sanctuary.

The sendout pipeline would cross 14,950 feet of ATV trails between MP 0.7 and MP 3.7 in 

Robbinston and 35,500 feet of ATV trails between MP 21.6 and MP 28.3 in Baileyville. The 

Robbinston Bushwackers and the St. Croix ATV clubs help manage these trails, and the sendout 

pipeline right-of-way would cross two segments of these trails.

Pipeline installation would not affect the use of ATV trails during construction, since the 

network of trails in the area leads to a wide variety of trails adjacent to the right-of-way. No 

single trail is relied on in the areas mentioned. There will be no limitation on access between 

points since riders will be able to continue along their path even though pipeline construction is 

occurring. There would be no net loss of ATV trails upon construction completion. ATV and 
4-185 4.7 – Land Use, Recreation, and Visual Resources

snowmobile riders could benefit due to the creation of a permanent open corridor, which will be 

maintained in conjunction with the pipeline operation.

Downeast would avoid construction impacts on snowmobile trails by scheduling construction 

during months without snow cover. Downeast would continue to work with the State of Maine 

and with members of the ATV clubs (Howard 2006a; Seavey 2006; Sears 2006) regarding the 

increased connectivity of their trail systems and temporary loss of access to some areas during 

construction. In addition to these trails, both clubs use gravel roads, and the sendout pipeline 

installation would parallel many of these roads and replace the ATV trails, providing new 

permanently maintained trails.

On lands where ATV use would not be permissible (e.g., private landowners), appropriate 

signage and/or fencing, public notices, and newspaper notices would be provided to local ATV 

clubs to restrict these lands from ATV use.

The proposed pipeline from MP 11.5 to MP 11.9 would run along the inside border of a portion 

of land optioned by the Passamaquoddy Tribe to be developed into a commercial racino. The 

racino was rejected in a statewide referendum in November 2007. Although the racino project 

was defeated, the Tribe retained the underlying land purchase option for the property, including 

the land proposed for the sendout pipeline. The Calais city council also passed a non-binding 

resolution in March 2011 in support of the racino. Discussions with Tribal representatives 

regarding an option with Downeast, which would have been secondary to the Tribe’s land 

option, were not conclusive. Preliminary negotiations with the landowner also were not 

conclusive; however, a follow-up discussion with the landowner resulted in a renewed 

opportunity to negotiate a primary option on the land. Downeast has indicated that it would 

continue negotiations with the landowner. 

4.7.4 Visual Resources 

The following section describes the existing environment and the potential visual impact of the 

proposed Downeast LNG Project and associated facilities in three parts—the waterway for LNG 

marine traffic, the LNG terminal, and the sendout pipeline. Chapter 315 in 06-096 Code of 

Maine Rules requires that an applicant for a permit under the NRPA demonstrate that the 

proposed activity will not unreasonably interfere with existing scenic and aesthetic uses of the 

scenic resources listed in Section 10 of Chapter 315, e.g., national, state, and local natural 

resources and lands that are visited by the general public. The following analysis of visual 

impact considers the existing landscape, the visibility of the proposed potential viewers, and the 

compatibility of the project with its surroundings. Visibility is assessed in terms of how much 

would be viewed and at what distance the facilities would be viewed. The viewer analysis 

considers motorists, tourists, residents, boaters, and hikers.

4.7.4.1 Waterway for LNG Marine Traffic

The waterway for LNG marine traffic is depicted in Appendix F. The waterway for LNG marine 

traffic follows two different routes from the Bay of Fundy to Quoddy Head. The route chosen by 

the LNG vessel captain would be determined in consultation with pilots, Transport Canada, and 

COTP and would depend on visibility, wind, tide cycle, and other such constraints. The eastern 

route follows an established navigational route (see Appendix F, figure F-1). This route is a 

known navigation route and should have minimal visual impact. The other route the LNG 

vessels would use is to the west of Grand Manan (see Appendix F, figure F-1). The western 
4.7 – Land Use, Recreation, and Visual Resources 4-186

route and transit from Head Harbour Passage to the proposed LNG terminal passes along and 

between Campobello Island, Indian Island, Deer Island, a number of smaller islands, and the 

Maine Coast with open water ranging from less than 1.0 mile in width to over 2.0 miles wide. 

Much of the shoreline is comprised of wooded hillsides and rocky shores. Concentrated 

development occurs in a few locations such as Eastport, Maine and St. Andrews, New 

Brunswick. Additional seasonal and year-round residential development is found at scattered 

locations along the length of the transit route.

LNG vessels servicing the proposed terminal would transport 70,000 to 165,000 m3 of LNG and 

would average 900 feet in length. Currently, a total of about 135 vessels per year pass through 

the Head Harbour Passage in the vicinity of Campobello Island. Downeast estimates that an 

LNG vessel would arrive once every five to seven days in the winter, and once every eight to ten 

days in the summer along the marine traffic route from Cutler, Maine to the LNG terminal site. 

The vessel would pass in proximity to Campobello Island and through an area with high quality 

scenic views of wide ocean expanses, and steep wooded slopes descending to the rocky 

coastline. Viewers would include motorists on U.S. Route 1 and other roads with views to 

Passamaquoddy Bay, tourists, boaters, hikers, and residents with sporadic views of the proposed 

marine traffic route with concentrations of viewers at developed areas like Eastport and St. 

Andrews. In many locations, viewers would see the entire vessel. Generally, viewers onshore 

would be a mile or more from the LNG vessels, but in locations such as the northwest shore of 

Campobello Island, the viewing distance could be less than 0.5 mile. Although the vessels 

would be large and highly visible, they would be viewed for only short durations in areas already 

used for shipping by large and small vessels and where people expect to see vessels, and should 

not result in a significant impact.

4.7.4.2 LNG Terminal

The proposed LNG terminal is located along the coast of Maine in the Town of Robbinston on 

Passamaquoddy Bay. The location of the LNG terminal and surrounding areas is shown in 

figure 4.7-1.

Passamaquoddy Bay is the dominant waterbody in the project area, which is predominately in 

Canadian waters. At the point where the Downeast LNG terminal is proposed, the Bay is 

approximately 3.0 miles wide. The berthing pier would be about 1.5 to 2.5 miles from the 

closest points on the Canada shoreline. Along Passamaquoddy Bay, north of the project, there 

are a number of coves and inlets. Of these, Mill Cove is the widest and deepest cove opening on 

the Bay, and the others open on the St. Croix River. This region is known for its high tidal 

amplitude with tidal ranges of up to 27 feet.

In the western portion of the potential viewing area of the LNG terminal, the topography is 

generally comprised of rolling hills averaging about 200 feet above sea level. Trimble Mountain 

is the highest point within the viewing area at 533 feet above sea level, and is located 

approximately 3.1 miles northwest of the proposed LNG terminal. To the north, south and west 

of the site, most of the land is wooded with open areas along the roads and shorelines. 

Vegetation is largely spruce-fir forest with some deciduous trees and old field growth. Second 

growth evergreens on the project site are approximately 50 feet in height.
Figure 4.7-1 

Downeast LNG Project

Terminal Location Map

4-187
4.7 – Land Use, Recreation, and Visual Resources 4-188

The majority of the area is undeveloped. However, along U.S. Route 1, there are a number of 

small communities such as North Perry and Robbinston. Outside Robbinston, the development 

along U.S. Route 1 is characterized by light commercial/retail, rural residential, and touristoriented facilities. Across the Bay, about 3.0 miles to the east in New Brunswick, Canada is the 

community of St. Andrews, which is the largest developed community in the viewing area (see 

figure 4.7-1). As shown on this figure, the area considered extended out 4.0 miles from the 

proposed LNG terminal.

The most prominent visual features of the proposed LNG terminal include:

• Marine Terminal – The facilities for LNG vessels docking and unloading, including a 

3,862-foot-long pier extending into Passamaquoddy Bay.

• LNG Storage and Regasification Facility – The storage facility located between 

U.S. Route 1 and Mill Cove includes two LNG storage tanks that are each approximately 

259 feet wide and 160 feet above grade. Also included are three vapor fences, a 

vaporizer building, a compressor building, a main control building, a maintenance 

warehouse, a water tank, firehouse, security building, and an administration building. 

• LNG Vessels – The proposed LNG terminal would be designed to accommodate typical 

LNG vessels, approximately 900 feet in length. On average, one LNG vessel would be 

docked at the proposed terminal every five to seven days in the winter and every eight to 

ten days in the summer.

Due to the forested rolling hills in the area, much of the onshore facility would be screened from 

areas to the north and south. The outer vapor fence, proposed to be 30 feet high, would be 

installed along the western site property along U.S. Route 1 and would be a prominent visual 

feature to vehicles driving along about a one-half mile length of the roadway. Primarily, the 

Downeast LNG pier would be visible from Mill Cove and portions of Passamaquoddy Bay, the 

St. Croix River, and St. Andrews. Figure 4.7-1 identifies areas of potential visibility from public 

viewing points including Passamaquoddy Bay. It also shows the five locations from which 

photo simulations were developed by Downeast.

Viewers within the area of visibility would include motorists on U.S. Route 1, hikers and tourists 

on Trimble Mountain and along the coast, commercial and recreational boaters and fishermen on 

Passamaquoddy Bay and the St. Croix River, residents of and visitors to St. Andrews, New 

Brunswick, and visitors to the Interpretive Center for the St. Croix Island International Historic 

Site in Canada. Portions of the storage facilities and terminal would be viewed by four abutting 

residences, several residences on the north side of Mill Cove, and residences in the vicinity of the 

intersection of U.S. Route 1 and Ridge Road. Figures 4.7-2 and 4.7-3 provide photo simulations 

of views from U.S. Route 1. Figure 4.7-4 provides a simulation for views from Trimble 

Mountain. Also, there are two informal scenic overlooks on the north and south sides of Mill 

Cove providing views of Mill Cove and Passamaquoddy Bay.

Motorists on U.S. Route 1 traveling south would have a foreground view (0.5 mile or less) of the 

pier and a portion of the storage tanks and vapor fence above the treeline for about 15 seconds 

and would have a glimpse from one other area of this highway. Motorists on U.S Route 1 

traveling either north or south would have a prominent foreground view of the outer vapor fence 

while driving along about a one-half-mile length of roadway along the western boundary of the 

site. From Passamaquoddy Bay, viewing locations would extend from the foreground to the 
4-189 4.7 – Land Use, Recreation, and Visual Resources

middle-ground (0.5 to 4 miles). All but near views of the tanks and vapor fence (most views) 

would be backdropped by local topography and vegetation helping to reduce potential visual 

impact. The pier and LNG vessels would be seen in their entirety across Passamaquoddy Bay 

and from portions of the St. Croix River. Residents and visitors to St. Andrews, approximately 

3.0 miles to the east of the terminal, would view a portion of the tanks and the entire pier and 

LNG vessels when moored, arriving and departing the proposed port. The view of the proposed 

terminal from Market Wharf on St. Andrews is discussed further below as Viewpoint 4, and is 

depicted in figure 4.7-5.

Although there are two National Natural Landmarks, a national and a local preserve, and four 

properties on or eligible for inclusion in the NRHP, these are outside the viewshed of the 

proposed LNG terminal and not visible to visitors. There are no state parks within the viewing 

area for the Downeast LNG terminal. However, a portion of the proposed pier and, about once a 

week in the winter and twice a week in the summer, an LNG vessel would be viewed from the 

international center referenced above.

From the St. Croix Island International Historic Site, there should be no adverse visual effect 

because project views would be limited to potential views of LNG vessels once a week in the 

winter and twice a week in the summer, at a distance of about 5 miles in a marine environment. 

As shown in figure 4.7-6, as viewed from the Interpretive Center in Canada, the proposed pier 

and LNG vessels would be a minor part of the viewed landscape, and the vessels would be 

compatible with the existing marine use.

As discussed in section 4.7.3, the St. Croix Estuary Project Ganung Nature and Marine Park is 

approximately 8.5 miles north of the Downeast terminal and should not be affected by the LNG 

vessel traffic or terminal operation.

Downeast provided five photo simulations to characterize the potential visual impact of the 

proposed terminal.

Viewpoint 1 – U.S. Route 1 overlooking Mill Cove (figure 4.7-2): From this location, the 

entirety of the pier, the top portion of the storage tanks, and the outer vapor fence (not shown) 

would be viewed in the foreground (within 0.5 mile) by motorists and tourists. Downeast 

originally proposed to maintain a 250-foot tree buffer along Passamaquoddy Bay; however, 

Downeast did not account for the forested areas in its hazard analyses. Therefore, in 

section 4.12.5, we have recommended that Downeast certify that all trees would be removed 

from the area between the vapor fences and the shoreline or demonstrate that the spacing of the 

trees, and any vegetation management plan, would prevent congested areas that could produce 

offsite overpressures above 1 psi. Given that recommendation, there is a possibility that the 

forested area visible in this figure would not be present after construction.

Viewpoint 2 – U.S. Route 1 view toward Liberty Point (figure 4.7-3): At this location, the 

pier and a docked LNG vessel, which would be there approximately one or two days a week, 

would be viewed in the middle-ground (distance of approximately 1.1 miles). The proposed pier 

has a line similar to background shorelines with a scale that has minimal contrast with and a size 

that is subordinate to the surrounding landscape.
Figure 4.7-2

Downeast LNG Project

Photo Simulation from Mill Cove: Sheet 1 of 3

4-190
Figure 4.7-2

Downeast LNG Project

Photo Simulation from Mill Cove: Sheet 2 of 3

4-191
Figure 4.7-2

Downeast LNG Project

Photo Simulation from Mill Cove: Sheet 3 of 3

4-192
Figure 4.7-3

Downeast LNG Project

Photo Simulation from Liberty Point: Sheet 1 of 3

4-193
Figure 4.7-3

Downeast LNG Project

Photo Simulation from Liberty Point: Sheet 2 of 3

4-194
Figure 4.7-3

Downeast LNG Project

Photo Simulation from Liberty Point: Sheet 3 of 3

4-195
Figure 4.7-4

Downeast LNG Project

Photo Simulation from Trimble Mountain: Sheet 1 of 1 

4-196
Figure 4.7-5

Downeast LNG Project

Photo Simulation from St. Andrews: Sheet 1 of 2

4-197
Figure 4.7-5

Downeast LNG Project

Photo Simulation from St. Andrews: Sheet 2 of 2

4-198
Figure 4.7-6

Downeast LNG Project

Photo Simulation from Interpretive Center: Sheet 1 of 3

4-199
Figure 4.7-6

Downeast LNG Project

Photo Simulation from Interpretive Center: Sheet 2 of 3

4-200
Figure 4.7-6

Downeast LNG Project

Photo Simulation from Interpretive Center: Sheet 3 of 3

4-201
4.7 – Land Use, Recreation, and Visual Resources 4-202

Viewpoint 3 – Trimble Mountain Private View Point (figure 4.7-4): The proposed LNG 

terminal storage tanks would be viewed at a distance of about 3 miles to the southeast. Due to 

distance, backdrop and applying appropriate coloration, the tanks would be reasonably 

compatible with the viewed landscape.

Viewpoint 4 – Market Wharf in St. Andrews, New Brunswick (figure 4.7-5): The pier, LNG 

vessels, and a portion of the storage tanks would be viewed from this location at a distance of 

approximately 2.4 to 3.2 miles. The storage tanks would be painted a neutral color so as to blend 

into the vegetated hillside that serves as a backdrop. The hillside behind the tanks would rise 

above the height of the tanks; therefore, the tanks would blend in with the backdrop. LNG 

vessels would be present on average of once or twice per week and the arrival, mooring, 

unloading, and departure sequence is expected to be completed within 24 hours. The pier would 

be 3,862 feet long, and would be elevated 18.8 feet above the mean high water level. 

Collectively, these features would have a moderate visual effect from the viewpoint in 

St. Andrews.

Viewpoint 5 – Outdoor Exhibit on the Canadian side of the St. Croix River (figure 4.7-6): 

From the St. Croix Island International Historic Site, there should be no adverse visual effect 

because project views would be limited to potential views of an LNG vessel once or twice a 

week, at a distance of about 5 miles in a marine environment. As shown in figure 4.7-6, as 

viewed from the Interpretive Center in Canada, the proposed pier and LNG vessels would be a 

minor part of the viewed landscape, and the vessels would be compatible with the existing 

marine use.

To reduce the potential visual impact of the proposed facility, Downeast has proposed the 

following mitigation techniques:

• Storage Tank Color – The tanks would be painted a neutral color to help reduce the 

visibility of these large structures and to enhance their ability to blend with the 

surrounding landscape.

• Passamaquoddy Bay Buffer – Downeast proposes to maintain an undisturbed 250-foot 

tree buffer along Passamaquoddy Bay. However, Downeast did not account for the 

forested areas in their hazard analyses. Therefore, in section 4.12.5, we have 

recommended that Downeast certify that all trees would be removed from the area 

between the vapor fences and the shoreline or demonstrate that the spacing of the trees, 

and any vegetation management plan, would prevent congested areas that could produce 

offsite overpressures above 1 psi. Given that recommendation, there is a possibility that 

these forested areas would not be present within the terminal area after construction and 

therefore, there may provide a forested buffer. They also state that side slopes of fill 

sections would be planted where feasible with low native materials to replicate existing 

conditions and minimize contrasts in color and texture seen from Passamaquoddy Bay.

• Lighting – We received comments regarding the effects of lighting on nighttime visual 

aesthetics. To address these concerns Downeast proposes to use equipment specifically 

designed to reduce off-site light spillage. Where lighting is necessary for security and 

operations, Downeast proposes to use cut-off fixtures to minimize views of light sources. 

Cut-off fixtures generally have no direct uplight, reduce glare, and are more efficient by 

directing all lighting down to the intended area only. Final lighting arrangements would 
4-203 4.7 – Land Use, Recreation, and Visual Resources

be considered by the Coast Guard during their review of the Facility Security Plan (FSP). 

The FSP is required by 33 CFR Part 105 and, as outlined in 33 CFR 105.410(b), must be 

submitted for review and approval at least 60 days prior to beginning operations.

Downeast did not propose any mitigation to reduce the potential visual impact of the proposed 

outer vapor fence; therefore, we recommend that:

• Prior to construction of the LNG terminal facilities, Downeast should file with the 

Secretary for review and written approval by the Director of OEP a mitigation plan 

to reduce the visual impact of the proposed outer vapor fence.

The proposed facilities would have a relatively large viewing area comprised of a large portion 

of the Passamaquoddy Bay and the St. Croix River with views from onshore locations limited by 

topography and vegetation. The most affected views from onshore (storage tanks and 

foreground view of outer vapor fence) would occur on U.S. Route 1, from residences along or in 

proximity to this highway. Due to the proximity, the project facilities would be highly visible to 

motorists and residents along U.S. Route 1 in the vicinity of the project. From the water the 

facilities would be highly visible from Mill Cove. Outside of Mill Cove the views grow 

increasingly distant with less visual impact as one proceeds east across the Bay. In this area, 

there is a relatively low number of viewers except at St. Andrews, which is located 

approximately 3 miles to the east.

4.7.4.3 Sendout Pipeline

Potential impacts on visual resources associated with construction and operation of pipeline 

facilities include alteration of terrain and vegetative patterns. The effects associated with 

construction through non-forested land would be temporary and minor, as the right-of-way 

would be restored to pre-existing conditions within a few growing seasons. The effects 

associated with construction through forested land would be long-term, as a portion of the 

disturbed forest would be permanently maintained right-of-way, and the remainder left to 

revegetate and eventually re-establish forest structure. During construction, the cleared and 

graded right-of-way, as well as the construction equipment operating on the right-of-way, would 

be visible from surrounding residences and local roads.

The majority of the sendout pipeline would pass through areas of wooded hills crossed by an 

occasional road with sparse development. For the majority of its length, the proposed sendout 

pipeline route would parallel existing right-of-way corridors, including the EMEC powerline 

right-of-way and the M&NE pipeline right-of-way. The heavily wooded area, in conjunction 

with local topography, would screen most of the right-of-way.

The amended sendout pipeline right-of-way no longer traverses lands of the Moosehorn NWR. 

No designated visual resource areas are likely to be affected by the sendout pipeline. Due to the 

few local roads traversing this area and the proximity to areas of low density residential 

development, the sendout pipeline right-of-way would not be visible to many motorists or local 

residents. The visual impacts associated with construction would be short-term and minimized 

by the restoration methods described in section 2.3.1.2. The 10-foot-wide corridor that would be 

permanently maintained in an herbaceous state would have minimal visual impact. 
4.7 – Land Use, Recreation, and Visual Resources 4-204

4.7.5 Coastal Zone Management 

4.7.5.1 Downeast LNG Project

The Maine CZMA is administered by the Maine Department of Agriculture, Conservation and 

Forestry, and is a partnership among local, regional, and state agencies. Maine’s coastal zone 

encompasses all political jurisdictions in Maine that have land along the coast or a tidal 

waterway, such as a river or bay. The zone encompasses Maine’s territorial waters, which 

extend 3.0 miles out to sea (Maine SPO 2008). Maine’s coastal zone also extends to the inland 

boundary of all towns bordering tidal waters and includes all coastal islands. Portions of the 

Downeast LNG Project would be located within a designated coastal zone management area in 

Maine. Specifically, the proposed waterway for LNG marine traffic from approximately Friar 

Roads to Mill Cove (see Appendix F, figure F-33), the LNG terminal, and the proposed sendout 

pipeline within the towns of Robbinston and Calais from MP 0.0 to MP 15.8 occur within the 

Maine coastal zone.

The Maine CZMP enforces various state and local environmental laws, regulations, standards, 

and criteria as the state’s coastal policies. The Maine Department of Agriculture coordinates the 

consistency review as necessary and serves as a single point of contact to receive requests for 

consistency reviews. Activities and development affecting Maine coastal resources that involve 

a federal permit or license are evaluated for compliance with the CZMA through a process called 

“federal consistency review.” Table 4.7.5.1-1 provides a list of laws and regulations that 

comprise the State’s enforceable coastal policies, with which a federal action must be consistent. 

Downeast filed a request for consistency review in December 2006; it was withdrawn by 

Downeast in November 2007 and Downeast would resubmit the request following issuance of 

the final EIS. Therefore, we recommend that:

• Prior to construction, Downeast should file with the Secretary documentation of 

concurrence from the Maine Department of Agriculture that the project is 

consistent with the Maine CZMP.

As part of the CZMA, the Maine Mandatory Shoreland Zoning Act requires that municipalities 

protect shoreland areas by adopting shoreland zoning maps and ordinances that are consistent 

with guidelines adopted by the Maine BEP. Zoning ordinances define the types of activities that 

can occur in certain areas. Shoreland areas include those within 250 feet, horizontal distance, of 

the normal high-water line of any great pond, river or saltwater body; areas within 250 feet, 

horizontal distance, of the upland edge of a freshwater wetland except in certain situations; and 

areas within 75 feet, horizontal distance, of the high-water line of a stream. Permits are required 

from each municipal planning board if land uses and/or structures could impact areas protected 

by the Mandatory Shoreland Zoning Act. The project would be located in two civil divisions of 

Maine’s coastal zone; the LNG terminal would be located in Robbinston and the sendout 

pipeline would be located in both Robbinston and Calais. The waterway for LNG marine traffic, 

although partially located within Maine’s coastal zone, is not subject to the Mandatory Shoreland 

Zoning Act.
4-205 4.7 – Land Use, Recreation, and Visual Resources

TABLE 4.7.5.1-1

Maine Coastal Laws and Regulations

Regulations Applicable Subsection

Natural Resources Protection Act 

(38 MRSA §§480-A to 480-S; 480-U to 480-Z)

Wetlands Protection rules (Maine DEP rules chapter 310) 

Coastal Sand Dune rules (Maine DEP rules chapter 355) 

Permit by Rule standards (Maine DEP rules chapter 305) 

Significant Habitat rules (Maine DIFW rules chapter 10) 

Scenic Impact rules (Maine DEP rules chapter 315)

Mandatory Shoreland Zoning Law 

(38 MRSA §§435 to 449) 

Guidelines for Municipal Shoreland Zoning Ordinances (Maine DEP rules 

chapter 1000) 

Site Location of Development Law

(38 MRSA §§481 to 485-A; 486-A; 

487-A to 490; 490-A to 490-Z)

Definitions of terms used in the site location of development law and 

regulations (Maine DEP rules chapter 371) 

Policies and procedures (Maine DEP rules chapter 372) 

Financial capacity standard (Maine DEP rules chapter 373) 

Rules regarding the traffic standard 

No adverse environmental impact standard (Maine DEP rules chapter 375) 

Soil types standard (Maine DEP rules chapter 376) 

Review of roads (Maine DEP rules chapter 377) 

Variance criteria; performance standards (storage of petroleum products) 

(Maine DEP rules chapter 378) 

Planning permit (Maine DEP rules chapter 380)

Stormwater Management rules (Maine DEP rules chapter 500)

Direct Watersheds of Lakes Most at Risk from Development (Maine DEP 

rules chapter 502)

MDOT Traffic Movement Permit 

(23 MRSA §704-A) 

Erosion Control and Sedimentation Law (38 MRSA 

§420-C) 

Subdivision Law (30-A MRSA §4401 to 4407) 

Maine Rivers Act (12 MRSA §§403 

and 407) 

Maine Waterway Development and Conservation 

Act (38 MRSA §§630 

to 636; 640)

Coastal Management Policies Act 

(38 MRSA §1801) 

Protection and Improvement of Air Law (38 MRSA 

§§349; 581 to 610-A) 

Protection and Improvement of Waters Act (38 

MRSA §§347; 361 to 367; 371-A to 372; 410-N; 411 

to 424; 451 to 455; 464 to 470) 

Nutrient Management Act

(7 MRSA Part 10) 

Land Use Regulation Law 

(12 MRSA §§681 to 689)

LURC Rules and Regulations, Chapter 10- Land 

Use Districts and Standards

List of Coastal Islands in the Jurisdiction of the Maine Land Use Regulation 

Commission

LURC Rules and Regulations, ch. 10 – Land Use Districts and Standards
4.7 – Land Use, Recreation, and Visual Resources 4-206

TABLE 4.7.5.1-1

Maine Coastal Laws and Regulations

Regulations Applicable Subsection

Maine Hazardous Waste, Septage and Solid Waste 

and Management Act (38 MRSA §§1273; 1281; 

1301 to 1310-BB; 1316 to 1316-L; 1317 to 1319-W; 

1362; 1609-10; 1661-1661-C; 1851-2;2133, 

sub §2(A); PL 1999 c.348; 2157; 2302 to 2313)

Nuclear Facility Decommissioning Laws (PL 1999 c. 

741)

Oil Discharge Prevention & Pollution Control Law 

(38 MRSA §§344 to 349; 541 to 560; 563 sub-§1(A) 

and 2; 

563-A-C; 564; 566-A; 568-A; 569-A to 569-B; 570-A 

to 570-L; 585-D; 585-H

Marine Resources Law (12 MRSA §§6171 to 6192; 

6432-A)

Coastal Barrier Resources System Act (38 MRSA 

§§1901 to 1905)

Maine Endangered Species Act 

(12 MRSA §§12801-12809; 12 MRSA §6971-6977; 

12 MRSA §10001, sub-§§19 and 62)

Endangered Species Rules (Maine DIFW Chapter. 8)

Robbinston has adopted a Land Use and Development Code for regulating the uses of land 

within the town boundaries. The Land Use and Development Code requires that all new 

developments obtain a land use permit from the Robbinston Planning Board (Robbinston 

Comprehensive Plan 1996), which was granted for the LNG terminal on February 16, 2006 

under its Shoreland Zoning Ordinance, and a Conditional Land Use Permit. The Downeast LNG 

Project is in conformance with this aspect of the Maine CZMP. Downeast consulted with town 

officials in Robbinston concerning its requirements for the construction of the sendout pipeline 

within specially designated lands.

The City of Calais has also adopted a Shoreland Zoning Ordinance, where essential services such 

as public utilities (e.g., natural gas transmission lines, electric transmission lines, sewage 

collection, and treatment facilities) may be permitted in the Shoreland Districts upon application 

to the City of Calais Planning Board. Downeast consulted with city staff concerning its 

requirements for the construction of the sendout pipeline within specially designated lands. The 

City Manager and Code Enforcement Officer for Calais, James Porter, reported to Downeast that 

the sendout pipeline, as a regulated utility facility, would fall under zoning exemptions 

(Porter 2006).

There are a number of state permit requirements that comprise the Maine CZMP, but the two 

more significant programs are the NRPA and the Site Location of Development Law, which are 

briefly discussed below.
4-207 4.7 – Land Use, Recreation, and Visual Resources

Under the NRPA, portions of the LNG terminal and sendout pipeline would be installed under a 

Permit by Rule allowing for the installation, maintenance, and replacement of a submerged 

utility line across a coastal wetland, freshwater wetland, great pond, river, stream, or brook 

excluding outstanding river segments identified in 38 Maine Revised Statute Annotated (MRSA) 

Section 480-P. Downeast filed an application with the Maine DEP on December 19, 2006, 

withdrew this application on November 11, 2007, and plans to re-submit the application 

following issuance of the final EIS. Downeast would obtain a permit prior to construction.

Under the Site Location of Development Law, projects occupying more than 20 acres must be 

reviewed. The LNG terminal and applicable portions of the sendout pipeline would obtain this 

approval prior to construction. Downeast filed an application on December 19, 2006, withdrew 

this application on November 11, 2007, and plans to re-submit the application following issuance 

of the final EIS. A determination that the project is consistent with the Maine CZMP must be 

received prior to construction of the LNG terminal and pipeline. 

4.7.6 Hazardous Waste Sites

4.7.6.1 Waterway for LNG Marine Traffic

There are six onshore hazardous waste sites located along the waterway that would be used by 

LNG vessels. All six sites are mapped within the Town of Eastport. These sites would not be 

affected by LNG vessel transit during normal operation.

4.7.6.2 LNG Terminal

Downeast conducted a search of available environmental database records and no sites 

associated with the storage, release, or disposal of petroleum products or hazardous materials or 

groundwater contamination were identified within 0.25 mile of the LNG terminal site 

(EDR 2006; EGAD 2006). For more detailed discussion see section 4.2.7.1.

4.7.6.3 Sendout Pipeline

Downeast conducted a search of available environmental database records within 0.25 mile of 

the sendout pipeline route. Based on the results of the search, 15 sites associated with the 

storage, release, or disposal of petroleum products or hazardous materials or contaminated 

groundwater were identified within 0.25 mile of the sendout pipeline centerline. A list of the 

identified sites, locations, and approximate milepost along the sendout pipeline route are shown 

in tables 4.2.7.2-1 and 4.2.7.2-2. 
4.8 – Socioeconomics 4-208

4.8 SOCIOECONOMICS

Several potential socioeconomic effects may result from construction and operation of the 

proposed LNG project. Many of these potential effects are related to construction and include 

the number of local and non-local construction workers who would work on the project; their 

income and local expenditures; and their impact on population, public services, and temporary 

housing during construction. Other potential effects related to construction include local 

construction expenditures by Downeast. Potential economic benefits associated with operation 

of the project include increased property tax revenue, increased job opportunities and income, 

and ongoing local expenditures by the company.

The proposed project consists of two components, the LNG terminal and the sendout pipeline. A

discussion of the effects of the proposed project to local population, the economy, housing, tax 

revenues, public services, and environmental justice is provided below. 

The Save Passamaquoddy Bay group commissioned a study of the potential impacts from an 

LNG terminal development that would be located on Passamaquoddy Bay. This report is 

referred to as the “Whole Bay Study” and was filed with the Commission on October 2, 2006. 

The Study primarily focuses on the socioeconomic and fiscal impacts of constructing and 

operating LNG facilities in the Passamaquoddy Bay area. Some concerns expressed in the Study 

have also been raised by other members of the public in their scoping comments. The issues 

raised by the Study have been fully evaluated within this section of the EIS.

4.8.1 Population 

The proposed project would be located in Washington County, Maine. Washington County is 

the easternmost county in the United States with a land area of 2,568 square miles and a low 

population density. The county seat is Machias, approximately 45 miles west of the Downeast 

LNG Project area. Washington County’s 2010 population was 32,856. The county ranked 14th 

in population among Maine’s 16 counties, but 5th in land area. 

Based on U.S. Census Bureau (USCB) population estimates for 2010, the county’s population 

declined by 3.2 percent between 2000 and 2010. By comparison, Maine’s population grew by 

4.1 percent and the U.S. population grew by 8.0 percent between 2000 and 2010. The county’s 

average population density in 2010 was 12.8 persons per square mile, and the median age was 

46.1 (USCB 2000, 2010). Table 4.8.1-1 presents population trends for the project area 

communities and comparison areas. As the table shows, many of the communities that would be 

affected by the project have experienced the overall trend of declining populations that has 

typified Washington County (and most rural areas of the United States). Communities within the 

project area declined by 5 percent between 2000 and 2010.
4-209 4.8 – Socioeconomics

TABLE 4.8.1-1

Population Trends, Downeast LNG Project Area and Comparison Regions

Area 2000 2010 % Change, 

2000-2010

United States 281,421,906 303,965,272 8.0%

Maine 1,274,923 1,327,665 4.1%

Washington County 33,941 32,856 -3.2%

Project Area

Robbinston 525 592 12.8%

Alexander 514 350 -31.9%

Baileyville 1,686 1,544 -8.4%

Baring Plantation 273 316 15.8%

Calais 3,447 3,192 -7.4%

Charlotte 324 311 -4.0%

Cooper 145 202 39.3%

Eastport 1,640 1,425 -13.1%

Meddybemps 150 136 -9.3%

Pembroke 879 980 11.5%

Perry 847 943 11.33%

Princeton 892 898 0.7%

Pleasant Point Reservation 640 475 -25.8%

Total Project Area 11,962 11,364 -5%

Source: USCB 2000, 2010

 

4.8.1.1 LNG Terminal

Short-term demographic impacts would result from an influx of construction workers during the 

construction phase of the LNG project, anticipated to last approximately three years. The 

construction workforce is estimated to average 332 workers, with peaks of about 650 workers at 

various points in the project. Downeast has assumed that 20 percent of the workforce would be 

specialized workers from outside the project area, and that approximately 50 percent of the 

remaining general workers would also be from outside the project area, for an average total of 

about 200 workers potentially relocating. If it were conservatively assumed that all the non-local 

workers would move into the area with their families, the county’s population could increase by 

1.7 percent and the project area’s population by 4.9 percent.17 With the existing trend of 

declining area populations, this would be a beneficial impact. 

Long-term impacts on local population would result from the addition of 78 permanent staff, 

consisting of 4 tugboat crews and 62 terminal staff, and their families. Given the extent of 

marine activities in the project area, it is highly likely that most if not all of the tugboat operators, 

and many of the terminal staff, would be hired locally. Even if all 78 workers were to relocate 

into the project area with their families (for a total of approximately 222 persons), Washington 

 17 This estimate is based on an average family size of 2.76 in Washington County (USCB 2010).
4.8 – Socioeconomics 4-210

County population would increase by only 0.7 percent, while population in the project area 

would rise by 2 percent. Again, this would be a beneficial impact on local population.

4.8.1.2 Sendout Pipeline

The pipeline construction labor force is estimated at 320 workers. Many workers would likely 

be hired from among the local employment force. Since the construction period is expected to 

be no more than about nine months, it is unlikely that non-local workers would permanently 

relocate to the project area, or would bring their families during the construction period. 

Population impacts from construction of the sendout pipeline are expected to be minimal. 

4.8.2 Economy 

This section contains a discussion of the local and regional economy, including employment and 

personal income, property values, tourism, the fishing industry, and agricultural industries. 

Section 1.1, Purpose and Need, includes a discussion of United States and New England natural 

gas trends, supply and demand issues, and the role of LNG.

4.8.2.1 Employment and Personal Income

Washington County’s 2011 civilian labor force averaged 14,278, according to the Maine 

Department of Labor. The 2010 civilian labor force of 15,603 in Washington County

represented an increase of 1.6 percent over the 2000 civilian labor force of 15,354. In contrast, 

between 2000 and 2010, the civilian labor force in Maine increased by 7.4 percent and in the 

United States, by 11.9 percent (USCB 2000, 2010; Maine Department of Labor 2013).

As of 2011, the government and government enterprises sector provided the greatest amount of 

employment (25.2 percent of the civilian labor force) in Washington County. The retail sector 

provided 16.5 percent of the county’s jobs, manufacturing provided 11.1 percent, and 

construction jobs accounted for 2.5 percent (BEA 2006). The average 2011 unemployment rate 

for the State of Maine was 7.7 percent, while the unemployment rate for Washington County was

7.6 percent, the highest unemployment rate in the state (Maine Department of Labor 2013). 

4.8.2.2 Commercial Shipping

The Port of Eastport has experienced varying commercial shipping activity over the past decade. 

Data from the DOT showed a total of 66 vessel calls in 2004, a 65 percent increase over 2002. 

However, since 2004, vessel traffic has declined sharply, with only seven calls recorded in 2007 

(the latest year available). During 2002 to 2004, the vast majority of traffic was general cargo, 

and in 2007 all shipping was general cargo (MARAD 2009). Much of Eastport’s shipping 

decline resulted from the closing or downsizing of paper mills in the area. Table 4.8.2.2-1 shows 

commercial vessel traffic by type for the Port of Eastport. During 2002-2004, the vast majority 

of traffic was general cargo.

Vessels bound for the Downeast LNG terminal can take one of two routes; the western route, 

which transits Grand Manan Channel to the west of Grand Manan Island; or the eastern route 

that follows the traffic lanes in the Grand Manan basin on the easterly side of Grand Manan 

Island towards the port of St. John, New Brunswick, turning west at the designated Eastport turnout lane. Both routes converge offshore in the general vicinity of the entrance to Head Harbour 

Passage, north-northeast of Campobello Island. Commercial marine traffic and other economic 

activity along the waterway route that would be used by the LNG vessels could be affected by 
4-211 4.8 – Socioeconomics

the passage of the LNG vessels. The Coast Guard’s WSR recommends the development of 

safety and security zone parameters that would be developed with the COTP in coordination with 

the government of Canada (see section 4.12 for more detail on marine traffic safety). The Coast 

Guard has indicated in the WSR that the combined moving safety/security zone for an LNG 

vessel in Passamaquoddy Bay would be 2 nautical miles (4,000 yards) ahead of the vessel, 

1 nautical mile (2,000 yards) astern of the vessel, and 0.25 mile (500 yards) abeam each side of 

the vessel. The speed of the LNG vessel would vary between about 5 and 10 knots18 through the 

transit route in accordance with waterway conditions, and decrease to 2 knots as the vessel 

approaches the terminal. At 10 knots, a vessel would take approximately 18 minutes to pass any 

given point. 

TABLE 4.8.2.2-1

Commercial Vessel Traffic, Port of Eastport, Maine, 2006-2010

2006 2007 2008 2009 2010 % Change 

2006-2008

% Change 

2006-2010

All Types a/ Calls 12 7 15 3 7 25% -42%

Capacity 467,986 97,202 486,980 55,306 135,217 4% -71%

Tanker (Product) b/ Calls 1 0 0 0 0 0.0% 0.0%

Capacity 16922 0 0 0 0 0.0% 0.0%

Dry Bulk c/ Calls 6 0 0 0 0 0.0% 0.0%

Capacity 253,066 0 0 0 0 0.0% 0.0%

General Cargo d/ Calls 5 7 15 3 7 200% 4%

Capacity 197,998 97,202 486,980 55,306 135,217 146% -31.7%

Capacity as % of Total

 Tanker (Product) 3.6% 0.0% 0.0% 0.0% 0.0%

 Dry Bulk 54.1% 0.0% 0.0% 0.0% 0.0%

 General Cargo 42.3% 100.0% 100.0% 100.0% 100.0%

a/ Only vessel types that called on Eastport are included. The following types were excluded: Crude Tanker, Container: "RoRo"[roll-on, roll-off cargo loading vessels]: Vehicle; Gas Carrier; Combination.

b/ All tanker traffic belonged to the Product Tanker subcategory of Tanker. Product tanker = 10,000 - 69,999 (deadweight 

DWT).

c/ Dry Bulk :Bulk Vessels, Bulk Containerships, Cement Carriers, Ore Carriers, Wood-chip Carrier.

d/ General Cargo: General Cargo Carriers, Partial Containerships, Refrigerated Ships, Barge Carriers, Livestock Carriers.

Source: DOT Maritime Administration (MARAD) 2010.

Downeast estimates that there would be one vessel every five to seven days in the winter 

(slightly more often than once per week), and one vessel every eight to ten days in the summer 

(or about once every week and a half), approximately 60 vessels per year. In locations where the 

waterway is narrow, some mariners attempting to travel in the opposite direction of an LNG 

vessel traveling at 10 knots may need to wait up to 18 minutes for the LNG vessel to pass before 

proceeding on its way. The delay would increase up to 36 minutes when the LNG vessel is 

traveling at 5 knots and up to 60 minutes when the LNG vessel is traveling at 3 knots. For 

mariners near or upstream of the facility, an additional 60-minute delay may be experienced 

while the LNG vessel is berthed or turned. Other vessels may be allowed to transit through the 

LNG vessel security zones with the specific permission of the COTP determined on a case-bycase basis. Mariners and other users of the waterway would receive advance warning of an LNG 

vessel transit and associated waterway restrictions through various established communication 

methods and public service announcements. Given the limited amount of LNG vessel traffic, the 

 18 A knot equals 1.0 nautical mile (6,016 feet) per hour, and is equivalent to 1.15 statute (land) mph.
4.8 – Socioeconomics 4-212

implementation of vessel traffic management practices, as recommended by the Coast Guard’s 

WSR, the advance notice to United States and Canadian authorities from the LNG vessels

transiting the area, and the limited time that nearby marine traffic could be interrupted, impacts 

on commercial marine activity would be insignificant.

One expected beneficial impact is the increase in the demand for pilots to guide the LNG vessels 

safely through the Western Passage to the LNG facilities, and tugboats and associated crews to 

assist the vessels. According to the Coast Guard, as per the current, informal practice, the LNG 

vessels would pick up pilots at the East Quoddy Head Pilot Station. Downeast expects that each 

vessel would ultimately need three to four tractor tugs (depending on carrier size) during transit 

of the waterway to the LNG facility. The proposed project would increase employment 

opportunities for pilots, tug captains, and tug crews, and would increase the need for tugboats 

and tug maintenance services. 

4.8.2.2.1 LNG Terminal

Downeast has stated that it intends to hire locally to the extent possible, and it is assumed that 

within the constraint of union labor rules, some workers would have opportunities for additional 

job training. Therefore, the proposed LNG project would create short-term beneficial impacts on 

both local and regional employment during the construction phase, with additional long-term 

benefits to the local workforce if workers were able to improve their skills. 

Downeast forecasts that construction of the proposed LNG project would create an estimated 

total average of 569 jobs, with a peak of about 650 jobs. Work at the LNG terminal site would 

require an average annual employment base of 332 workers. Based on the anticipated schedule, 

75 percent of these workers would be on-site during peak construction activities (approximate 

average of 249 workers on-site at any one moment in time). Downeast also estimated that 

approximately 320 pipeline workers would be required during a nine-month pipeline 

construction period.

Downeast commissioned the University of Maine to conduct a study of the economic impacts of 

the proposed Downeast LNG Project.19 The findings of this study indicate that construction 

activities would support an estimated 1,053 jobs throughout the state in each of the three years. 

Such an increase in employment would be equivalent to 0.16 percent of total state employment 

as of 2011. Maine workers associated with Downeast’s pre-operations activities would receive 

an estimated $42.9 million in income per year. Furthermore, the study found that terminal 

construction would support an estimated 375 jobs in Washington County (counted in the 

statewide impact of 1,053 jobs noted above) in each year of the construction project. These 

workers would receive an estimated $15.3 million in income per year. An impact of 375 new 

jobs would be equivalent to 2.9 percent of total employment in Washington County as of 2011

(Maine Department of Labor 2013). The study used an employment multiplier of 2.04, meaning 

that each Washington County worker employed on the construction project would support an 

additional 1.04 workers within the county. However, it should be noted that the U.S. Bureau of 

 19 Todd Gabe Jonathan Rubin, et al. 2005. Economic and Fiscal Impacts of a Proposed LNG Facility in Robbinston, 

Maine. University of Maine REP Staff Paper #556. November. The research was supported by a grant from 

Downeast LNG. The study assessed other LNG projects and studies, and used the IMPLAN model to forecast 

employment requirements and associated impacts (indirect employment, income and tax generation).
4-213 4.8 – Socioeconomics

Economic Analysis20 calculated an employment multiplier of 1.44 for Washington County, 

which would result in a smaller number of indirect jobs and lesser amounts of secondary income 

than predicted by the University of Maine study. By either calculation, the creation of secondary 

jobs and income would be a beneficial impact for the project area.

Of the $400 million expenditure to construct the Downeast LNG Project, the University of 

Maine study estimated that $222.5 million would be spent within the state over three years, 

resulting in beneficial impacts within the project area, the county, and the state. 

Prior to beginning operations, Downeast plans to purchase tugboats that would be built by a 

Maine company located outside of Washington County. This spending represents another shortterm impact that would occur during the construction phase. The University of Maine study 

assumed that the boats would be built over a three-year period and that $8 million of spending 

would occur in each year, directly supporting 52 jobs per year and providing $2.1 million in 

annual labor income. Along with these direct impacts, the multiplier effects associated with 

spending by the boat builder and its workers would amount to an estimated annual 35 jobs and 

$1.1 million in labor income, for a total of 87 temporary jobs and $3.2 million in labor income 

per year. This would be a beneficial impact on the region.

When the proposed project begins operation, it would affect the economy through the creation of 

direct employment opportunities and the purchases of goods and services from other businesses 

located within Washington County and the rest of Maine, providing beneficial long-term impacts 

on the area. 

Operation of the proposed LNG facilities would employ 78 workers, including 16 tugboat 

operators and 62 positions within the terminal. Tugboat operators’ and facility workers’ annual 

salaries, including benefits, are expected to average $51,750 and $69,000, respectively. 

In addition, Downeast expects to purchase $4.0 million worth of goods and services from other 

Maine businesses on an annual basis. The employment multiplier suggests that operation of the 

project would support a total of 253 jobs across Maine over the lifecycle of the LNG terminal, 

which is expected to be 30 years or longer. These workers would receive an estimated 

$10.7 million in income per year. A statewide impact of 253 jobs would be equivalent to 

0.036 percent of total state employment as of 2004. 

Focusing on local effects, the University of Maine study found that the LNG terminal operations 

would support a total of 187 jobs in Washington County over the terminal’s lifecycle. These 

workers would receive an estimated $8.1 million in income per year. A county-level impact of 

187 jobs would be equivalent to 1.33 percent of Washington County’s total employment in 2000. 

The local availability of goods and services needed by the LNG facilities would determine the 

proportion of the $4.0 million in anticipated annual spending (during the 30-year or longer 

lifecycle of the import terminal) that would take place in Washington County. Based on 

information from an economic model for the State of Maine, the University of Maine study 

assumed that the LNG facility would purchase $2.35 million of goods and services in 

Washington County on an annual basis. 

 20 The U.S. Bureau of Economic Analysis (BEA), Regional Economic Analysis Division, uses an updated version of 

the Regional Industrial Multiplier input-output model (RIMS II) to estimate secondary impacts that are specific both 

to certain types of industries and to certain regions. The RIMS II Multipliers presented here are based on BEA’s 

2003 national annual input-output (I-O) accounts and BEA’s 2003 regional economic accounts (BEA 2006).
4.8 – Socioeconomics 4-214

The Town of Robbinston and Downeast have finalized a “Host Community Benefits Agreement” 

that outlines a number of commitments being sponsored by Downeast in the event the project is 

developed. Downeast stated that these commitments would serve to ensure that project benefits 

are shared with the people of Robbinston and that certain obligations and services are 

documented in a legally binding document. 

Under the Host Community Benefits Agreement, Downeast has agreed, subject to the availability 

of sufficient qualified local firms and personnel, to set aside 5.0 percent of the construction 

contracting value for the LNG project that is to be performed within the State of Maine for 

contractors that are based in Washington County. In addition, Downeast has agreed to provide 

incentives to its construction contractors to employ Washington County local workers and to 

make available to qualified hires, as needed, up to five months of basic construction job training 

through a qualified training institution or entity. For operations, Downeast has also agreed 

(subject to the availability of a sufficient pool of qualified local workers) to maximize the levels 

of employment of local workers and to pay the costs of any training required for local workers 

hired to work.

4.8.2.2.2 Sendout Pipeline

In contrast to the estimated 320 pipeline construction workers, only 4 permanent staff would be 

required for operation and maintenance of the sendout pipeline. Therefore, there would be small 

beneficial impacts resulting from any local purchase of goods and services, and expenditures by 

inspection and maintenance personnel. 

4.8.2.3 Property Values

Many local residents expressed concerns during the scoping process about the proposed project’s 

impact on property values, insurance rates, and any visual impacts that could affect local 

tourism. Comments were also expressed regarding property devaluation caused by the 

construction and operation of the sendout pipeline.

The transit route is currently being used by large vessels enroute to other United States and 

Canadian facilities. The addition of one LNG vessel in passage along the waterway every 8 to 

10 days would be very unlikely to adversely affect the value of properties along the shoreline. 

Many residents along waterways enjoy observing ships and other marine traffic and consider it 

an “amenity” of shoreside living. 

4.8.2.3.1 LNG Terminal

Appraisal methods used to value land are based on objective characteristics of the property and 

any improvements. The impact an LNG facility may have on the value of a tract of land depends 

on many factors, including size, the values of adjacent properties, presence of other industrial 

facilities, the current value of the land, and the current land use. Regional studies have been 

conducted to evaluate the potential effects of LNG terminals and other types of energy facilities 

on local property values. A 1995 study surveyed several land assessors from the Commonwealth 

of Massachusetts (Real Estate Counseling Group of Connecticut 1995). A 1993 study examined 

the effects of 262 facilities on standardized 1,000-square-mile areas across the United States, 

11 of which were LNG facilities (Clark and Nieves 1993). These studies concluded that the 

presence of an LNG facility did not have a significant positive or negative impact on either 

wages or property values. Based on information from these studies, it is unlikely that the 
4-215 4.8 – Socioeconomics

construction and operation of the LNG terminal would have significant adverse impacts on 

property values in the surrounding area.

Homeowner insurance rates are generally set on a countywide basis, with individual rate 

adjustments made to reflect the age and value of the property and the claims record of the owner. 

Insurance rates are not based on the surrounding landscape or structures at the local level. It is 

not anticipated that the presence of the proposed LNG facilities would adversely affect the 

insurance rates of nearby residences. 

A land parcel’s property taxes are generally based on the actual use of the land. Construction of 

the LNG facilities would not likely change the general use of the land for surrounding properties. 

If a landowner feels that the presence of the LNG facilities reduces the value of his or her land, 

resulting in an overpayment of property taxes, he or she may appeal the assessment and 

subsequent property taxation to the local property taxation agency. 

Under the Host Community Benefits Agreement, Downeast has agreed to compensate owners of 

any affected business in the town that was in operation as of July 11, 2005, and that is 

determined by an independent arbitrator to have been adversely impacted solely by the 

construction and operation of the project. Downeast has also agreed to compensate residential 

property owners whose property abuts the project boundary, is located immediately across 

U.S. Route 1 from the terminal site, or is on the north shoreline of Mill Cove and faces the 

shoreline portion of the terminal site. Property owners would receive a one-time impact fee of 

$25,000 or would be compensated for the reduced market value of properties that were sold.

4.8.2.3.2 Sendout Pipeline

Comments were received during the scoping process regarding property devaluation caused by 

the construction and operation of the sendout pipeline. Appraisal methods used to value land are 

based on objective characteristics of the property and any improvements. The impact a pipeline 

may have on the value of a tract of land depends on many factors, including the size of the tract, 

the values of adjacent properties, the presence of other utilities, the current value of the land, and 

the current land use. Subjective valuation is generally not considered in appraisals. This is not 

to say that the pipeline would not affect resale values. A potential purchaser of property may 

make a decision to purchase based on his or her planned use, such as agricultural, future 

subdivision, or second home on the property in question. If the presence of a pipeline renders 

the planned use infeasible, it is possible that a potential purchaser would decide not to purchase 

the property. However, each potential purchaser has different criteria and differing capabilities 

to purchase land. 

The effect of an easement on property values would be negotiated between Downeast and 

affected landowners during the easement acquisition process, which is designed to provide fair 

compensation to the landowner for the right to use the property for pipeline construction and 

operation. To the extent eminent domain might be required to acquire a section of the right-ofway, established legal methods of valuation would be used to compensate owners for any lost 

value. 

Property taxes on a parcel of land are generally based on its actual use. Construction of the 

pipeline would not change the general use of the surface property, but it would preclude the 

construction of aboveground structures (and other activities involving excavation) along the 

permanent right-of-way. The pipeline right-of-way must also be kept clear of timber. If a 
4.8 – Socioeconomics 4-216

landowner feels that the presence of a pipeline easement reduces the value of his or her land, 

resulting in an overpayment of property taxes, he or she could appeal the issue of the assessment 

and subsequent property taxation to the local property taxation agency. 

4.8.2.4 Tourism

According to the Maine Department of Economic and Community Development (Maine DECD) 

(2006), the travel and tourism industry continues to be a significant and growing contributor to 

Maine’s economy. The entire state is visited by tourists, including the Downeast LNG Project 

area and surrounding environs. Attractions in the state include natural resource areas, recreation 

and hunting/fishing, water-related activities, casinos and cruises, and others. In particular, Saint 

Andrews, Campobello and Eastport are using local initiatives and investments to actively expand

local cruise ship tourism. These ports-of-call attracted 11 ships during 2012 that resulted in 

estimated local expenditures of at least $100 per passenger and total local expenditures of close 

to $1 million (McIntyre 2013). From 2009 to 2013, the Town of Saint Andrews invested 

$900,000 in the Town Market Wharf to support large cruise ships and smaller ships (Choptiany 

2013) and investors have committed as much as $5 million at Welshpool in Campobello for 

wharf improvements. In addition, the island of Grad Manan has been working with Saint 

Andrews and Eastport to attract small expedition ships to the area (McIntyre 2013).

The Maine Department of Tourism reports that net direct tourism expenditures amounted to 

$4.9 billion in 2011, which was made up by $1.2 billion of expenditures in lodging, $569 million 

in transportation, $1.3 billion in food, $1.5 billion in retail goods, and $351 million in recreation.

Net spending by overnight leisure travelers (41.3 percent) was greater in every category as 

compared to net spending by day leisure travelers (58.7 percent) (Maine Department of Tourism 

2012). According to the Maine Department of Tourism, 653 people were employed in leisure 

and hospitality in Washington County in 2011 and made a total of $8.2 million in wages (Maine 

Department of Labor 2013). State tax rates are 5 percent for sales and 7 percent for lodging and 

food; there is no local community option to tax. However, tourism studies (Longwoods 

International 2004) have found that while 39 percent of first-time visitors listed 

Downeast/Acadia as their main destination, only 18 percent of repeat visitors listed 

Downeast/Acadia as their main destination. In the project area, Eastport was the choice of only 

6.0 percent of first-time visitors and 3.0 percent of repeat visitors, while Calais was selected by 

7.0 percent of both first-time and repeat visitors.

As another tourism measure, taxable retail sales data for 2012 from the Maine Office of Policy 

and Management (2013) show that Washington County, had $2.2 million in restaurant and 

$734,600 in lodging sales, accounting for 16.7 percent of total retail sales (Maine Office of 

Policy and Management 2013).

LNG vessels bound for the Downeast LNG terminal can take one of two routes; the western 

route, which transits Grand Manan Channel to the west of Grand Manan Island; or the eastern 

route that follows the traffic lanes in the Grand Manan basin on the easterly side of Grand Manan 

Island towards the port of St. John, New Brunswick, turning west at the designated Eastport turnout lane. Both routes converge offshore in the general vicinity of the entrance to Head Harbour 

Passage, north-northeast of Campobello Island. Along the transit route, recreational activities 

are not expected to be significantly affected. From 2010 to 2013, the tour boat industry has 

generated revenues of $54,000 as a result of passenger capacity, $18,000 for berthing fees for the 

town of St. Andrews, and $5.4 million in ticket sales at the wharf for the tour boat operators. The 
4-217 4.8 – Socioeconomics

tour boat industry also contributes high seasonal employment (Boucher 2013). Whale watching 

vessels generally dock in St. Andrews, Canada, and access whale watching areas via Letite 

Passage, rather than along the proposed transit route for LNG vessels. Other whale watching 

vessel transits are not expected to be significantly affected by LNG shipping. However, 

disruptions to local whale habitat from large vessels may require the whale watching vessels to 

travel to farther areas, adding expenses for the tour boat operators in fuel costs and loss of time

(Boucher 2013). LNG vessels would transit the Western Passage less than once a week (every 

eight to ten days) during the major whale watching season, from mid-June to September (Bay of 

Fundy.com 2009). As discussed in section 4.7.3, recreational boating traffic is extremely light 

with only a handful of vessels operating on any given day. Several local festivals or events occur 

along the shoreline of the LNG vessel transit route, including the Eastport Fourth of July 

Celebration, with large U.S. Navy vessels present, and the Salmon Festival. These events 

reportedly provide a major portion of the summer revenue stream for local businesses. However, 

these events would not likely be adversely affected by the Downeast operations, since LNG 

vessel scheduling can usually be pre-established to avoid interference with special waterway 

event days. In any event, the 15 to 30 minute transit of a Downeast LNG vessel past Eastport 

approximately two times (once inbound and once outbound) every eight to ten days in the 

summer should not have a material impact on Eastport summer business activities or visitors. 

Eastport residents, tourist-type businesses, and the Port of Eastport should not incur a significant 

adverse impact from the transit of an LNG vessel on an average of once per week. 

4.8.2.4.1 LNG Terminal

As noted above, tourism in the project area is not a large contributor to the state or local 

economy. However, tourism-type activities in both Maine and Canada remain an important part 

of the area’s amenities, with many residents taking part in many of the same activities as tourists, 

especially boating recreation, hunting, shopping, dining out, and local festivals and other events.

During construction, Downeast would mitigate interruption to local businesses by maintaining 

access to side roads and business entries. Local concerns about construction activity and 

possible impacts on local businesses primarily focus on the reaction of possible shoppers if large 

numbers of construction vehicles on U.S. Route 1 cause delay of traffic. In particular, it is 

believed that potential customers would not consider getting off the road to come into a roadside 

business.

Traffic studies conducted for Downeast indicate that, with proper planning and mitigation 

measures, the construction of the project would not result in significant traffic delays or 

stoppages (see section 4.9 for further information on transportation and traffic). State and local 

road cut permits may also include measures to mitigate the impact of traffic caused by 

construction. 

No major recreational activities occur at the proposed pier location. The proposed pier is over 

3,000 feet from the currently used vessel channel, providing more than sufficient access for 

vessel use. Concerns have been expressed that the visibility of the LNG terminal may affect 

tourism. The LNG terminal is being constructed so as to have minimal viewshed impacts from 

the Canadian side of the river, and would not emit smoke or steam. Viewshed changes would 

have minimal impacts to tourists in both the United States and Canada.
4.8 – Socioeconomics 4-218

4.8.2.4.2 Sendout Pipeline

Construction of the sendout pipeline could have brief, localized impacts on tourist traffic if 

construction vehicles caused congestion on local roadways. The mitigation measures discussed 

in section 4.9 of this EIS would apply to pipeline construction traffic, and impacts during 

construction would be insignificant. No impacts on tourism are anticipated from the pipeline’s 

operation. 

4.8.2.5 Fishing Industry

The principal commercial fisheries in the vicinity of the proposed project and the LNG marine 

traffic route are lobster and herring, clamming, and salmon aquaculture.21 Combined 

commercial fishing income for the primary users of Mill Cove is about $19,000 per year at 

current market prices, including $10,000 from lobstering and $9,000 from herring. Previous 

income from the local area was substantially higher, principally due to significantly higher yields 

in the past (Morrison 2006). Washington County had approximately 2,000 active commercial 

fishermen and approximately $800 million in landings in 2012 (Maine DMR 2012).

Due to the strong currents, commercial fishing within the channel is relatively light. Most of the 

lobster fishing is conducted in the Grand Manan Channel and along the coast south of Lubec 

Narrows. Herring is harvested mainly through the use of weirs, active along the coast away from 

channel traffic, and purse seiners. Aquaculture has been a mainstay industry in the area, with 

salmon being the principal fish grown and harvested. The state-controlled leases for these 

facilities are generally along the waterway in shallower water than that transited by deep-draft 

vessels. Reportedly, on any given day there are approximately 20 small commercial draggers 

and lobster boats working in the inlets and coves. The regional pilots have estimated that about 

20 fishing vessels operate out of the U.S. side, and over 300 licensed fishing vessels from the 

Canadian side seasonally, but not necessarily all at the same time.

Primarily, the fish catch is lobster and herring, with limited amounts of scallops and other 

species. There are some shellfish (soft-shell clam) nurseries along the transit route; however, 

these areas are well inshore where manual harvesting of the clams is accomplished using hand 

rakes. The shorelines along most of Head Harbour Passage, Friar Roads, and Western Passage 

are steep and rocky, offering little habitat for the soft-shell clam. The majority of the remaining 

area that would provide the necessary habitat is adversely affected by the “red tide,” a “bloom” 

of damaging marine microorganisms; only a few of the coves/mud flats are actually open to 

shellfish harvesting. Scallops are harvested commercially by draggers, primarily in Cobscook 

Bay and South Bay, which are south and west of the transit route and proposed facility site.

The 2012 Maine-wide landed values for lobster was $521.5 million. Lobster landings along the 

Maine coast have, with only a few exceptions, generally risen since the late 1980s with 

126 million pounds in 2012, of which 21 million pounds (16.7 percent) were landed in 

Washington County (Maine DMR 2012). Most lobsters landed in Washington County are 

 21 There are no official Maine state lobster or herring landing records specifically for Passamaquoddy Bay. The 

Canada Department of Fisheries and Oceans does not separate Passamaquoddy Bay catch data in its New 

Brunswick/Bay of Fundy area reporting, either for lobster or herring. Downeast LNG therefore focused on the 

Maine data that includes a breakdown to the county level for lobsters. Mr. Dave Libby, Marine Resources Scientist 

at the Maine Department of Marine Resources, assisted in providing an historical synopsis of the herring industry. 

Downeast collected additional data by interviewing local fishermen. 
4-219 4.8 – Socioeconomics

caught along and offshore of the outer coast, with substantially fewer traps set inside of West 

Quoddy Point in Cobscook Bay, Western Passage, and Passamaquoddy Bay, due in large part to 

the strong tidal currents, which can present difficulties in setting and hauling traps. The reported 

current landed value of $10,000 for lobsters (roughly 2,000 to 3,000 lbs.) caught in the vicinity 

of Mill Cove represents a tiny fraction of the county’s total.

The herring fishery is the most important pelagic fishery resource in Maine. Harvest numbers 

for the years provided by the Mill Cove weir owner are generally consistent with those posted by 

the Maine DMR. Herring canneries have all but disappeared in Maine, but continue to operate 

on Passamaquoddy Bay in New Brunswick, Canada. In comparison to the proposed project 

vicinity data, the 2012 Maine-wide landed values were $14.5 million for herring (Maine DMR 

2012). In Maine, herring catch data is only reported on a statewide basis (Libby 2006; Maine 

Commercial Marine Fisheries 2006).

According to the Maine DMR, farm-raised finfish harvest in Maine yielded 24.4 million pounds 

of Atlantic Salmon with a value of $73.6 million in 2010. The harvest totals vary greatly from 

year to year, with, for example, 11.6 million pounds and $23.2 million in 2005, 36 million 

pounds and $79 million in 2000, 22 million pounds and $56.3 million in 1995 (Maine DMR 

2013). As of spring 2013, there were 26 active finfish aquaculture leases in Maine, 13 of which

are in the Cobscook Bay area. There are four salmon aquaculture sites belonging to Cooke 

Aquaculture on the Maine side of the border in the vicinity of Eastport near the transit route to 

the Downeast LNG Project pier. All four sites are north of the Eastport breakwater and Dog’s 

Head. In New Brunswick, there are eight marine farms near the LNG marine traffic route.

Aquaculture activities directly account for more than 3,000 full-time jobs (25% of the workforce)

in New Brunswick’s Passamaquoddy Bay region. Total direct employment wages, salaries, and 

benefits expenditures are estimated at $47 million. Aquaculture supports an estimated 2,900 jobs 

with a total payroll of $46 million in related supply and service industries such as boat building, 

net and cage manufacturing, and machine shops. The island of Grand Manan alone has 

approximately 240 direct and indirect full time, year round jobs related to the salmon farming 

industry. A 30 percent growth in aquaculture employment is projected to occur on the island of 

Grand Manan over the next few years, resulting in 73 new jobs and an additional $1.3 million in 

wages. New Brunswick collects more than $4.5 million in tax revenues from the farming 

industry on Grand Manan each year (Boucher 2013).

4.8.2.5.1 Waterway for LNG Marine Traffic

Downeast has proposed two transit routes for LNG vessels to and from the proposed LNG 

terminal. LNG vessels bound for Passamaquoddy Bay can either (1) enter the Gulf of Maine and 

transit up the Grand Manan Channel on the westerly side of Grand Manan Island to Head 

Harbour Passage or (2) enter the Grand Manan Basin and transit up the Bay of Fundy VTS on 

the easterly side of Grand Manan Island. According to the WSR, either route is acceptable to the 

Coast Guard. Safety and security zones would be established around transiting LNG tankers. 

Local fishing vessels operate within set seasons but are unable to plan in advance when they 

would be within the proposed LNG tanker route because the fishermen are opportunistic in that 

their use of the waterway is influenced by weather and the location of fish stocks. Particularly in 

areas of high current like Head Harbour Passage and the Grand Manan Channel, fishing typically 

occurs at slack tide when tankers would also travel though the waterway (Boucher 2013). 

Consultations with local fishermen conducted by Downeast indicate that in general fishermen try 
4.8 – Socioeconomics 4-220

to avoid placing fishing gear directly in designated shipping lanes in order to prevent loss of their 

equipment. However, because there is no designated shipping lane within the Grand Manan 

Channel or Western Passage, it is likely that LNG tankers could interact with fishing gear along 

these routes, causing lobster or crab traps and lines to become entangled and damaged by passing 

vessels, causing fishermen to lose gear and income and inadvertently killing lobsters and other 

species. Lost lobster and crab gear and halibut longline gear also pose an entanglement danger 

to whales (Boucher 2013). 

Downeast has developed a comprehensive compensation plan to address any potential loss of 

fishing equipment or income as a result of unavoidable impacts by Downeast LNG vessels. This 

Fishermen’s Communication, Coordination, and Compensation Plan includes replacement cost 

payment for traps or gear loss, plans to maintain a stock of traps and gear for immediate 

replacement of lost or damaged equipment, coordination with local suppliers to ensure adequate 

stocks of equipment, and coordination with Maine DMR and lobstermen to ensure tag 

replacement, if necessary. Downeast intends to implement the following measures to avoid 

impacts on fishing equipment: (1) During the peak fishing season (June-July, SeptemberOctober), as few as three vessels per month would transit the area; (2) Downeast has proposed 

transit routes that, subject to the discretion of the pilot and vessel captain, would avoid lobster 

waters during this peak season, reflecting input from several lobstermen; (3) Downeast would 

implement a “Look Ahead” lobster trap survey before and after each LNG vessel transit; and (4) 

Advance mariner advisories would publish LNG transit dates and times. Downeast consulted 

with individual members of the Cobscook Bay Fishermen’s Association, the Campobello

Fishermen’s Association, and other sources to develop this Communication, Coordination, and 

Compensation Plan to reduce adverse impacts on commercial fishing, which applies to both U.S. 

and Canadian fisheries that occur within the waterway from the pilot boarding area in the 

vicinity of East Quoddy Head to the LNG terminal.

Downeast contracted with Dr. Porter Hoagland and Dr. Di Jin, who are associated with the 

Marine Policy Center of the Woods Hole Oceanographic Institution, to independently assess the 

potential economic impact on lobstering that might be associated with the proposed facility. 

Based on conservative assumptions (favoring the lobster fishery), Hoagland and Jin concluded 

that significant economic impacts from LNG vessel transits would be unlikely. Regardless, 

Downeast would continue discussions with lobstermen as well as fishermen to finalize any 

potential compensation and mitigation planning measures that may be appropriate. We have 

included a recommendation in section 4.5.2.2 for Downeast to continue consultation with NOAA 

Fisheries, Maine DMR, and other appropriate agencies to finalize its Fishermen Communication, 

Coordination, and Compensation Plan.

There is no indication that the LNG project would affect any lobster catch results in Canada, as 

there is little if any lobstering along the LNG vessel route in the waters of Head Harbour 

Passage. There are no salmon aquaculture pens directly within the LNG marine traffic route; 

however, boats servicing the aquaculture sites use the same waterway as the proposed LNG 

vessel transit route. 

4.8.2.5.2 LNG Terminal

Construction activities associated with the pier would last approximately 20 months and include 

the installation of the pier structure support piles and surface platforms. Noise from pile driving 

associated with the pier construction could discourage recreational fishing in the immediate 
4-221 4.8 – Socioeconomics

vicinity. Given the low use of the area for such purposes and the large amount of alternative 

areas for recreational fishing, this impact is expected to be insignificant. 

There would be little if any perceptible impact on estuaries or lobster breeding grounds in Mill 

Cove or at other locations as a result of the pier construction. Potential effects to lobster 

populations and habitat are discussed in section 4.5 of this EIS. 

The proposed project would not have a significant adverse impact on the lobster fisheries. 

However, the two residents of Robbinston who are reported to be the primary lobstermen for this 

area may be potentially adversely affected due to the construction and operation of the project 

pier. It is uncertain if the lobstermen could continue to lay traps and recover them without line 

entanglement around the pier. Downeast has developed a Fishermen Communication, 

Coordination, and Compensation Plan to address impacts on lobster gear that may result with the 

implementation of its LNG project. This would not affect the area’s overall fishery income, 

since these lobsters could be caught in other nearby areas. Downeast in cooperation with the 

Maine DMR has met with leading representatives of the local lobster fishery to further define 

and detail the lobstermen’s key concerns. This information would be used in Downeast’s 

ongoing effort to update and revise the original Fishermen Communication, Coordination, and 

Compensation Plan.

There is very limited fishing in the pier area that would be affected. However, the existing Mill 

Cove weir fishing practices would be directly affected by noise, lighting, and other activities 

during the construction and operation of the project pier, which would bisect the area used by the 

weir fishermen to drive fish into the weir and eliminate the use of the weir during the project life. 

While there are over 100 herring weir locations along the coast of Maine, the loss of use of the 

weir system in Mill Cove would have a direct economic impact upon the weir owners. At 

current value and productivity, the annual economic loss from non-use of the weirs would equal 

roughly $9,000 per year, although the area’s overall fishery income may not be affected, as the 

herring may be caught in other area weirs beyond Mill Cove. The Mill Cove weirs have 

operated intermittently and have been of minimal value in the last decade. Downeast has 

negotiated an agreement with the weir owner to compensate for the losses resulting from the 

operations of the LNG facilities. No other fishing weirs would be affected by project operations. 

Revisions to the Fishermen Communication, Coordination, and Compensation Plan are ongoing, 

and we have recommended that Downeast file the final Plan with the Commission prior to 

operation of the LNG terminal.

Shoreline fishing and clamming from the immediate vicinity of the LNG terminal site may be 

prohibited when an LNG vessel is docked based on the 500-yard fixed safety and security zone 

that could be established around the moored vessel. It has not been determined if a

safety/security zone would be established around the pier when an LNG vessel is not present. 

According to local community members and observations during the course of Downeast studies 

of the area, there is no shoreline fishing along south Mill Cove or its vicinity, and very little 

clamming activity. The vast majority of clammers observed in Mill Cove were digging the north 

and central Mill Cove muds. This is likely due to the fact that the tidal substrate coincident with 

clams is not predominant at the shoreline area of the Downeast LNG Project pier. While the 

exact area of prohibited activities near the project pier has not yet been determined, it would be 

included by Downeast in its Operations and Emergency Manuals and Facility Security Plan. In 

accordance with 33 CFR Part 127.019, Downeast must submit two copies of the Operations and 

Emergency Manual to the Coast Guard COTP Sector Northern New England for review and 
4.8 – Socioeconomics 4-222

approval at least 30 days before transferring. Furthermore, in accordance with 33 CFR Part 

105.410, Downeast must submit the Facility Security Plan to the Coast Guard COTP Sector 

Northern New England at least 60 days in advance. This is reiterated in section 4.6, Risk 

Mitigation Measures, of the Coast Guard’s WSR (Appendix B). The prohibition of shoreline 

fishing or clamming in the less active immediate vicinity of the project’s pier abutment with the 

shore is not anticipated to be a significant adverse impact.

4.8.2.5.3 Sendout Pipeline

Construction of the sendout pipeline would have minimal effects to commercial and recreational 

fishing. Any disruption of fishing activity along inland streams during pipeline construction 

would be very localized and short-term. Operation of the pipeline would have no impacts on 

fishing. 

4.8.2.6 Agricultural Industries

Washington County is a predominately rural area, with substantial agricultural and forestry 

resources. 

4.8.2.6.1 LNG Terminal

There are no agricultural lands in the immediate vicinity of the LNG terminal site; therefore, no 

agricultural lands would be affected by the construction and operation of the LNG terminal.

4.8.2.6.2 Sendout Pipeline

Construction of the sendout pipeline would impact about 2.1 acres of agricultural land, with 

about 1.3 acres to be included in the permanent pipeline right-of-way. Agricultural uses would 

be impacted during construction, but would be allowed to continue following construction. Due 

to the temporary and short-term nature of impacts on agricultural uses, it is expected that the 

impact on the agricultural industry would be minimal. Construction and operation of the sendout 

pipeline could result in long-term impacts on forest areas, as a permanent right-of-way would be 

cleared and not allowed to revert to forest or be used for timber production during the pipeline’s 

operational life (see section 4.7 of this EIS). Compensation for the temporary or permanent loss 

of any timber production would be addressed during easement negotiations between Downeast 

and affected landowners. Because landowners would be compensated for any losses that might 

result, economic effects would be insignificant. 

4.8.3 Housing 

There were 23,001 housing units in Washington County in 2010; over 11 percent were mobile 

homes (USCB 2010). Of the total housing units, 14,302 (62.2 percent) were occupied and 8,699

(37.8 percent) were vacant. Of the vacant housing units, 6,329 (72.8 percent) were for seasonal, 

recreational, or occasional use, resulting in 2,370 units classified as year-round housing. The 

median value for owner-occupied units was $68,700. The median gross monthly rent for renteroccupied units was $419. In addition to the housing stock, there are 23 hotels/motels in 

Washington County (Podunk County Profiles 2006).

The Town of Robbinston had 354 housing units at an average density of 12.6 per square mile. 

Of these units, 238 (67.2 percent) were reportedly occupied (57 percent owner-occupied and 

10.2 percent renter-occupied). Robbinston had a higher percentage of owner-occupied housing 

units than Washington County (46.9 percent) and the State of Maine (55.1 percent). Twenty-
4-223 4.8 – Socioeconomics

four percent of the housing units were for seasonal, recreational, or occasional use. The 

proportion of housing units that are for these uses is higher in Robbinston than in the state as a 

whole (16.4 percent). 

The median value for owner-occupied units in the Town of Robbinston was $129,200. This is 

comparable to the median home value in Washington County ($102,300) and the state as a whole 

($176,200). In the Town of Robbinston 14.6 percent of the owner-occupied housing units were 

valued at less than $50,000, and 28.6 percent were valued between $50,000 and $100,000. Only 

10 percent of these homes were valued over $500,000. The median gross monthly rent for 

renter-occupied units was $545, higher than the county ($496) but lower than the state ($707).

Based on a summer 2006 field survey and review of aerial photographs, there were 

approximately 50 houses within a 1-mile radius of the project entrance, primarily along 

U.S. Route 1, Ridge Road, and in the Mill Cove area north of the site. 

The 2010 census reported that Robbinston had 116 vacant houses and a vacancy rate of 

32.8 percent, higher than the state and higher than the county. Table 4.8.3-1 provides total 

housing unit data for the project area.

TABLE 4.8.3-1

Number and Density of Housing Units in the Project Area

Community Number of Housing Units Density of Housing Units

(Units per Square Mile)

Robbinston 354 12.6

Alexander 399 9.9

Baileyville 875 23.6

Baring Plantation 141 6.7

Calais 1,737 50.6

Charlotte 256 8.3

Cooper 167 5.4

Eastport 1,083 298.3

Meddybemps 182 13.9

Pembroke 531 19.4

Perry 551 18.8

Source: USCB 2010

4.8.3.1 LNG Terminal 

Construction and operation of the terminal would have a minimal impact on local housing 

markets through the influx of workers, because nearly all of the workers hired are anticipated to 

live in homes within commuting distance or other available accommodations, such as local 

hotels, motels, cabins, and campgrounds. The use of these alternative accommodations would 

assist the project area in moderating seasonal fluctuations in normal occupancy (i.e., high 

summer occupancy, low winter occupancy). While there are discrepancies between census data 

and local realtor estimates, it is expected that non-local workers would be able to find temporary 

housing in the local area.

There are no residences or businesses on the terminal site and hence no displacement would 

occur as a result of construction or operation of the facility. During the operations phase, the 

terminal facilities would employ 78 workers, many of whom are expected to be hired from 

among local residents. Any employees relocating to the area would be able to find permanent 
4.8 – Socioeconomics 4-224

housing in the area, either in existing housing or in new housing being developed independent of 

the project. Even assuming conservatively that all workers relocated to the area with their 

families, the impact would be insignificant in the project area, which has sufficient available 

housing units to support the newcomers. 

4.8.3.2 Sendout Pipeline

Construction of the sendout pipeline is expected to last approximately nine months. Most shortterm construction workers who do not live in a project area typically prefer temporary quarters 

such as hotels, motels, rental housing, or rented rooms from local residents, while the remainder 

may utilize campsites and recreational vehicle sites. Impacts on the local housing market would 

be insignificant.

During operation of the sendout pipeline, negligible impacts on local housing markets would be 

expected, since only four permanent staff would be required to manage its operation and 

maintenance. No homes or businesses would be displaced by construction of the pipeline. 

4.8.4 Tax Revenues 

Washington County’s approved 2013 budget was $5,792,431 (Down East 2013, Walsh 2012). 

Local taxes are collected by the Town of Robbinston. Local taxes include a Washington County 

tax and a school district tax. For 2010, the property taxation rate in Robbinston was 

11.05 percent per $1,000 of assessed value (State of Maine 2010). 

There would be no direct impact on tax revenues from the LNG marine traffic along the 

waterway.

4.8.4.1 LNG Terminal

LNG terminal activities would affect the state government through increased corporate and 

income tax revenues and additional sales tax receipts. The county and municipalities would 

receive increased property taxes.

The University of Maine study included a fiscal impact analysis based on Maine’s current tax 

and educational spending system, using data from 2004 and 2005. The study found that those 

workers directly and indirectly associated with construction and tugboat manufacturing would 

pay an estimated $1.4 million in state personal income taxes per year in each of three years of 

pre-operations activities. The direct and indirect economic activity, including business and 

household spending by those associated with project construction and tugboat manufacturing, 

would generate an estimated $1.3 million in sales taxes during each of the three years that 

construction is taking place (University of Maine 2005). 

Based on Maine’s 2005 maximum state corporate income tax rate of 8.93 percent and 

Downeast’s anticipated earnings, Downeast would contribute approximately $625,000 to 

$1.8 million in corporate income taxes annually (University of Maine 2005). Workers directly 

and indirectly supported by the Downeast LNG Project would pay $539,268 in state personal 

income taxes annually over the lifecycle of the terminal, expected to be 30 years or longer. 

Finally, the economic activity associated with operations (e.g., business and household spending 

by those directly and indirectly associated with facility operation) would generate an estimated 

$246,282 in state sales tax revenue per year.
4-225 4.8 – Socioeconomics

The University of Maine study found that the presence of a $400 million LNG terminal in 

Robbinston would lower the Town of Robbinston’s full value tax rate by 69.1 percent. The 

study estimated that Downeast would pay $1.2 million in local property taxes on an annual basis 

once the terminal is in operation, amounting to 92.1 percent of the total property taxes paid in the 

Town of Robbinston. 

Construction and operation of the project would also affect municipal expenditures and the size 

of the local tax base. In addition to an anticipated increase in the local tax base, several other 

fiscal impacts can be anticipated relative to local government expenditures and revenues. These 

impacts include changes in Robbinston’s county tax obligations and possible reductions in 

educational subsidies and funding from revenue sharing (University of Maine 2005). 

The anticipated construction cost of the facility is $400 million. At this value, the terminal 

would increase the 2006 full state value of real and personal property from $33.05 million to 

$433.05 million, leading to a decrease in the local full value property tax rate (University of 

Maine 2005). This increase in the local tax base would increase the amount of taxes paid by 

Robbinston to the Washington County government. Robbinston has a 2005 state valuation of 

$30.95 million, which results in obligation to pay $55,097 to Washington County. The 

Downeast LNG Project could lead to a $400 million increase in total state valuation, resulting in 

a decrease in Washington County’s full state value tax rate from 0.00178 to 0.00153. According 

to the University of Maine 2005 study, Robbinston’s tax obligation to Washington County would 

be expected to increase by $602,136 to $657,233 as a result of operation.

An increase in the Robbinston tax base may also result in reduction in the amount of educational 

subsidies Robbinston receives from the state, as the subsidies are linked to Robbinston’s full 

state valuation. A $400 million increase in Robbinston’s state valuation could decrease the 

educational subsidy from the currently anticipated value of $454,603 (estimated for 2005-2006 

school year) to $95,293, a decrease of $359,310 if the project were operational in 2006 

(University of Maine 2005).

The amount of funding received by Robbinston through state and municipal revenue sharing 

could also be affected by operation of the LNG facility. The $400 million increase to the full 

state value of real and personal property and other estimated changes to local government 

expenditures and revenues would lower Robbinston’s allotment of the revenue sharing 

distribution by an estimated $19,611, from $27,295 to $7,684 (University of Maine 2005).

The fiscal impacts described above could increase Robbinston’s total expenditures from 

$302,944 to approximately $1.3 million. Combined with a $400 million increase in the full state 

value of real and personal property, this would lead to a reduction in the full state value property 

tax rate from 0.0097 to 0.0030, assuming no new development and no increase in expenditures 

on local public services. This rate reduction would benefit Robbinston homeowners and 

businesses by lowering their property taxes. Operation of the LNG facility would obligate the 

facility to pay $1.2 million in annual local property taxes to Robbinston, equivalent to 

approximately 92 percent of the total property taxes paid in the municipality (University of 

Maine 2005). The reduction in revenues paid to the county and town by the state would also 

result in a beneficial impact on Maine taxpayers outside of Washington County.

In the Host Community Benefits Agreement, Downeast has agreed to pay its property tax 

obligation to the town based upon the assessed (fair market value) of the project, without 
4.8 – Socioeconomics 4-226

deduction for plant depreciation or amortization, as calculated by the town in accordance with 

applicable laws. In order to secure the payment obligation, Downeast has agreed to obtain and 

maintain in effect a bond, letter of credit or other form of security in favor of the town covering 

three full years of estimated property tax obligations. 

Under the Host Community Benefits Agreement, Downeast has also agreed to establish a 

community development fund exclusively in the name of the town, to which it would initially 

contribute the sum of $100,000 per calendar year (increased to annual payment of $1.2 million 

per calendar year at start of operations). The fund would be administered by a group of town 

residents, specifically responsible for the management of such funds. Downeast has placed no 

restrictions on the use of the Community Development Fund. 

Under the Agreement, Downeast has also agreed to reimburse the town for the reasonable 

expense of hiring a part-time clerk or other qualified official to ensure that the project complies 

with all applicable licenses, permits, approvals, laws and regulations. Downeast has further 

agreed to put into place and to maintain a form of financial security in an amount sufficient to 

fund the estimated costs of decommissioning and dismantling facilities at the conclusion of its 

scheduled operational life in accordance with the requirements of applicable federal and state 

laws, regulations, licenses, permits and approvals. The amount of the financial security 

instrument would be revised no less frequently than every five years in order to keep pace with 

changes in the estimated costs of decommissioning and dismantling the project. 

4.8.4.2 Sendout Pipeline

Construction and operation of the sendout pipeline would also generate county and town tax 

revenues. Based on preliminary information and review of tax revenues generated by the 

existing M&NE pipeline, as well as the Portland Pipeline (est. 1999, used for Maine state tax 

calculations), the following analyses have been made to develop tax revenue estimations. It has 

been assumed for this assessment that the tax valuation of the pipeline would be calculated in a 

manner similar to previous tax formulations used for gas pipelines in unorganized territories of 

Maine, i.e., that the valuation used for the Downeast sendout pipeline would be based on a 

construction cost of approximately $1.0 million to $1.2 million per mile. The pipeline distance is 

approximately 29.8 miles. 

At the lower value ($1.0 million/mile), the total real property tax valuation would equal 

$29.5 million, while the higher value ($1.2 million/mile) yields an estimate of $35.4 million. 

This value would be taxed in full by each town in Year 1. The valuation would then be 

depreciated 2.0 percent per year for Years 2-5, and then 1.5 percent per year for Year 6 and 

beyond. Estimates based on the more conservative values (at $1 million per mile) are shown in 

table 4.8.4.2-1.22

In addition to the individual townships, Washington County would benefit from the tax revenues 

generated by the sendout pipeline. However, the county’s tax revenue would be dependent on 

each town’s respective mill rate differential after the construction of the sendout pipeline has 

been completed. Since this is not known at present, an amount equal to 10 percent of each 

town’s tax revenue from the sendout pipeline has been assigned to Washington County for 

general estimation purposes. As such, the Year 1 tax revenues generated by the sendout pipeline 

 22 Note: The University of Maine Study used the higher value, $1.2 million per mile, in its estimations.
4-227 4.8 – Socioeconomics

for Washington County would approximate $56,276 [at the more conservative estimate of 

$1.0 million per mile of pipeline]. The total annual amount would be reduced each year 

thereafter due to depreciation.

TABLE 4.8.4.2-1

Estimated Property Tax Revenues from Sendout Pipeline for Year 1

Township Pipeline Miles Total Value Millage Rate Tax Revenue

Robbinston 4.7 $ 4,700,000 0.0136 $ 63,920

Baileyville 10.7 10,700,000 0.0150 $160,500

Baring 2.7 2,700,000 0.0162 43,740

Calais 10.5 10,500,000 0.0260 $273,000

Princeton 1.2 1,200,000 0.0180 21,600

Total 29.8 $29,800,000 $562,760

Washington County

(estimated to be 10% of total revenues) $56,276

The State of Maine would not receive direct tax revenues generated by the sendout pipeline’s 

real property value. However, as noted earlier, the reduction in state payments to the county and 

municipalities would result in a beneficial impact on Maine taxpayers and residents outside of 

Washington County. 

4.8.5 Public Services and Infrastructure 

4.8.5.1 Schools 

The 11 communities of eastern Washington County (including Robbinston) have a total of 

8 public elementary schools and 3 high schools within 3 school districts. Information regarding 

student enrollment at area schools is shown in table 4.8.5.1-1. The excess capacities in area 

schools (except for Perry) reflect declining population trends over past decades.

Post secondary schools located in eastern Washington County include the University of Maine–

Machias and Washington County Community College (Calais and Eastport campuses).

4.8.5.1.1 LNG Terminal

Area schools could see a small increase in enrollments as a result of the influx of construction 

workers. However, this would not be a significant impact on local schools for several reasons. 

First, except for Perry’s elementary school, all schools have sufficient capacity to absorb sizable 

increases in enrollment. Second, it is likely that new pupils would be distributed among several 

schools, rather than concentrated in one or two facilities. Finally, it is assumed that many of the 

construction workers would be area residents, so their children would already be in local schools. 

Therefore, adverse impacts to area schools would be minimal.
4.8 – Socioeconomics 4-228

TABLE 4.8.5.1-1

Enrollment and Capacity in Project Area Schools

School Enrollment Capacity

Enrollment 

as % of 

Capacity

Source

Elementary (Grade) Schools

Robbinston 51 100 15% Maine Department of Education Data Center; 

Public School Review 2013

Calais 284 384 74% Perkins, 2006; Public School Review 2013

Charlotte 41 75 54.7% Lingley, 2006; Public School Review 2013

Eastport 85 300 28.3% Eastport Elementary School Secretary, 2006; 

Public School Review 2013

Pembroke 101 150 67.3% Pembroke Elementary School Secretary, 2006; 

Public School Review 2013

Perry 107 120 89.2% Smith, 2006; Public School Review 2013

High Schools

Calais 367 450 81.6% Underwood, 2006; Public School Review 2013

Shead, Eastport 119 250 47.6% Stanhope, V., 2006; Public School Review 2013

Washington Academy, Machias 

(private)

390 520 75% McBrine, 2006 ; Private School Review 2013

Under the Host Community Benefits Agreement, Downeast would fund the construction of a 

new elementary school within the town (at an estimated cost, including land acquisition, of 

$5 million) to replace the existing school. The draft Host Community Benefits Agreement 

anticipates that the school would be operational by the start of project operations and be designed 

at a size that meets the reasonable projected growth in school population.

4.8.5.1.2 Sendout Pipeline

As discussed above, few families are expected to relocate to the project area during construction 

of the pipeline. Therefore, no impacts on existing public services and infrastructure are 

anticipated from construction and operation of the pipeline. 

4.8.5.2 Police, Fire, and Emergency Services 

The Town of Robbinston has no police force. Depending on the circumstances, law enforcement 

services are provided by either the Washington County Sheriff’s Office or the Maine State 

Police. The Sheriff’s Office has six full-time patrol offices assigned to northern, central, and 

western divisions of the county. The department also has two officers contracted to the Town of 

Lubec and one to the Town of Jonesport, along with a K-9 unit and administrative staff 

(Washington County Sheriff’s Office Website 2008). Troop J of the Maine State Police has a 

total of 25 troopers in Washington County. Tactical, Air, Dive, Hostage, and Bomb Teams from 

other areas are also available in emergencies (Snedeker 2006).

Fire emergencies in the Downeast LNG Project area are responded to by a collaboration of fire 

departments from the towns of Robbinston, Charlotte, Perry, Pleasant Point, Eastport, and the 

City of Calais. Safety and emergency response are discussed in section 4.12 of this EIS.
4-229 4.8 – Socioeconomics

The majority of local, on-site public and private emergency response services within the 

immediate area are predicated on ‘everyday’ emergent situations based on a largely rural 

population and risk model. In the event of a large-scale crisis or catastrophe, the implementation 

of enhanced response capabilities, such as bomb squads, hazardous materials response, marine 

firefighting/salvage operations, and major medical assistance, etc., would require significant 

coordination among the major emergency organizations. 

4.8.5.2.1 LNG Terminal

The influx of workers to construct the LNG facility could increase the costs of public safety 

services, and facility operations could place demands exceeding the capacity of the existing 

infrastructure. Under the Host Community Benefits Agreement, Downeast has agreed to pay the 

town for all capital costs (estimated at $500,000) associated with the maintenance, improvement 

or expansion of the firehouse facility and the fire equipment of the town arising out of increased 

need, due to the operation of the Downeast LNG Project. The annual operating expenses of the 

town’s fire and emergency services would be included in the town budget.

The development of an ERP, pursuant to Section 311 of the EPAct of 2005, is one of the risk 

mitigation measures recommended by the Coast Guard’s WSR. In addition, the EPAct calls for 

a cost-sharing plan identifying the mechanisms for funding all project-specific security costs and 

safety/emergency management costs that would be imposed on state and local agencies. This 

cost-sharing plan must specify what the LNG terminal operator would provide to cover the cost 

of state and local resources required to manage the security of the terminal and vessels. The ERP 

would be developed through a transparent, public process that actively involves the Coast Guard, 

appropriate agencies, and key officials of state and local governments.

4.8.5.2.2 Sendout Pipeline

There would be minimal impacts on local public safety services as a result of the construction 

and operation of the proposed sendout pipeline. 

4.8.5.3 Medical Services

Two medical facilities serve the proposed Downeast LNG Project area, the Calais Regional 

Hospital, located approximately 15 miles from the terminal site, and the Downeast Community 

Hospital in Machias, located approximately 36 miles from the terminal site. As discussed in 

section 4.8.5.2, a large-scale catastrophe in this remote, rural area would require significant 

coordination among the major emergency organizations. The potential impacts on medical 

services from a large scale emergency are discussed below. Medical services would not be 

affected by normal LNG vessel traffic.

4.8.5.3.1 LNG Terminal 

Workers engaged in construction activities for the terminal facilities would likely increase 

demand for medical services in the project area. However, local hospitals and providers have 

adequate facilities to handle most emergencies and routine care. In the unlikely event of a largescale emergency, hospitals and emergency services in the region could address any needs 

through coordination. Therefore, impacts on local medical facilities would be insignificant.
4.8 – Socioeconomics 4-230

Operations personnel and their families would constitute a very small increase in the area’s 

population. Impacts on local medical services would be similarly insignificant but probably 

smaller than those under the construction phase.

4.8.5.3.2 Sendout Pipeline

Pipeline construction workers could increase demand for medical services, but the local facilities 

are adequate to handle such emergencies and routine care. Impacts on local facilities would be 

insignificant. 

4.8.6 Environmental Justice 

Executive Order 12898, Federal Actions to Address Environmental Justice in Minority 

Populations and Low-Income Populations, was signed by the President in 1994. It requires that 

each federal agency address the potential for disproportionately high and adverse health or 

environmental effects of its programs, policies, and activities on minority populations and lowincome populations. An environmental justice area is defined as an area where the community’s 

minority population is equal to or greater than 50 percent of the community population and/or a 

community in which the percentage of persons living below the poverty level is higher than the 

county average, based on poverty statistics published by the USCB. If the proposed action 

would result in significant adverse effects to minority or low-income populations or Native 

American tribes, the NEPA analysis should address those impacts as part of the alternatives 

analysis and identify appropriate mitigation measures to address the effects.

Each federal agency must also ensure that public documents, notices, and hearings are readily 

available and accessible to the public. As part of the preparation of this EIS, the NEPA review 

process must provide opportunities for effective community participation and involve 

consultation with affected communities. Consultation with Native American groups, including 

the Passamaquoddy tribe, and evaluation of measures to address impacts on that community is 

described in section 4.10 of this EIS.

This section evaluates the construction and operation of the proposed project to determine if it 

would have a disproportionately adverse impact on minority or low-income populations. The 

assessment follows the methodology in EPA’s Final Guidance for Incorporating Environmental 

Justice Concerns in EPA’s NEPA Compliance Analyses (April 1998). 

As noted earlier, the socioeconomic impact area for the proposed project is Washington County. 

Table 4.8.6-1 provides data on minority population and income for all communities affected by 

the proposed project, along with data on comparison areas.23

In 1999, 19.9 percent of the county’s population lived below poverty level, while the state of 

Maine had a poverty rate of 12.6 percent and the United States, 13.8 percent. As of 2010, the 

county’s population was 92.1 percent white (Caucasian) and 4.9 percent Native American, with 

other groups comprising only 3.0 percent of the total. Hispanics, who can be of any race, were 

1.4 percent of total residents (USCB 2010).

 23 Data from the 2000 Census are the latest reliable and consistent data regarding the ethnic composition and poverty 

status of the population, especially for sub-county divisions such as towns or census tracts. Later estimates from 

varying sources may use different methodologies and do not provide accurate comparisons among areas.
4-231 4.8 – Socioeconomics

TABLE 4.8.6-1

Ethnic and Poverty Statistics, Proposed Project Area and Comparison Areas

Area

Percent of Total Population

White Black a/ Native 

American b/

Other 

Minorities c/ Hispanic d/ Per Capita Income

% Below 

Poverty

United States 72.4 12.6 0.9 14.1 16.3 $27,334 13.8

Maine 95.2 1.2 0.6 2.9 1.3 $25,385 12.6

Washington County 92.1 0.4 4.9 2.6 1.4 $19,401 19.8

Town of Robbinston 98.6 0.2 2.3 1.6 0.3 $18,112 21.5

Alexander 98.2 0.0 1.0 0.8 1.2 $31,631 2.3

Baileyville 98.1 0.7 0.8 3.8 0.7 $25,121 9.2

Baring Plantation 97.2 0.0 0.0 2.8 1.2 $17,359 24.4

Calais 95.5 0.5 1.3 2.7 1.4 $22,127 16.9

Charlotte 94.0 0.0 3.0 3.0 0.9 $21,909 8.0

Cooper 98.1 0.6 1.3 0.0 0.6 $29,316 6.9

Eastport 92.0 0.8 3.6 3.7 0.9 $21,360 19.4

Meddybemps 99.4 0.0 0.0 0.6 0.0 $14,840 23.5

Pembroke 94.9 0.1 1.3 3.7 1.0 $18,303 19.1

Perry 85.5 0.2 10.5 5.0 1.0 $15,416 24.6

Pleasant Point Res. e/ 13.1 0.5 81.8 4.0 2.0 $10,863 45.0

a/ Black or African American.

b/ American Indian and Alaska Native. 

c/ Includes Asian; Native Hawaiian or other Pacific Islander; Some Other Race; and Two or More Races.

d/ Hispanic can be of any race.

e/ Pleasant Point Reservation is a separate “Census Place” not included in the statistics for the Town of Perry.

Source: USCB 2000 Census of Population and Housing, Demographic Profiles.

4.8.6.1 LNG Terminal

In the proposed terminal area, the poverty rate in 2010 for the Town of Robbinston was 

21.5 percent, substantially higher than the county and the nation, while the population was more 

than 98 percent white, with a smaller percentage of minorities than the county and comparable to 

most other communities in the project area. The exceptions are the nearby Pleasant Point 

Reservation and the Town of Perry, which are approximately 82 percent and 11 percent Native 

American, respectively. Additionally, on the Pleasant Point Reservation, 45 percent of the 

population lived below the poverty level in 2010. These two communities would therefore be 

classified as environmental justice communities, although they are sufficiently distant from the 

proposed Downeast LNG facility that direct adverse impacts would be highly unlikely. Rather, 

the proposed project would result in a substantial economic benefit to the neighboring 

environmental justice communities through increased job opportunities, income, and tax 

revenues.
4.8 – Socioeconomics 4-232

The EPA and CEQ provide guidance on assessing environmental justice impacts. This guidance

requires that in environmental justice areas, the applicant show, through environmental 

assessments or environmental impact statements, that there would be no significant impacts as a 

result of the project, especially in terms of cumulative impacts from the project combined with 

other sources of pollution in the area that may affect those living there (EPA 1998; CEQ 1997). 

An analysis of environmental resources, such as surface water, groundwater, and noise, found no 

significant impacts on the environmental justice communities as a result of the proposed 

project’s construction or operation. 

Another important requirement in environmental justice areas is to ensure that members of 

populations living in these areas are adequately represented, and that they have an opportunity to 

become involved in development of the proposed project and to express any concerns regarding 

adverse impacts. NEPA requires that all local residents, not just members of environmental 

justice communities, be kept advised of the proposed project and allowed to express any 

concerns. Downeast has held numerous meetings with the local community to explain the 

proposed project and to determine local concerns. In addition, FERC staff held a scoping 

meeting in Robbinston; section 2.0 of this EIS provides details of public scoping meetings and 

community outreach. Section 2.0 also notes that all members of the public, including 

environmental justice community members, were given an opportunity to file comments on the 

draft EIS. Our responses to comments received on the draft EIS are included in Appendix S.

4.8.6.2 Sendout Pipeline

The sendout pipeline would traverse the towns of Alexander, Baileyville, Baring Plantation, 

Calais, Charlotte, Cooper, Eastport, Meddybemps, Pembroke, and Perry. With the exception of 

Perry, as noted above, all of these towns have very small minority populations. The proportion 

of the population living below the poverty level varies from 2.4 percent to 20.7 percent, with 

three communities—Alexander, Baring Plantation, and Pembroke—being slightly higher than 

the county average. These communities could therefore be defined as environmental justice 

communities. However, as stated in section 4.8.4 of this EIS, the sendout pipeline operations 

would substantially increase tax revenues for all of the towns traversed by the pipeline. As a 

result, both the towns and the environmental justice communities affected by the pipeline would 

receive significant long-term economic benefits.

Environmental justice considers disproportionate environmental, health, and cultural impacts on 

environmental justice communities. This EIS analysis found that the pipeline construction and 

operation would result in minimal potential for air quality impacts, contaminated soils and/or 

groundwater, or for other environmental or health impacts that could disproportionately affect 

the local environmental justice communities. Only minimal short-term adverse environmental 

impacts would occur during construction, and there would be negligible long-term impacts from 

the pipeline once it is in operation. There would be no disproportionate adverse environmental 

and human health impacts on low-income or minority communities or Native American groups. 
4-233 4.9 – Transportation and Traffic

4.9 TRANSPORTATION AND TRAFFIC

4.9.1 Land Transportation

The Downeast LNG terminal site is located eastward of U.S. Route 1, on the southern shores of 

Mill Cove in the Town of Robbinston, Maine. U.S. Route 1 is the primary transportation 

corridor in the vicinity of the site, and generally runs parallel to the St. Croix River and 

Passamaquoddy Bay, connecting the City of Calais to the north with the towns of Perry, Pleasant 

Point, Eastport, and Machias to the south. The nearest interstate freeway is I-95, approximately 

100 miles from Robbinston via U.S. Route 9, which is also known locally as Airline Road. 

U.S. Route 9 serves as the primary northeast-southwest connector between the terminal site 

and I-95.

Inland towns are accessible to and from the project site via a number of rural roads that connect 

to U.S. Route 1, including Ridge Road (access to Perry, Pembroke, and Charlotte) and Lake 

Road (access to Perry, Pembroke, and Robbinston).

Access to the terminal site would be directly from U.S. Route 1, consisting of a single, 

combined entrance and exit approximately 0.5 mile south of the intersection with Ridge Road. 

U.S. Route 1 within the vicinity of the proposed terminal was restructured within the past 

15 years and is in excellent condition. Additional resurfacing work along U.S. Route 1 has 

continued in recent years in the Perry area (Maine DOT 2013). Speed limits vary from 35 to 

55 mph. Traffic count surveys conducted along U.S. Route 1 indicate that traffic along the route 

has not increased in recent years. Traffic loading is very seasonal with summer traffic 

representing the highest count period (Stanhope, Earle 2006).

Ridge Road located near the terminal site, would provide access for construction equipment to 

the proposed equipment laydown areas for the terminal construction activity. Ridge Road is 

22 feet wide, and the posted speed limit is 45 mph. Ditches, culverts, and hard-topping are in 

good condition, but the road is narrow with sharp curves in places.

4.9.1.1 LNG Terminal

Work at the terminal site would require the use of approximately 332 workers over the three-year 

construction period. Approximately 75 percent of these workers would be on-site during peak 

construction activities. This equates to an average of 249 workers on-site at any one moment in 

time. 

A project-specific traffic capacity analysis in the area of Robbinston, Maine was performed by 

Downeast in order to: (1) establish the current traffic volumes and roadway level of service; 

(2) identify the construction and operation-related vehicle trips that would be associated with the 

Downeast LNG Project; (3) evaluate future roadway levels of service with the addition of 

construction and facility operational traffic; and (4) make recommendations for ensuring that 

facility-related traffic would not have an unacceptable impact on area roadways (HNTB 2006). 

The study results are reported in terms of Level of Service (LOS), a qualitative measure 

describing operational conditions at a specific traffic location. LOS is based on service measures 

such as delay and length of vehicular queues. Letters designate each level ranging from A to F 

where an LOS of A represents the best operating conditions and an LOS of F represents the 
4.9 – Transportation and Traffic 4-234

worst. At signalized intersections, an LOS of D or higher is desired. At intersections without 

signals, if the LOS classification falls below a D, an evaluation should be made to determine if a 

traffic signal or turning lanes are required.

Traffic impacts associated with construction and operation of the terminal were estimated for 

both material delivery and worker transportation. Each trip would actually count as two endtrips – one to and one from the site. For material delivery trips, approximately 75 material 

deliveries (150 end-trips) would occur per day during peak months. For worker transportation, 

the travel of an average of 249 construction workers would result in almost 500 daily end-trips 

(one trip entering in the morning, one trip leaving in the evening) assuming each worker would 

drive to the construction site each day. However, Downeast proposes to transport workers from 

dispersed off-site parking areas to the import terminal during construction by van and/or bus to 

minimize on-site construction parking requirements and worker trips to the construction site. 

According to the Traffic Study conducted for Downeast, assuming 50 percent are transported in 

a 40-passenger bus, and the remainder transported in 10-passenger vans, approximately 15 peak 

hour and 30 non-peak worker trips are assumed (HNTB 2006). 

Downeast has not identified specific off-site parking areas that would be used during 

construction, but has indicated that these areas would be inactive, existing open fields or 

graveled areas located along U.S. Route 1 near Woodland/Baileyville and Perry/Pembroke. 

Prior to the use of these areas, Downeast would file the location and environmental information 

with FERC staff for review and approval.

According to the Traffic Study conducted for Downeast, during operations, the estimated 

78 employees would generate 99 end-trips during peak hours and 50 non-peak end-trips. This 

estimate assumes 75 percent of the employees would arrive and depart during standard 

morning/evening hours, and an average vehicle occupancy of 1.3, the approximate state average 

for Maine. Based on this level of trip generation, no State of Maine traffic permit is required. 

The traffic analysis concluded that the site driveway, U.S. Route 1, and Ridge Road would 

operate with acceptable LOS levels, given the predicted traffic increases. Other study area 

intersections are also anticipated to operate at acceptable LOS, based on the minimal existing 

volume of traffic (HNTB 2006). 

The traffic analysis also assessed sight distance and crash data, finding that all locations have 

sight distances in excess of the minimum Maine DOT recommended guidelines for safe traffic 

operations, and that there were no high crash locations within the Town of Robbinston. To 

ensure safe ingress and egress of construction and operations traffic, Downeast proposes to 

construct turning lanes on both the north and southbound lanes of U.S. Route 1 at the entrance to 

the terminal site. The construction of these turning lanes would not affect any existing public 

utilities.

Federal siting regulations for LNG facilities under Title 49, CFR, Parts 193.2007 and 193.2059 

have established exclusion zones to ensure adequate separation between members of the public 

and flammable vapor dispersion. These exclusion zones must be legally controlled by the LNG

facility operator or a government agency. Although the 1,600 Btu/hr-ft2 incident flux level for 

the north storage tank (T-201A) located at the terminal site extends beyond the site property and 

onto U.S. Route 1, which is under the legal control of the State of Maine, it would meet the 

requirements specified by Title 49, CFR, Part 193. In the Yukon Pacific LNG Project, the 
4-235 4.9 – Transportation and Traffic

Department of Transportation, Office of Pipeline Safety (OPS) filed comments with the 

Commission dated August 9, 1993 indicating that the need for an LNG operator to demonstrate 

an ability to control public access to property does not apply to transient travel within the 

exclusion zone, including travel offshore. Downeast, therefore, is not required to control the area 

of U.S. Route 1 that falls within the exclusion zone, and hence, the thermal radiation exclusion 

zone for the north tank meets federal code requirements.

Based on the findings discussed above and Downeast’s implementation of the mitigation 

measures discussed below, we believe that construction and operation of the proposed terminal 

would not significantly affect traffic conditions on roads proximal to the site.

4.9.1.2 Sendout Pipeline

An estimated 320 workers would be employed to construct the sendout pipeline, resulting in over 

600 daily end-trips. The pipeline construction crews would be divided into two different 

spreads. Downeast would implement a bus and vanpool system to transport groups of workers 

from the off-site leased parking areas, thus reducing the traffic to 40 peak hour end-trips and 

80 non-peak end-trips. These end-trips would be split between the two pipeline construction 

spreads. Additionally, six to seven pipe delivery trips to the storage areas (see table 2.2.2.1-1) 

are anticipated daily. Only four permanent staff would be required for operation and 

maintenance of the sendout pipeline.

Limited traffic delays may occur at pipeline-roadway crossing locations. We believe that 

pipeline construction would not result in a significant increase in traffic volume, and would not 

adversely affect traffic on area roadways. Downeast has agreed to the mitigation measures 

described below, which would minimize the impacts and ensure safety for construction crews 

and roadway passengers.

In the Traffic Study commissioned by Downeast (HNTB 2006), Downeast has agreed to provide 

a number of traffic mitigations, including:

• provide flaggers as required at driveways to material sites, equipment laydown areas, and 

the intersection of Ridge Road and U.S. Route 1 during peak construction periods to 

safely facilitate the movement of trucks and other construction-related vehicles; 

• perform daily roadway cleaning, which includes a truck cleaning station/services for all 

trucks exiting the terminal, pipeline construction, and material storage sites; 

• mitigate any construction traffic-related impacts on local and state roadways following 

construction, including roadway reconstruction and paving, the provision of turning lanes 

at the facility entrance, and roadway striping and signing; and

• prohibit employee/vendor parking alongside U.S. Route 1 near the terminal site.

The Host Community Benefits Agreement also requires that Downeast pay the cost of repairing 

any material damage to town or state roads during the construction or operation of the Downeast 

LNG Project that is directly attributable to construction or operation. Finally, the Traffic Study 

notes that Downeast would consult with the Maine DOT and the road departments of affected 

communities regarding the need for improvements that might be identified and deemed 

necessary in the future, as well as the mitigation measures identified above.
4.9 – Transportation and Traffic 4-236

4.9.2 Marine Transportation

Downeast has indicated that materials required for construction would be delivered by land, via 

U.S. Route 1. Marine traffic associated with construction of the terminal would be minimal and 

limited to the arrival and departure of construction barges and tugs. With coordination and 

advance notice regarding the construction barges, impacts on fishing vessels, ferries, and other 

marine traffic would be minimal.

Operation of the LNG terminal would result in regular LNG marine traffic in the Bay of Fundy, 

Grand Manan Channel, Western Passage, and Passamaquoddy Bay. An LNG vessel’s transit 

from the sea to the Downeast LNG terminal would follow a circuitous route through Canadian 

waters. This is virtually the same route as currently used by all deep-draft vessels servicing the 

Passamaquoddy Bay port area. Deep-draft vessels bound for the ports of Bayside, New 

Brunswick, or Eastport, Maine, either enter the area via the Gulf of Maine and into Grand Manan 

Channel, or by transiting Grand Manan Basin into the Bay of Fundy. Downeast has proposed 

two transit routes. LNG vessels bound for Passamaquoddy Bay can either (1) enter the Gulf of 

Maine and transit up the Grand Manan Channel on the westerly side of Grand Manan Island to 

Head Harbour Passage or (2) enter the Grand Manan Basin and transit up the Bay of Fundy VTS 

on the easterly side of Grand Manan Island. According to the WSR, either route is acceptable to 

the Coast Guard. Both routes converge offshore in the general vicinity of the entrance to Head 

Harbour Passage, north-northeast of Campobello Island. A typical transit, from the time the 

LNG vessel enters 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. 

Downeast estimates that there would be one vessel every five to seven days in the winter 

(slightly more often than once per week), and one vessel every eight to ten days in the summer 

(or about every week and a half), approximately 60 vessels per year. The WSR recommends that 

three to four tractor tugs accompany each LNG vessel in the waterway and that Coast Guard 

authorized assets, as determined by the COTP, escort the LNG vessel to the terminal. In 

locations where the waterway is narrow, some mariners attempting to travel in the opposite 

direction of an LNG vessel traveling at 10 knots may need to wait up to 18 minutes for the LNG 

vessel to pass before proceeding on its way. The delay would increase up to 36 minutes when 

the LNG vessel is traveling at 5 knots and up to 60 minutes when the LNG vessel is traveling at 

3 knots. For mariners near or upstream of the facility, an additional 60-minute delay may be 

experienced while the LNG vessel is berthed or turned. Other vessels may be allowed to transit 

through the LNG vessel security zones with the specific permission of the COTP determined on 

a case-by-case basis. Mariners and other users of the waterway would receive advance warning 

of an LNG vessel transit and associated waterway restrictions through various established 

communication methods and public service announcements.

A discussion of marine traffic and transportation as they relate to marine safety is included in 

section 4.12 of this EIS. The socioeconomic and environmental justice impacts associated with 

marine traffic are discussed in section 4.8 of this EIS. Large commercial vessels such as LNG 

vessels must coordinate closely with the Coast Guard and other waterway and port authorities in 

the area. This coordination and advance notice of the arrival and departure of LNG vessels, 

along with the implementation of vessel traffic management practices, as recommended by the 

Coast Guard’s WSR, would ensure that other marine traffic, both commercial and recreational, 

would experience insignificant impacts as a result of the LNG vessel movements.
4-237 4.10 – Cultural Resources

4.10 CULTURAL RESOURCES

Section 106 of the NHPA, as amended, requires the FERC to take into account the effect of its 

undertakings (including authorizations under Sections 3 and 7 of the NGA) on historic

properties, and afford the ACHP an opportunity to comment. Downeast, as a non-federal party, 

is assisting the FERC in meeting its obligations under Section 106, providing data, analyses, and 

recommendations in accordance with the ACHP’s implementing regulations at 36 CFR 

800.2(a)(3). While we have delegated the gathering of cultural resources information to the 

applicant, the Commission retains its authority to make findings and determinations. 

The COE, NOAA Fisheries, EPA, and the Coast Guard also have responsibilities for considering 

the impacts of their undertakings on historic properties under the NHPA. However, as the lead 

federal agency for this project, the FERC will jointly address compliance with the NHPA for all 

the federal cooperating agencies in this EIS. The sections below summarize consultations and

cultural resources information, identify historic properties that may be affected by the project, 

update the status of compliance with the NHPA, and present our findings and recommendations. 

4.10.1 Consultations

Interested and consulting parties concerned about the potential effects the project may have on 

historic properties have had multiple opportunities to comment through the public scoping period 

(discussed in section 1.4), during direct consultations with the applicant, and in response to our 

release of draft environmental documents. The FERC issued a Draft EIS in May 2009 and a 

Supplemental Draft EIS in March 2013. These documents were sent to a wide range of 

stakeholders on our environmental mailing list that included U.S. government agencies, such as 

the Department of the Interior (USDOI), the Maine State Historic Preservation Office (SHPO), 

interested Indian tribes and Native Americans, regional environmental groups, and nongovernmental organizations. Their responses and comments on cultural resources issues are 

noted below.

4.10.1.1 Consultations with the State Historic Preservation Office

Downeast initiated consultation with the Maine Historic Preservation Commission (the SHPO) 

on February 21, 2006. In a letter dated March 14, 2006, the SHPO requested that Downeast 

conduct terrestrial surveys to identify architectural and historic and prehistoric archaeological 

resources onshore and an underwater survey to identify offshore cultural resources. The SHPO 

indicated that there was one previously recorded prehistoric site (number 97.6) located near the 

proposed LNG terminal. Through subsequent telephone calls (June 7 and June 15, 2006) and 

correspondence, Downeast and the SHPO discussed survey methods. 

On June 15, 2006, Downeast provided the SHPO with a project sensitivity assessment and 

proposal for Phase I survey. Four areas were identified as possessing high sensitivity for 

potential to contain precontact archaeological resources, and nine areas were identified as having 

moderate potential. Subsurface testing was recommended for those areas. The SHPO accepted 

this survey proposal in a letter to Downeast’s contractor dated June 16, 2006.
4.10 – Cultural Resources 4-238

Downeast provided the SHPO with draft copies of its Phase I Historic Archaeological and 

Historic Architectural Survey Report and Phase IA and Phase IB Precontact Archaeological 

Survey Report on August 8, 2006. Revised copies of those reports were submitted to the SHPO 

on October 23, 2006. Also on October 23, 2006, Downeast provided the SHPO with a copy of 

its Marine Archaeological Technical Report. On October 2, 2006, Downeast provided the SHPO 

with a copy of its draft Unanticipated Discovery Plan. The plan, entitled Procedures for Guiding 

the Discovery of Unanticipated Cultural Resources and Human Remains, is discussed below in 

section 4.10.3. In a letter to the SHPO dated December 6, 2006, Downeast addressed questions 

about potential visual impacts on historic properties resulting from LNG marine traffic.

We discussed the project with the SHPO on November 7, 2006. The SHPO indicated

satisfaction with the approach taken by Downeast’s archaeological contractors (Spiess 2006).

In a letter dated January 25, 2007, to Downeast’s cultural resources consultant, the SHPO 

commented on the prehistoric, historic archaeology, and architectural survey reports it received 

on January 4, 2007. In that letter, the SHPO requested additional information about architectural 

resources. In a letter dated March 5, 2007, the SHPO requested additional information on 

historic fish weirs in Mill Cove. 

In response to the SHPO’s comments, in May 2007, Downeast provided a revised historic 

architectural survey report, and a report on the Mill Cove fish weirs. The SHPO commented on 

the revised architectural report in a letter dated June 25, 2007, and commented on the fish weir 

report in a letter dated June 19, 2007.

In January 2008, Downeast advised the SHPO of the amended pipeline route and requested 

continued consultation on the project. The SHPO responded on January 31, 2008, requesting 

additional archaeological and architectural surveys covering the new pipeline route. In a letter to 

the FERC on June 16, 2009, the SHPO stated that it had reviewed our Draft EIS for this project, 

and concurred with the information and recommendations contained in section 4.10 Cultural 

Resources. In addition, the SHPO indicated that it was still waiting for Downeast to provide data 

previously requested. As noted in our Draft EIS, the results of all cultural resources inventories, 

including the amended pipeline route and associated facilities, have not yet been filed with the 

Commission (see section 4.10.4 of this EIS).

4.10.1.2 Consultations with Other Federal Agencies

Downeast consulted with the FWS in 2006 regarding the portion of the proposed pipeline that 

would cross the Moosehorn NWR. However, in January 2008, Downeast amended the pipeline 

route so that it no longer crosses the Moosehorn NWR. 

The USDOI National Park Service (NPS), which administers the Saint Croix Island International 

Historic Site, in cooperation with Parks Canada, provided comments to the FERC about the 

project in a letter dated April 14, 2006. The park, comprising about 22 acres, including an island 

in the St. Croix River and two mainland parcels in Calais, Maine, was established to 

commemorate the first attempt by France to establish a colony in North America. It was 

designated a national monument in 1949, and recognized as an international historic site in 1884.

The Saint Croix Island International Historic Site is located about 5.5 miles northwest of the 

proposed LNG terminal. The NPS is concerned about potential project-related impacts on the 

site, including impacts on air quality and noise, visual impacts, impacts from LNG marine traffic, 
4-239 4.10 – Cultural Resources

and safety. In a November 7, 2006 data request, we asked Downeast to evaluate any potential 

project impacts on the Saint Croix Island International Historic Site. Downeast conducted a 

photo simulation assessment exercise, filed on April 9, 2007, that showed that only a portion of 

the proposed LNG terminal pier would be visible from the Interpretive Center at the Saint Croix 

Island International Historic Site. Downeast’s consultant contends that there should be no 

project-related adverse visual impacts, because the proposed facilities would be a minor element 

in the background landscape of the viewshed from the Saint Croix Island International Historic 

Site.

The U.S. Department of the Interior Bureau of Indian Affairs (BIA) motioned for intervener

status on behalf of the Passamaquoddy Tribe in its letter of February 29, 2008 to the 

Commission. The BIA indicated it was interested in participating in the resolution of 

outstanding issues regarding the mitigation of impacts on aquatic and terrestrial species, and the 

protection of tribal religious and cultural resources. The BIA, through the July 2, 2009 letter to 

the FERC from the USDOI commenting on our Draft EIS, stated that it believes that the 

development of this project may have effects on the traditional cultural practices of the 

Passamoquoddy Tribe. The BIA would like the applicant to consult regarding potential impacts 

on tribal trust lands. Consultations with Indian tribes and other Native Americans are discussed 

in more detail below in section 4.10.1.3.

On July 2, 2009, the USDOI, on behalf of its NPS, BIA, and FWS, provided the FERC with its 

comments on our Draft EIS. The NPS raised concerns about the potential for lighting at the 

LNG terminal to affect the quality of the night sky at the Saint Croix Island International Historic 

Site. The USDOI requested that Downeast adjust its terminal lighting system to minimize those 

impacts. The FWS is concerned about potential impacts on the Moosehorn National Wildlife 

Refuge, including effects on air quality. The BIA claims that the applicant has not provided it 

with copies of cultural resources reports. The BIA is concerned about potential project effects on 

traditional cultural properties, historic sites, and fisheries of importance to the Passamoquoddy 

Tribe. The USDOI disagreed with the area of potential effect (APE) defined by Downeast’s 

consultants for the terminal tract and pipeline route (see sections 4.10.2.2 and 4.10.2.3 below). 

It would like the APE expanded to the entire bay where the terminal would be located, the 

shoreline visible along the waterway, and the visible swatch of the entire pipeline. However, the

SHPO accepted the APE as defined by Downeast’s consultants when it accepted the survey 

reports, and the USDOI comments far exceed the definition of the APE given in the ACHP’s 

regulations for implementing Section 106 of the NHPA.24

In a letter dated May 8, 2007, the Natural Resources and Planning Manager for the Roosevelt 

Campobello International Park commented that the Sandia Zones of Concern appear to overlap 

park lands (see section 4.12.5 of this EIS for discussion of Sandia Zones of Concern). In a data 

request issued July 24, 2007, we asked Downeast to clarify if any historic structures within the 

 24 36 CFR 880.16(d) defines the APE as “the geographic area...within which an undertaking may directly or 

indirectly cause alternations in the character or use of historic properties...” There are no historic properties

currently identified that would be adversely affected within the viewshed for the LNG terminal and pipeline. Nor 

would LNG vessel traffic in the waterway alter the character or use of historic properties overlapped by the Zones of 

Concern, any more than current ship traffic in the sea lanes does. Lastly, 36 CFR 800.4(a)(1) states that the agency 

defines the APE in consultation with the SHPO, or THPO for tribal lands. The FERC staff and SHPO agree on the 

definition of the APE by Downeast’s consultants.
4.10 – Cultural Resources 4-240

Roosevelt Campobello International Park would be overlapped by the Zones of Concern. 

Downeast responded, on August 13, 2007, that no historic structures within the Roosevelt 

Campobello International Park would be overlapped by the Zones of Concern, which extend up 

to 2.2 miles from the waterway for LNG vessel marine transit. In a letter to the FERC dated 

January 19, 2009, the Superintendent of the Park stated that any LNG facility development on 

the St. Croix River or in Passamaquoddy or Cobscook Bays would be inappropriate, and the Park 

Commission opposes the granting of any permits to Downeast. 

In a letter to the FERC on July 5, 2009, commenting on our Draft EIS, the Executive 

Secretary/Superintendent for the Roosevelt Campobello International Park Commission stated 

that it still had concerns about potential impacts on air quality, and safety issues related to LNG 

vessel marine traffic in the waterway, including effects on tourism and visitors, vistas, and core 

structures at the park, such as the Franklin D. Roosevelt Summer Home and Park Visitor Center.

On April 10, 2013, the Executive Secretary/Superintendent for the Roosevelt Campobello 

International Park Commission commented to the FERC on our Supplemental Draft EIS. The 

Park Commission pointed out that it is an intervenor in this proceeding, remains opposed to the 

project, and reiterated its safety concerns. 

The St. Croix International Waterway Commission commented in a letter dated March 14, 2008 

to the FERC that construction or operation of the project could result in disturbance or loss of 

native species, assemblages, and habitats having high ecological or cultural significance. It also 

commented that the project could result in loss of archaeological and historical resources within 

the waterway corridor due to construction or operation. 

4.10.1.3 Consultations with Indian Tribes and other Native Americans 

The FERC has consulted with federally recognized Indian tribes that may have historically 

occupied or used the project area, and may attach religious or cultural significance to sites that 

may be affected by the project. A copy of our NOI issued March 13, 2006 was sent to the 

Passamaquoddy Tribe. In an April 15, 2006 letter to the FERC, the Passamaquoddy Tribal 

Historic Preservation Officer (THPO) raised concerns about tribal access to a cultural site 

located south of the proposed LNG terminal. The THPO’s letter indicated that traditional 

activities such as water crossings occurred in the region, that the terminal area was used as a 

tribal hunting site, and that an eighteenth century trading post may have been situated on the 

north side of Mill Cove. The THPO requested that a survey be conducted covering the LNG 

terminal and its associated waterway for LNG marine traffic, and the THPO would like the 

opportunity to review archaeological work plans.

We sent a copy of our September 18, 2006 supplemental NOI to the Passamaquoddy Tribe. We 

also sent copies of our December 1, 2006 and February 13, 2008 supplemental NOIs to the 

Passamaquoddy Tribe, Penobscot Indian Nation, Aroostock Band of Micmacs, and Houlton 

Band of Malisset Indians. The Passamaquoddy Tribe filed as an intervener in this proceeding on 

January 11, 2007, because of its interests in potential project impacts on ecological, spiritual, and 

cultural resources.
4-241 4.10 – Cultural Resources

The Passamaquoddy Tribe at Pleasant Point commented to the FERC in a February 20, 2008 

letter about the amended pipeline route. The tribe objected to the placement of the pipeline 

across islands within the St. Croix River. They are concerned about potential project-related 

impacts on salmon and the river’s ecosystem. On May 3, 2013, Edward Bassett, a member of 

the Pleasant Point Reservation Passamaguoddy Tribal Council filed comments with the FERC in 

response to our Supplemental Draft EIS. He also raised concerns about the proposed pipeline 

route crossing the St. Croix River, which may have effects on tribal fishing activities and impacts 

on reservation islands. Further, he suggested that Downeast continue to have face-to-face 

consultations with the tribe. Downeast proposes to use an HDD to cross under the St. Croix 

River, and in response to these comments has amended the pipeline route to avoid encroaching 

on any Indian lands, and disturbing sensitive environments during construction and operation of 

the sendout pipeline.

Besides federally recognized Indian tribes, some other Native American organizations have 

commented to the FERC about the Downeast LNG Project. St. Mary’s First Nation Fisheries 

corresponded with the FERC in January 2007. They expressed concerns about possible impacts 

on their fishing and sustenance rights. They also expressed concerns about potential impacts on 

threatened or endangered whale species, such as the North Atlantic right whale, fin whale, 

humpback whale, and harbor porpoise. Whales are connected to First Nation creation stories and 

whale ceremonies are still practiced. This EIS addresses potential project-related impacts on 

marine mammals, including whales in section 4.5.2. Project-related impacts on fishing are 

addressed in sections 4.7 and 4.8. Other Native American groups have filed as interveners in 

Downeast’s proceeding before the FERC. This includes the Union of New Brunswick Indians 

and the Nulankeyutmonen Nkihtahkomikumon (We Take Care of Our Land). In a letter dated 

January 15, 2007, the Union of New Brunswick Indians, which represents 12 First Nations in the 

Canadian Province of New Brunswick, raised concerns about the preservation of aboriginal 

treaty rights. The Nulankeyutmonen Nkihtahkomikumon, consisting of three individuals from 

the Passamaquoddy Tribe, in a letter dated January 19, 2007, raised concerns about possible 

impacts of LNG marine traffic on traditional waters and fisheries, and potential impacts on a 

traditional cultural site at Split Rock.

On July 6, 2009, the law firm of Shems Dunkiel Raubvogel & Saunders, representing the 

Nulankeyutomonen Nkihtahkomikumon, Save Passamaquoddy Bay-Canada, Inc., and Save 

Passamaquoddy Bay-U.S., Inc. (Three Nation Alliance or TNA) filed with the FERC comments 

on our Draft EIS. That letter mentioned several historic districts not addressed in the draft, 

which we have listed in this final EIS (see section 4.10.2.1).

The Coast Guard has also consulted directly with the Passamaquoddy Tribe and other Native 

Americans. The tribe was invited to participate in Coast Guard working groups related to the 

proposed Downeast project. Elements of the Pleasant Point Reservation tribal government, 

including law enforcement, fire, emergency response, and environmental management personnel, 

participated in the working group’s evaluation of Downeast’s WSA. A representative of the 

Coast Guard met with Edward Barrow, representing the Passamaquoddy Tribe, on December 13, 

2006, and in response to tribal requests the Coast Guard has engaged in further outreach 

activities (Garrity 2006).
4.10 – Cultural Resources 4-242

In a September 11, 2007 submittal to the Coast Guard and the Commission, the TNA provided 

comments to the Coast Guard’s information requests. Citing provisions for aboriginal and 

sustenance licenses at 12 M.S.R.A §6302-A, TNA contends that Passamaquoddy tribal members 

maintain aboriginal fishing rights to the waters proposed for use by Downeast. Downeast 

disagrees, and stated that the Passamaquoddy Tribe does not have sovereignty or any other 

special fishing or sustenance rights over waters proposed for use by the project. Impacts on 

tribal fishing grounds would be similar to those described in sections 4.7.3.1 and 4.7.3.2 of this 

EIS with regard to public, recreation, and special land uses. However, as noted by the Coast 

Guard in their comments on the draft EIS, the Coast Guard ultimately has the jurisdictional 

authority to enforce safety and security measures within the navigable waters of the United 

States, and is sensitive to the fishing rights of the Passamaquoddy Tribe. The Coast Guard’s

WSR includes a recommendation that Downeast provide written verification of collaboration 

with and acceptance from the Passamaquoddy Nation, ensuring that its jurisdictional interests 

and public safety and security needs are adequately met. In addition to the FERC’s consultations 

with Indian tribes, Downeast contacted Indian tribes in Maine about its proposed project, 

including the Houlton Band of Maliseet Indians, Aroostock Band of Micmacs, Penobscot Nation, 

and Passamaquoddy Tribe. On March 13, 2006, the Penobscot Nation commented that the 

project would have no impact on cultural resources of significance to them. However, the 

Penobscot Nation requested that the Passamaquoddy Tribe be contacted, and that the Penobscot 

Nation should be notified in the event that Native American cultural materials are encountered 

during the course of the project. 

Downeast met with the Passamaquoddy THPO on June 21, 2006. The THPO requested that 

Downeast purchase a parcel of land on the south side of the proposed LNG terminal to provide 

tribal access to a cultural site. Downeast requested more specific data about the location of the 

eighteenth century trading post. The THPO indicated that areas along the pipeline route should 

be surveyed and tested that are sensitive for cultural resources, including water crossings and 

potential caribou hunting camps. The THPO requested that Downeast consider involving the 

tribe in the project, providing assistance for tribal cultural education programs, and that it make a 

presentation about the project to the joint Tribal Council.

On August 10, 2006, Downeast provided copies of its draft terrestrial cultural resources survey 

reports to the Passamaquoddy Tribe, Aroostook Band of Micmac Indians, and Houlton Band of 

Maliseet Indians, and revised copies of these reports were sent to the tribes on October 23, 2006. 

Downeast also provided the tribes with copies of its Phase I Marine Archaeological Survey 

Report. In addition, on September 28, 2006, Downeast submitted copies of its draft 

Unanticipated Discovery Plan to the Passamaquoddy Tribe, Aroostook Band of Micmac Indians, 

and Houlton Band of Maliseet Indians. 

On September 16, 2006, the Passamaquoddy THPO sent a letter to Downeast reiterating its 

concerns. These concerns include the location of the proposed LNG terminal in direct line of 

travel to a cultural site of significance to the tribe; location of the proposed LNG terminal near an 

old village site and historic trading post; proposed pipeline crossing of waterbodies that may be 

traditional fishing sites, and sites for tribal travel, camping, and quarrying activities; and the 

proposed pipeline crossing of Moosehorn NWR, which was historically used by the tribe for 

hunting caribou. In an April 9, 2007 response to our March 19, 2007 data request, Downeast 

indicated that the company is continuing to consult with the Passamaquoddy Tribe. Downeast 
4-243 4.10 – Cultural Resources

held a meeting with the Passamaquoddy THPO and an environmental advisor to the tribe on 

May 3, 2007. The THPO informed Downeast that the Passamaquoddy Tribal Council had 

entered into a development agreement with Quoddy Bay LNG25 that prohibited the 

Passamaquoddy Tribe from formally consulting with Downeast. The THPO agreed to continue 

to hold informal discussions with Downeast about cultural resources issues.

In an April 6, 2007 communication to Downeast, filed on June 5, 2007, the THPO stated that the 

potential impact of the proposed LNG pier on access to a traditional cultural sacred site had been 

discussed at a previous meeting. Downeast indicated to the THPO that the company was looking 

for another point of access for the tribe.

In a May 4, 2007 submittal to the Maine BEP, a copy of which was filed by Downeast on June 5, 

2007 in its proceeding before the FERC, Bear Creek Investments (BCI) stated that it has 

executed a purchase agreement for the property that abuts the proposed Downeast LNG terminal 

tract on the southeast. According to an article published in the Bangor Daily News on May 8, 

2007, a copy of which was filed with the FERC by Downeast on June 5, 2007, BCI plans to build 

the Wabanaki Interpretive and Conference Center on this property. The center would be 

developed in consultation with the Passamaquoddy Tribe, and is designed, among other things, 

to provide access to sites that the tribe considers historically and culturally important, including 

Pulpit Rock. According to the architectural firm that designed the Center, there are no 

immediate plans to commence construction of the project. We have no additional information on 

the status of this project. 

4.10.2 Cultural Resources Overviews and Inventories

4.10.2.1 Waterway for LNG Marine Traffic 

Stakeholders have raised concerns about potential project-related impacts from LNG marine 

traffic on historic resources at Campobello Island, New Brunswick, Canada, including the 

1829 Head Harbour Light station and the former summer home of United States President 

Franklin Roosevelt within the Roosevelt Campobello International Park. Downeast indicated 

that LNG marine traffic would not pass within 1,500 feet of Campobello Island. There are five 

historic summer cottages within the park, on the north side of the island near the junction of 

Route 774 and Glensevern Road. The closest of these historic cottages to the LNG vessel transit 

route would be approximately 2.6 miles. Downeast’s architectural consultant did a site file 

search within 2.1 miles of the LNG marine traffic route, and identified 10 properties listed on the 

NRHP in the towns of Robbinston and Eastport (PAL 2006). Downeast, in an April 30, 2007 

filing, clarified that three NRHP-listed properties, all historic residences, are located in 

Robbinston, about 2.5 miles north of the proposed LNG terminal. There are four individual 

NRHP-listed historic sites (a church, a house, a former high school, and an eighteenth century 

fortification barracks) and two Historic Districts located in Eastport, about 14 miles south of the 

proposed LNG terminal. Lastly, the West Quoddy Head Lighthouse, in Lubec, Maine, located 

between 1.0 and 2.1 miles from the LNG vessel marine transit route, is listed on the NRHP. The 

TNA mentioned that the town of Eastport, on Moose Island, along the LNG vessel marine transit 

 25 On October 17, 2008, FERC dismissed Quoddy Bay LNG’s application to build and operate an LNG import 

terminal and associated pipeline. This dismissal is without prejudice to Quoddy Bay filing a new application in the 

future.
4.10 – Cultural Resources 4-244

route, contains the Boynton Street Historic District (consisting of three buildings), Fort Sullivan 

(consisting of a barracks and remains of a powder magazine), and the Eastport Historic District 

(consisting of 29 buildings), which are all listed on the NRHP. 

The Passamaquoddy Tribe’s Pleasant Point Indian Reservation is within about 1.0 mile of the 

LNG vessel transit route. The Passamaquoddy Tribe and Downeast disagree about aboriginal 

fishing rights to the waters proposed for use by LNG marine traffic to and from the terminal. 

The Coast Guard ultimately has jurisdictional authority to enforce safety and security measures

within the navigable waters of the United States, and is sensitive to the fishing rights of the 

Passamaquoddy Tribe.

In a November 20, 2006 data request, we asked Downeast to consult with the SHPO regarding 

potential impacts on cultural resources resulting from LNG marine traffic. The SHPO responded 

to that request, in a January 25, 2007 letter to Downeast’s cultural resources consultant, that 

LNG vessel transit, in and of itself, is not likely to affect aboveground or archaeological 

resources, and no further work is necessary along the waterway for LNG marine traffic. We 

concur with the SHPO. Given the design of LNG vessels, the safety and security measures 

adopted by Downeast in its WSA, and the mitigation measures recommended in the Coast Guard 

WSR, it is highly unlikely that an accident or spill from an LNG vessel transiting within the 

waterway would have adverse effects on any historic properties.

4.10.2.2 LNG Terminal 

Downeast’s application included copies of reports for its marine archaeological survey, 

prehistoric archaeological survey, historic archaeological survey, and architectural survey. 

Downeast’s archaeological consultants defined the APE for the terrestrial portion of the proposed 

LNG terminal to be 47 acres, including areas for the LNG storage tanks, vaporizers, 

administrative buildings, access roads, and parking lots. In its application, Downeast proposed 

to leave the remaining 33 acres of its 80-acre parcel as an undeveloped buffer. 

Background research indicated that a previously documented prehistoric shell midden (site 

number 97.6) was reported near the north shore of Mill Cove. However, Downeast claims that 

this site is not within the APE for the LNG terminal.

In April 2006, Downeast’s prehistoric archaeological contractor conducted a walkover survey of 

the terrestrial portion of the LNG terminal APE. No evidence of Native American occupations 

was found during this survey of upland areas (Clark et al. 2006). 

As noted by interested stakeholders, Mill Cove, in the area of Downeast’s terminal marine 

facilities, has the potential to contain prehistoric fish weirs. Downeast conducted a marine 

archaeological survey and filed a draft copy of the report of the investigations with the FERC on 

November 7, 2006. The study encompassed the proposed pier and berthing facilities, covering 

an area of about 57 acres offshore. The marine field reconnaissance consisted of geophysical 

remote sensing using a multi-beam echo sounder, side-scan sonar, sub-bottom profiler, marine 

magnetometer, and single-beam bathymetry system, in association with geotechnical borings. 

The marine survey found no evidence of submerged cultural resources, including prehistoric 

archaeological sites or fish weirs, or historic shipwrecks (Robinson and Brett 2006). 
4-245 4.10 – Cultural Resources

Two offshore historic-era fish weirs were documented in the historical archaeological survey 

report for the proposed LNG terminal. A local informant, Gerald Morrison, told Downeast that 

his family operated one weir south of the LNG terminal for catching herring during the 1950s. 

In 1976, Mr. Morrison built a new weir just east of the proposed location for the LNG terminal 

pier. This modern weir is still in use (Booth et al. 2006). 

After local residents expressed concerns that other historic fish weirs may exist in Mill Cove, the 

SHPO staff conducted a site visit that found unrecorded resources, and requested that Downeast 

conduct additional investigations. In May 2007, Downeast’s contractor reported an evaluation of 

two previously unrecorded fish weirs (site numbers ME 371-009 and ME 371-010). The report 

concluded that the two sites are remains of late nineteenth or early twentieth century fish weirs 

most likely constructed to catch either smelt or herring. The contractor concluded that the weirs 

are highly deteriorated and do not meet the criteria for eligibility to the NRHP (Booth and 

Wheeler 2007). 

Historic research identified a building labeled as the “McCleland” residence on an 1881 map in 

the vicinity of the proposed LNG terminal. In April 2006, Downeast’s historic archaeological 

contractor recorded a cellarhole and barn associated with the McCleland farmstead as site 

number ME-371-005. The contractor indicated that the site is located north of the LNG terminal 

parcel boundaries, outside of the APE, and therefore no additional testing or research was 

conducted (Booth et al. 2006).

Downeast filed a revised historic architectural survey report on May 30, 2007. No architectural 

sites were identified within the LNG terminal tract, but there were six standing historic structural 

complexes noted within the viewshed for the terminal. In its June 25, 2007 review of the revised 

architectural survey report, the SHPO did not identify any of the historic complexes within the 

viewshed of the proposed LNG terminal as being eligible for the NRHP. However, additional 

data was requested by the SHPO for the farmstead at 235 Ridge Road in Robbinston before an 

assessment of its NRHP eligibility can be made. According to an August 13, 2007 filing by 

Downeast, in response to our July 24, 2007 data request, this house faces north, away from the 

LNG terminal, located about 0.5 mile to the southeast of it. The house is surrounded by trees, 

and we believe that the LNG terminal would have no adverse visual impacts on this site.

The SHPO reviewed Downeast’s marine survey report in a letter dated November 14, 2006, and 

found it acceptable. The SHPO accepted Downeast’s historic archaeology survey report in a 

letter dated January 25, 2007. In a letter dated June 19, 2007, the SHPO accepted the report 

evaluating the historic fish weirs, and concurred that they are not eligible for the NRHP. We 

agree with the SHPO that no historic properties were identified that would be affected within the 

APE for the LNG terminal. 

4.10.2.3 Sendout Pipeline

A stakeholder requested an analysis of potential project-related impacts on archaeological 

resources in the Meddybemps Lake area. Since the proposed pipeline route avoids the 

Meddybemps Lake area, we believe that the project would have no impacts on archaeological 

resources in that area, and no further analyses are necessary.

An archaeological site file search indicated that a previously recorded prehistoric site (number 

96.08) and historic homestead site (number ME-024-001) were located in the vicinity of Stony 
4.10 – Cultural Resources 4-246

Brook, where the proposed pipeline would parallel the EMEC powerline. Downeast’s 

prehistoric archaeological consultant conducted field survey and testing in this area, and 

determined that site numbers 96.08 and ME-024-001 are located on the north side of the 

powerline, while the proposed Downeast sendout pipeline would be routed on the south side of 

the powerline. As currently designed, the project should avoid impacting these sites since they 

are outside of the proposed pipeline construction right-of-way, so no further work was done 

(Clark and Cole-Will 2006; Booth et al. 2006).

Downeast’s archaeological consultants defined the APE for the pipeline as a survey corridor 

200 feet wide (100 feet on each side of the proposed centerline), except where the pipeline would 

be adjacent to roads, where the survey corridor was 100 feet from the road shoulder. Based on 

its research design, Downeast’s prehistoric archaeological contractor conducted a pedestrian 

inventory of a total of 21.3 miles of selected portions of the pipeline route (between MPs 0.0 to 

11.0, 12.9 to 13.1, 13.4 to 17.9, 18.1 to 20.1, 22.0 to 23.0, and 24.7 to 27.1). Twelve locations 

were subjected to subsurface archaeological testing (at MPs 1.0, 7.6, 7.9, 8.6, 8.7, 14.2, 14.4, 

14.8, 17.5, 19.2, 22.1, and 25.9). We note that, based on the amended sendout pipeline route, the 

areas along the original route between MP 10.2 and MP 17.7, including three testing locations, 

are no longer within the APE for the pipeline. 

The testing resulted in the discovery of one new buried prehistoric archaeological site 

(number 96.09) in the vicinity of Conic Stream (Clark et al. 2006). This area would be avoided 

by the amended pipeline route, so no additional work is required at this site.

Downeast’s historical archaeological consultant reviewed historic maps and conducted on-theground inspections of a total of about 11.5 miles where potential historic sites might be located. 

The historical research identified two historic homesteads, a schoolhouse, a cemetery, and a 

quarry that may be located near the original pipeline route, but were not confirmed by on-theground inspections (Booth et al. 2006). The surveys resulted in the recording of seven newly 

identified historic archaeological sites (numbers ME-371-003, 004, 006, 007, 008, 011, and 012). 

These sites include the remains of five farmsteads, a quarry, and a dam. 

Three of the historic farmstead sites (numbers ME-371-003, 004, and 006) were archaeologically 

tested in June and October 2006. Testing at site ME-371-003 (J. Tramble Homestead) indicated 

that the site boundary is about 144 feet west of the proposed pipeline centerline, and therefore 

this site should not be affected by project construction. Site ME-371-004 (W. Trimble 

Homestead) is located about 230 feet west of centerline. However, it may be affected if 

Downeast uses McNeil Road for access. As a result of testing at site ME-371-006 (McNeil/Nash 

Homestead), the site was evaluated as not containing significant remains and is probably not 

eligible for the NRHP. A modern camper is currently parked within the site boundaries. 

A nineteenth century schoolhouse was noted on historic maps on the west side of McNeil Road 

in this vicinity, but was not found during on-the-ground inspections. Also in the vicinity of the 

McNeil/Nash Homestead was a historic rock wall that was not recorded as a historic 

archaeological site. Nevertheless, Downeast’s historic archaeological contractor recommended 

that the rock wall should be rebuilt if it is disturbed by pipeline construction activities. In an 

August 13, 2007 filing, Downeast submitted a plan, dated July 2007, outlining procedures it 

would implement to ensure that historic rock walls affected during pipeline construction 

activities would be properly identified, recorded, and restored after construction. 
4-247 4.10 – Cultural Resources

No further work was done at the other newly recorded historic archaeological sites, because they 

appear to be outside of the proposed pipeline construction right-of-way and should not be 

affected by the project. For example, site ME-371-007 (Schoolhouse Road Cellarhole) is about 

895 feet east of the proposed centerline, and site ME-371-008 (J. Larner Homestead) is about 

220 feet east.

Downeast conducted an architectural survey to identify historic standing structures that may be 

within the viewshed of the project (PAL 2006). In a letter dated January 25, 2007, the SHPO 

commented that the architectural survey report did not meet its standards and requested 

additional information regarding aboveground resources potentially affected by the pipeline. 

Downeast provided a revised architectural survey report dated May 2007. That report identified 

36 historic complexes with standing structures within the APE for the pipeline. Five of those 

historic complexes were evaluated as eligible for the NRHP (Porterfied and Olausen 2007).

The SHPO’s review of the revised architectural survey report, dated June 25, 2007, indicated that 

it disagreed with Downeast’s consultant, and that all but one of the identified historic structural 

complexes do not qualify for the NRHP. The SHPO requested additional information for one 

site before it would make a final finding of eligibility, and also requested corrections to the 

report maps before it would assess project impacts. In a letter dated January 25, 2007, the SHPO 

accepted the historical archaeological report submitted by Downeast’s consultant, and agreed 

with its recommendations relative to the proposed sendout pipeline. The SHPO also found the 

prehistoric archaeological survey report done for Downeast to be acceptable. However, it noted 

that two areas identified as being sensitive for prehistoric archaeological sites where access was 

previously denied still require survey and testing in the future (at MP 1.0 and MP 6.7). In 

addition, survey information for the amended portion of the pipeline route (MP 11.6 to MP 17.7) 

has not been filed with the Commission. We will defer making determinations of eligibility and 

effect until the entire APE for the pipeline is inventoried, and the SHPO has had the opportunity 

to comment on all reports, including a revised architectural survey report that addresses its 

previous concerns. 

4.10.3 Unanticipated Discoveries 

In our August 24, 2006 data request to Downeast, we asked for a project-specific plan to handle 

the unanticipated discovery of cultural resources or human remains during project construction 

and operation. A draft plan, entitled Procedures for Guiding the Discovery of Unanticipated 

Cultural Resources and Human Remains, was filed with the FERC on October 2, 2006, and also 

provided to the SHPO and interested Indian tribes. The SHPO reviewed the plan, and in a letter 

dated October 11, 2006, requested revisions. A revised plan was filed with Downeast’s 

application. The SHPO and the tribes have not yet commented on the revised plan. Pending 

SHPO approval and acceptance by the tribes consulted, we believe that the plan is acceptable.

4.10.4 Compliance with the NHPA

The FERC consulted with Indian tribes to identify sites of religious and cultural importance that 

may be affected by the project. Downeast has assisted us in addressing our responsibilities under 

Section 101(d)(6) of the NHPA, and 36 CFR 800.2(c)(2) by contacting Indian tribes in Maine 

about the project. The Passamaquoddy Tribe and other Native Americans have indicated 
4.10 – Cultural Resources 4-248

concerns about potential project impacts on traditional cultural properties, including restricting 

access to sites located in Mill Cove. Downeast has not documented that it has resolved issues 

related to potential project impacts on traditional cultural properties raised by the 

Passamaquoddy Tribe and other Native Americans. Therefore, in order to ensure that the project 

would have no adverse impacts on properties of traditional religious and cultural importance to 

an Indian tribe, we recommend that:

• Prior to construction, Downeast should file with the Secretary documentation of 

continued consultations with the Passamaquoddy Tribe, BIA, and other appropriate 

Indian tribes and Native Americans interested in the project’s potential impacts on 

cultural resources, including access to sites in Mill Cove, and seek resolution of 

identified project-related impacts on archaeological sites, burials, existing historic 

properties, and sites of religious or cultural importance within the APE.

We have not yet completed the process of complying with Section 106 of the NHPA. There are 

portions of the pipeline route that still require archaeological survey and testing. In addition, the 

architectural survey report should be revised to address issues raised by the SHPO.

Once data are complete, the FERC, in consultations with the other federal cooperating agencies 

and the SHPO, will make determinations of NRHP eligibility and project impacts. If any historic 

properties would be adversely affected by the project, we would seek ways to resolve those 

impacts, develop a Memorandum of Agreement if appropriate, and provide the ACHP with an 

opportunity to comment. The FERC will complete the Section 106 process before notifying 

Downeast that construction may proceed. 

To ensure that the Commission’s responsibilities under the NHPA are met, we recommend that:

• Downeast should not begin construction of facilities and/or use of all staging, 

storage, or temporary work areas and new or to-be-improved access roads until:

a. Downeast files with the Secretary:

(1) remaining cultural resources survey report(s);

(2) site evaluation report(s) and avoidance or treatment plan(s), as required; 

and

(3) comments on the cultural resources reports and plans from the Maine 

SHPO, and interested Native Americans and Indian tribes. 

b. the ACHP is afforded an opportunity to comment if historic properties would be 

adversely affected; and

c. the FERC staff reviews and the Director of OEP approves the cultural resources 

reports and plans, and notifies Downeast in writing that treatment measures 

(including archaeological data recovery) may be implemented and/or 

construction may proceed.

All materials filed with the Commission containing location, character, and 

ownership information about cultural resources must have the cover and any 

relevant pages therein clearly labeled in bold lettering: “CONTAINS PRIVILEGED 

INFORMATION – DO NOT RELEASE.”
4-249 4.11 – Air Quality and Noise

4.11 AIR QUALITY AND NOISE

4.11.1 Air Quality

Construction and operation of the project can potentially have an effect on local and regional air 

quality. We have identified the best estimate of exhaust emissions and emissions from fugitive 

dust from all construction operations as well as the direct and indirect emissions from the 

facilities. Although air emissions would be generated by construction activities involving the 

proposed pipeline and LNG terminal, the majority of air emissions associated with the project 

would result from the operation of the LNG terminal and the indirect emissions from the LNG 

vessels. We have attempted to quantify the impact of these emissions from the project, along 

with neighboring facilities on local and regional air quality. 

4.11.1.1 Regional Climate

The proposed LNG terminal and sendout pipeline are located in Washington County along the 

northeast coast of Maine. This region is strongly influenced by the ocean temperature and 

coastal weather patterns. Other climate influences include regional and subregional weather 

patterns and land topography. 

Historical climate data for the nearby City of Eastport, Maine demonstrates the daily and 

seasonal climate variability for the project area. Average daily high temperatures range from 

30.1°F (-1.1oC) in January to 74.5°F (23.6oC) in July and August. Daily minimum temperatures 

range from 13.7°F (-10.2oC) in January to 54.5°F (12.5oC) in August. The annual average 

temperature is 44.1°F (6.7oC). Extreme temperatures in Eastport for the entire period of record 

(1926 to 2005) range from a low of -23°F (-30.6oC) to a high of 98°F (36.7oC). Sea breezes in 

coastal areas help to reduce the frequency of high temperatures that occur more often in inland 

areas.

Winds blow predominantly from the west and northwest in the cold months and from the south 

and southwest in the warm months, with average speeds of 9.3 mph in the winter to 12.4 mph in 

the summer. Stronger winds blow primarily from the west. During winter, significant storms 

may occur with high winds and heavy rain or snow.

The waters in the Bay of Fundy are among the foggiest areas in the world. Seasons that produce 

the greatest contrast in temperature between sea surface and the air produce the densest fog. For 

this reason, fog is generally more prevalent in summer than winter; however, fog can develop 

any day of the year. Fog occurs an average of 112 days per year in Eastport, and heavy fog with 

visibility less than a quarter mile occurs 35 to 40 days per year. 

4.11.1.2 Existing Air Quality 

The term air quality refers to relative concentrations of pollutants in the ambient air. The 

subsections below describe well-established air quality concepts that are applied to characterize 

air quality and to determine the significance of increases in air pollution. 

Federal and state ambient air quality standards (AAQS) have been designed to protect human 

health and the environment from airborne pollutants. AAQS establish limits on the 

concentration of pollutants in the ambient air. The EPA has developed National Ambient Air 

Quality Standards (NAAQS) for criteria air pollutants such as nitrogen oxides (NOx) and carbon 
4.11 – Air Quality and Noise 4-250

monoxide (CO), ozone (O3), sulfur dioxide (SO2), and inhalable particulate matter (PM2.5 and 

PM10). PM2.5 includes particles with an aerodynamic diameter less than or equal to 2.5 microns, 

and PM10 includes particles with an aerodynamic diameter less than or equal to 10 microns. 

VOCs are the precursor pollutant for ozone generation. 

Individual states may adopt standards more stringent than the NAAQS. AAQS promulgated by 

the Maine DEP are published in Chapter 110 of the Maine DEP regulations. In some cases, the 

Maine AAQS are more stringent than the NAAQS. In addition, the Maine DEP has also 

established ambient air quality standards for pollutants not addressed by the NAAQS.

Primary NAAQS levels are targeted for protection of human populations, in particular, sensitive 

populations such as asthmatics, children, and the elderly. Secondary NAAQS are targeted for 

protection of public welfare (visibility; damage to animals, crops, vegetation, and buildings). 

The National and Maine AAQS are presented in table 4.11.1.2-1. 

TABLE 4.11.1.2-1

National and State Ambient Air Quality Standards

Air Pollutant Averaging Period NAAQS (μg/m3) Maine AAQS (μg/m3)

Carbon Monoxide 1 hour 40,000 40,000

8 hour 10,000 10,000

Lead 24 hour NA 1.5

Quarter 1.5 NA

Rolling 3-Month Average 0.15 NA

Nitrogen Dioxide 1 hour 189 NA

Annual 100 100

Particulate Matter less than 10 microns 24 hour 150 150

Annual NA 40

Particulate Matter less than 2.5 microns 24 hour 35 NA

Annual 15 NA

Sulfur Dioxide 1 hour 195 NA

3 hour 1,300 1,150

24 hour 365 230

Annual 80 57

Ozone 8 hour 147 NA

Hydrocarbons 3 hour NA 160

Photochemical Oxidants 1 hour NA 160

Total Chromium a/ 24 hour NA 0.3

Annual NA 0.05

Hexavalent Chromium 24 hour NA MDL or 0.001

a/ The total chromium standards apply until an analytic procedure to measure hexavalent chromium in the ambient air is approved. 

At that time, the total chromium standard would be replaced by the 24 hour hexavalent chromium standard.

MDL = method detection limit

NA = not available or not applicable

μg/m3 = micrograms per cubic meter
4-251 4.11 – Air Quality and Noise

A geographic area that satisfies the NAAQS for a given pollutant is considered an attainment 

area with respect to that pollutant. Likewise, an area that does not satisfy the NAAQS for a 

pollutant is considered a nonattainment area with respect to that pollutant. Thus, an area may be 

in attainment with respect to some pollutants and nonattainment for others. Regional air 

monitors provide the basis to determine whether an area is or is not in attainment. In the absence 

of air monitor data, an area may be designated as "unclassifiable" with respect to one or more 

pollutants. NAAQS attainment status designations for Maine, Massachusetts, and New 

Hampshire are shown in 40 CFR 81, Subparts 320, 322, and 330, respectively.

The proposed project would be located near the border with the Canadian province of New 

Brunswick. Projects in New Brunswick are subject to both Canadian and New Brunswick 

Ambient Air Quality Objectives as shown in table 4.11.1.2-2.

TABLE 4.11.1.2-2

Canadian and New Brunswick National Ambient Air Quality Objectives (and Acceptable Levels)

Air Pollutant Averaging 

Period

New Brunswick Maximum 

Permissible Ground Level 

Concentration in Saint John 

County (μg/m3)

Canadian National Ambient Air 

Quality Objectives Maximum 

Desirable Level / Acceptable 

Levels (μg/m3)

Sulfur Dioxide 1-hour 450 450 / 900

24-hour 150 150 / 300

Annual 30 30 / 50

Nitrogen Oxides 1-hour 400 -- / 400

24-hour 200 -- / --

Annual 100 60 / 100

Carbon Monoxide 1-hour 35,000 15,000 / 35,000

8-hour 15,000 6,000 / 15,000

Total Suspended Particulates 24-hour 120 -- / 120

Annual 70 60 / 70

Respirable Particulate Matter 

(PM2.5)

24-hour -- 30 / --

Ozone 1-hour -- 100 / 160

24-hour -- 30 / 50

Annual -- -- / 30

Greenhouse gases (GHG), the most common of which are carbon dioxide (CO2), methane (CH4), 

nitrous oxide (N2O), O3, hydrofluorocarbons, and perfluorocarbons, are naturally occurring 

pollutants in the atmosphere and products of human activities, including burning fossil fuels. In 

2009, EPA determined that current and projected concentrations of the key GHGs in the 

atmosphere threaten public health and welfare due to climate change effects. Fossil fuel 

combustion emits CO2, CH4, and N2O. GHG emissions are generally calculated in terms of 

carbon dioxide equivalents (CO2e) where the heating potential of each gas is expressed as a 

multiple of the heating potential of CO2e.
4.11 – Air Quality and Noise 4-252

Air Quality Control Regions

An Air Quality Control Region (AQCR) is a geographic area (generally urbanized areas or 

consolidated metropolitan areas), which, due to existing air quality or projected growth rates, has 

the potential to exceed the NAAQS. The CAA requires each state to adopt and submit a State 

Implementation Plan (SIP) to implement, maintain, and enforce the NAAQS for each 

nonattainment AQCR. The SIP identifies source control strategies to achieve and maintain 

NAAQS, or identifies the methods (e.g., air sample collection, report submittals) by which 

nonattainment areas can demonstrate progress toward attainment. Upon approval by EPA, the 

rules in the SIP become federally enforceable. The SIP for Maine is published in 40 CFR 

Part 52 Subpart U.

The EPA assigns a number and a name to each ACQR. The LNG project would be located in 

ACQR-109, the Down East Intrastate AQCR. The proposed area for the LNG terminal and 

sendout pipeline is designated as attainment or unclassified for all NAAQS. The nearest 

nonattainment area to the proposed Downeast LNG terminal location is in Eastern Hancock 

County about 56 miles to the southwest.

The attainment status designations for Maine are listed at 40 CFR 81.320. The areas previously 

designated as nonattainment for ozone were, on December 11, 2006, reclassified as maintenance 

areas for ozone. The entire state of Maine is located within the Ozone Transport Region (OTR).

The CAA sets out specific requirements for Maine and other northeast states that make up the 

OTR.

Air Quality Monitoring

To evaluate the impact of a project on air quality, the existing air quality must first be known. 

To achieve this, the state of Maine operates a criteria pollutant air monitoring network that 

collects ambient concentration data to estimate air quality for most locations within the state. 

This data is made available to the public via the EPA AirData database.

For the LNG terminal area and sendout pipeline, existing background concentrations of criteria 

pollutants were determined based on the available monitored data that was judged to be most 

representative based on distance from the project site, proximity to the coast, and the general 

land use nearby. Table 4.11.1.2-3 summarizes the existing ambient air pollutant concentrations 

determined from air monitor data over a recent five-year time span. As the table shows, the 

existing air quality levels in the vicinity of the LNG terminal and sendout pipeline are below the 

Maine AAQS. As stated previously, the region is in attainment for all federal NAAQS. Federal 

and state programs and regulations (discussed below) are established with the goal of ensuring 

that emissions from proposed projects do not cause significant deterioration of the existing air 

quality.
4-253 4.11 – Air Quality and Noise

TABLE 4.11.1.2-3

Existing Ambient Air Quality Monitoring Data Representative for the Project Area

Pollutant Monitor Avg. Time Units

Measured Concentrations a/

2003 2004 2005 2006 2007 AAQS b/

NO2 Bar Harbor Annual ppm - 0.001 0.001 0.001 0.001 0.053

CO Bar Harbor 1-Hour ppm 0.6 0.3 0.6 0.3 0.3 35

8-Hour ppm 0.4 0.3 0.4 0.3 0.3 9

SO2 Bar Harbor 3-Hour ppm - 0.007 0.008 0.005 0.006 0.50

24-Hour ppm - 0.004 0.006 0.003 0.004 0.14

Annual ppm - 0.003 0.002 0.001 0.001 0.03

PM10 Bangor 24-Hour μg/m3 48 44 48 42 53 150

Annual μg/m3 22 18 20 19 19 40

PM2.5 Bar Harbor 24-Hour μg/m3 22 19 19 20 22 35 

Annual μg/m3 6.7 5.9 5.9 5.1 5.4 15

O3 Perry 8-Hour ppm - 0.055 0.06 0.057 0.056 0.075

a/ Except for ozone, annual measurements represent the maximum measured pollutant level, and short-term measurements 

represent the second highest pollutant level. For ozone, the table shows the fourth highest measured levels.

b/ The most stringent AAQS is presented here. AAQS values for CO, NO2, and SO2 are converted from μg/m3 to ppm.

4.11.1.3 Regulatory Requirements for Air Quality

Federal and state regulations are established to protect existing air quality from new air pollution 

sources. Federal regulations are established in response to the CAA. State regulations must 

meet or exceed federal regulations. Upon approval by the EPA administrator, CAA permit 

responsibilities, compliance monitoring and enforcement are delegated to the state. The process 

to ensure regulatory review of a new emission source is facilitated through a permit or license 

application submitted by the new source to the state. The Maine DEP has delegated authority 

and thus jurisdiction over air emissions produced by the proposed project. The Maine DEP 

enforces its own regulations as well as EPA’s federal requirements. The following sections 

summarize the applicability of various Maine DEP and federal regulations. The permit review 

process, performed by the Maine DEP, addresses regulatory requirements for both construction 

and operation of the new source.

The type of air quality permit that must be obtained depends on whether the proposed facility is 

designated as a major source or a minor source. This source designation (major or minor) 

depends on the potential to emit (PTE) for the various pollutant emissions. For a new LNG 

facility in the state of Maine, if the emissions for any regulated pollutant in an attainment area 

exceeds 100 tons per year (tpy), then the facility is considered a major source for that pollutant. 

In addition, if the PTE for any one hazardous air pollutant (HAP) exceeds 10 tpy, or the total of 

all HAPs exceed 25 tpy, then the facility is considered a major source for HAPs. 

All new emission sources located in the OTR are considered to be in a nonattainment area with 

respect to permitting of NOx and VOC emissions, and the corresponding major source thresholds 

for these ozone precursor pollutants are 100 tpy and 50 tpy, respectively. 
4.11 – Air Quality and Noise 4-254

Although operation of a new LNG terminal would mean additional air emissions from LNG 

vessels, tugs, and escort boats that visit the terminal, these maritime emissions are excluded from 

consideration for permit PTE calculation under Maine regulations. As described in Maine DEP 

Chapter 100, emissions from marine vessels are considered secondary emissions, and secondary 

emissions are excluded from stationary source permit calculations. The estimated emissions for 

the LNG terminal and operations are below the thresholds for a major source, and thus the 

project is considered a minor source. The project is thus required by the state of Maine to obtain 

a minor source permit. Use of Best Available Control Technology (BACT) is required for all 

new emission sources in the state of Maine.

To ensure protection for other air quality concerns (e.g., visibility, vegetation damage), the state 

of Maine requires a new emission source to model their emissions to quantify the impacts. An 

air model analysis is automatically required for any source with a emissions of 50 tpy for SO2, 

250 tpy for CO, 25 tpy for PM10, 100 tpy for NOx, 0.6 tpy for lead, or 0.2 tpy for total chromium. 

The level of impact analysis required for sources where the emissions are below these levels is 

generally determined by the Maine DEP on a case-by-case basis. At the request of the FERC, an 

air quality impact analysis was performed for CO, NOx, PM10, PM2.5, and SO2 emissions from 

SCVs and vessel activities within the moored safety zone for the Downeast LNG Project. For 

the purpose of the analysis, PM2.5 emissions are assumed to be equal to PM10 emissions. Under 

NEPA we require that air quality impacts be evaluated based on the combination of primary and 

secondary emissions related to the project. Additional discussion of this air impact analysis is 

provided in section 4.11.1.5.

State Permit Application

To comply with Maine DEP Chapter 115 requirements, on December 5, 2006 Downeast 

submitted a minor source air emissions permit (i.e., license) application. This permit application 

was withdrawn by Downeast in November 11, 2007 and Downeast has estimated that the revised 

permit application would be resubmitted with the other state applications following issuance of 

the final EIS. The permit process requires a thorough review of project emissions to demonstrate 

they comply with applicable state and federal regulations and requirements, including the Maine 

SIP, however, the final permit should reflect the equipment and emissions identified in this final 

EIS. State rules require that project construction activities cannot begin until the permit 

application has been approved and because the state is within the OTR. Areas within the OTR 

must comply with the federally enforceable SIP. To ensure that the final permit reflects the 

analysis within this final EIS, we recommend that:

• Prior to construction of the LNG terminal, Downeast should file with the Secretary 

a copy of its final air permit from the Maine DEP. The permitted emissions should 

be consistent with the emissions of criteria pollutants, GHGs, and HAPs analyzed in 

the final EIS.

Federal Requirements

New Source Review/Nonattainment New Source Review

New Source Review (NSR) is a major source permit review process that applies to the 

construction and operation of new and modified stationary sources in nonattainment areas to 

ensure attainment of NAAQS. The goal of NSR is to assure that new major source emissions do 
4-255 4.11 – Air Quality and Noise

not significantly worsen air quality, and that advances in pollution control technology occur 

concurrently with industrial expansion. NSR requirements do not apply to the project because 

the project is designated under Maine regulations as a minor source.

Federal Class I Areas

Federal Class I areas include international parks, national wilderness areas, national parks, and 

national memorial parks that are given special protection. Federal Class I areas are designated in 

40 CFR 81. If a new major source is located near a Class I area, then the air quality impacts (i.e., 

expected increases in air pollutant concentrations caused by the project) must be evaluated based 

on the more stringent thresholds. The Class I areas located near the project are shown in 

table 4.11.1.3-1. Because the project is a minor source, the major source requirements for 

protection of Federal Class I areas do not apply. However, under NEPA we are tasked with 

disclosing the individual and cumulative impacts from the project. 

We requested that Downeast coordinate with the Domtar Paper Company and Calais LNG26, in 

cooperation with the Maine DEP, the Department of the Interior, and the Department of 

Agriculture Forest Service, to provide a cumulative air impact analysis consistent with the 

guidelines published in the Federal Land Managers Air Quality Related Values Workgroup 

(FLAG) Report. The results of the cumulative air analysis are described later in this section.

TABLE 4.11.1.3-1

Distance from Downeast LNG Site to Nearby Federal Class I Areas

Class I Area Distance from Project (miles)

Moosehorn Wilderness Area - Baring Unit (MWABU) 8.5

Moosehorn Wilderness Area - Edmunds Unit (MWAEU) 14.8

Roosevelt Campobello International Park (RCIP) 14.4

Acadia National Park 66.2

Prevention of Significant Deterioration

Prevention of Significant Deterioration (PSD) is an emissions permit review process designed to 

ensure that new major sources do not excessively compromise air quality for attainment areas. 

The major source threshold for PSD review for LNG facilities is 250 tpy of any criteria pollutant. 

The PSD major source threshold for GHGs is 100,000 tpy of CO2e. The direct emissions from 

the Downeast LNG Terminal would be above these thresholds, thus the terminal would be 

required to apply for a PSD permit.

 26 Calais LNG previously proposed to construct an LNG import terminal and related natural gas facilities (Calais 

LNG Project) by the St. Croix River in Washington County, near the city of Calais, Maine. This project would 

include a 20.7-mile-long natural gas pipeline to connect the LNG terminal with M&NE system near Baileyville, 

Maine. The Commission has dismissed the Calais LNG application and the project is no longer considered a 

proposed project. 
4.11 – Air Quality and Noise 4-256

Title V Operating Permit

New major sources are required to obtain a Title V Part 70 operating permit. The Title V Part 70 

permit process is designed to ensure that rules and regulations associated with air emissions are 

adequately followed. If a facility’s PTE exceeds the criteria pollutant (100 tpy) or HAP 

thresholds (10 tpy of any single HAP or 25 tpy of all HAPs), the facility is considered a major 

source. Beginning July 1, 2011, facilities that emit at least 100,000 metric tpy (tonnes) CO2e will 

be subject to Title V permitting requirements. Title V Part 70 requirements apply to the 

Downeast LNG Project because the project is a major source of GHG. 

New Source Performance Standards

The New Source Performance Standards (NSPS) are codified in 40 CFR Part 60. NSPS apply to 

new equipment used in specific source categories. NSPS that could potentially apply to the 

project are discussed below.

Project Feature NSPS Discussion

LNG Storage 

Tanks 

(160,000 m3 

each)

NSPS Subpart Kb applies to new vessels that store volatile organic liquids; 

however, vessels that store only methane are specifically excluded from the 

NSPS Subpart Kb requirements. Since the LNG storage tanks would store only 

methane, Subpart Kb requirements do not apply.

Diesel Storage 

Tanks

NSPS Subpart Kb also applies to fuel tanks with a storage capacity greater than 

10,567 gallons. The project would include two diesel storage tanks; however, 

the capacity of these tanks is less than 10,567 gallons; therefore, NSPS Subpart 

Kb requirements do not apply to the diesel tanks.

Submerged 

Combustion 

Vaporizers 

(SCVs)

NSPS Subparts Db and Dc apply to steam generation units. However, an SCV 

that transfers heat to a heat transfer medium by direct contact or intermixing of 

the combustion gases, the heat transfer medium is not considered a steam 

generation unit under Subparts Db and Dc. The project SCVs satisfy this 

exclusion; therefore, NSPS Subparts Db and Dc do not apply.

1,000 kW 

Emergency 

Generator and 

Fire Pumps

EPA promulgated NSPS requirements (Subpart IIII – “Standards of 

Performance for Stationary Compression Ignition Internal Combustion 

Engines”) to reduce emissions of air pollutants from stationary compression 

ignition (CI) internal combustion engines (ICE), such as the 1,000-kW 

emergency generator and the eight emergency fire pumps to be located at the 

LNG terminal. 

The final rule would reduce NOx, PM, SO2, CO, and HC emissions gradually 

from now to year 2015. New stationary diesel engines (those constructed or 

ordered after July 11, 2005) are required to comply with the final rule.

Owners and operators of stationary CI ICE with a displacement of less than 

30 liters per cylinder that use diesel fuel must only use diesel fuel that satisfies 

the requirements of 40 CFR 80.510(b) for nonroad diesel fuel, which requires 

that the diesel fuel have a maximum sulfur content of 15 ppm.
4-257 4.11 – Air Quality and Noise

National Emission Standard for Hazardous Air Pollutants 

The National Emissions Standards for Hazardous Air Pollutants (NESHAPs) are emissions 

standards regulated by the EPA for specific HAPs not included in the NAAQS. NESHAPs are 

established on the basis of source category (source category means the type of industry or 

process that generates the HAPs). A minor HAP emission source emits less than 10 tpy of any 

single HAP and less than 25 tpy of all HAPs combined while a source that exceeds these 

thresholds is designated as a major HAP source. Major HAP sources are subject to Maximum 

Available Control Technology (MACT) standards to minimize HAP emissions.

The EPA has not issued any NESHAPs for LNG projects pursuant to the CAA. However, HAP 

emissions for the LNG terminal and sendout pipeline are well below the major source thresholds. 

Accordingly, MACT standards would not apply to the project. 

General Duty Clause and Risk Management Plan

The General Duty Clause of the CAA states that the owners and operators of a stationary source 

that produces, processes, handles, or stores one or more extremely hazardous substance have a 

general duty to identify the hazards which may result from the release of those hazardous 

substances. In addition, based on appropriate hazard assessment methods, the owners and 

operators must design and maintain a safe facility, ensure adequate prevention methods, and 

minimize consequences in the event an accidental release does occur. These efforts must be 

formalized into a Risk Management Plan (RMP) that is made available to local and state 

agencies and to the public.

In year 2005, the EPA Office of General Counsel clarified in a memorandum that “the language 

of the statute and the legislative history demonstrate that Congress did not intend the general 

duty clause and RMP regulations to apply to LNG facilities to the extent they transport, or store 

incident to transportation, extremely hazardous substances, including methane.” Therefore, the 

requirements of the General Duty Clause and RMP do not apply to the project.

General Conformity

A conformity analysis is required when a federal action will generate emissions exceeding 

conformity threshold levels of pollutants for which an air basin is designated as nonattainment. 

According to Section 176(c)(1) of the CAA (40 CFR Section 51.853), a federal agency cannot 

approve or support activity that does not conform to an approved SIP. At this time, General 

Conformity does not apply to federal actions in Washington County, Maine, which is attaining 

all NAAQS and does not have a maintenance plan. 

Control of Air Pollution from Marine Compression Ignition Engines

The EPA emission control program for marine engines consists of several sets of standards 

which vary based on engine type (gasoline or diesel powered) and size. These standards apply to 

newly manufactured engines installed on vessels that operate under the flag of the United States; 

however, all LNG vessels currently in service are foreign flagged vessels and not subject to this 

regulation. Therefore, the EPA emission control requirements would likely have little effect to 

reduce pollutant emissions associated with LNG vessel activity, but may reduce emissions from 

escort vessels and tugs at the LNG terminal.
4.11 – Air Quality and Noise 4-258

The International Maritime Organization (IMO) is the primary regulatory agency that develops 

regulations for the control of air pollution generated by international marine activities. The IMO 

published the MARPOL in 1973 and modified it in 1978. Since then, the IMO has developed six 

annexes concerned with pollution from maritime vessels. MARPOL Annex VI, “Regulations for 

the Prevention of Air Pollution from Ships” went into force in May of year 2005. Since that time 

it has been ratified by 53 nations that collectively represent nearly 82 percent of the global 

marine tonnage. Annex VI applies to all ships registered to the nations that have ratified the 

legislation, and ships that operate in waters controlled under the jurisdiction of nations that have 

ratified the legislation. On October 10, 2008, the IMO issued a revised Annex VI, which 

includes restrictions on the sulfur content of marine fuels. For territorial waters off the United 

States, the current maximum sulfur content of fuel is 4.5 percent, which is applicable until 2012. 

In 2012, the maximum sulfur content is 3.5 percent and in 2020 the sulfur content is restricted to 

0.5 percent. MARPOL Annex VI was adopted by the U.S. Government on July 21, 2008 and 

Downeast and associated LNG vessels would be required to comply with the Annex VI emission 

standards. 

In March 2010, the IMO designated specific areas of our coastal waters as part of an Emission 

Control Area (ECA). The proposed ECA would extend 200 nautical miles from the coastal 

baseline. EPA has estimated this new ECA designation will lead to a 96 percent reduction in 

sulfur in marine fuels and reduce particulate matter and NOx emissions by 85 percent and 

80 percent, respectively. To achieve these reductions, vessels must use fuel with no more than 

1,000 parts per million (ppm) sulfur beginning in 2015, and new vessels will have to use 

advanced emission control technologies beginning in 2016. In the United States and Canada 

combined, the ECA is expected to reduce emissions of NOx by 320,000 tons, PM2.5 by 90,000 

tons, and SOx by 920,000 tpy, which is 23 percent, 74 percent, and 86 percent below current 

levels, respectively. 

In June 2009, the EPA proposed more stringent exhaust emission standards for the largest marine 

diesel engines which propel Category 3 engines (these are large engines, greater than or equal to 

30 liters per cylinder). These proposed CAA standards are part of a coordinated strategy to 

address emissions from all maritime vessels which adversely impact air quality in the United 

States.

4.11.1.4 Greenhouse Gas Reporting

On October 30, 2009, the EPA published the final Mandatory Reporting of Greenhouse Gases 

rule, establishing the Greenhouse Gas Reporting Program (GHGRP) codified in Title 40 CFR

Part 98. The GHGRP has required large direct emitters of GHGs, and certain suppliers (e.g., of 

fossil fuels, petroleum products, industrial gases and CO2) to report GHG information annually. 

Subpart W of Title 40 CFR Part 98 applies to petroleum and natural gas systems, including: both 

onshore and offshore petroleum and natural gas production; onshore natural gas processing; 

natural gas transmission compression; underground natural gas storage; and liquefied natural gas 

storage, import and export facilities that emit greater than or equal to 25,000 metric tons of 

GHG, as CO2e, per year. 

Because combustion-related GHG emissions from the Downeast LNG Project operations are 

expected to exceed 25,000 metric tpy, Downeast may be required to comply with all applicable 

requirements of the rule. If actual GHG emissions from the proposed project are equal to or 
4-259 4.11 – Air Quality and Noise

greater than 25,000 metric tpy, Downeast would be required to comply with all applicable 

requirements of 40 CFR Part 98.

State Requirements

The Maine DEP Bureau of Air Quality (BAQ) is the lead air permit authority for the proposed 

LNG project. Any new facility is required to obtain an air quality permit (license) before 

construction is initiated. Facilities can trigger additional review by EPA if emissions exceed the 

major source thresholds listed in 40 CFR Section 52.21. Maine DEP Chapter 375 regulations 

deal with state review to determine compliance with the “no adverse effect to the natural 

environment” standard of the Site Location Law. Chapter 375.1 addresses “No Unreasonable 

Adverse Effect on Air Quality” considerations. Other state requirements for air quality are listed 

below.

Maine DEP BAQ Requirement Description

Chapter 101 Section (2)(B)(1)(f) Visible emission standards

Chapter 101 Section (2)(B)(6) Visible emissions standards (fuel burning sources that 

are restricted to less than 20 percent capacity on an 

annual basis).

Chapter 103 Section (2)(B)(1)(a & b) Particulate emissions standards

Chapter 106 Section (2)(A)(2) Sulfur in liquid fossil fuels

Chapter 115 Section (3)(E)(5)(e) Annual air emission license fees (payment thereof)

Chapter 115 Section (3)(E)(5)(g) Maintain and operate all emission units, air pollution 

control and monitoring systems required by the air 

emission license in a manner consistent with good air 

pollution control practice for minimizing emissions.

Chapter 115 Section (3)(E)(5)(h) Maintain sufficient records to accurately document 

compliance with emission standards and license 

conditions and maintain such records for a minimum of 

six (6) years. The records shall be submitted to the 

Maine DEP upon written request.

Chapter 135 Section (3) Hexavalent chromium particulate emissions standard 

(only if total aggregate chromium concentration in 

distillate oil is in excess of 500 ppm).

Chapter 137 Section (3)(A) File an emission statement (for criteria pollutants) with 

the Maine DEP on an annual basis. 

Chapter 137 Section (3)(C) File an emission statement (for HAPs) with the Maine 

DEP every three years.

Chapter 148 Emissions from Smaller-Scale Electric Generating 

Resources
4.11 – Air Quality and Noise 4-260

Maine DEP BAQ Requirement Description

Chapter 101 Section (2)(B)(4) Visible emissions from a fugitive emission source shall 

not exceed opacity of 20 percent, except for no more 

than five minutes in any one hour period. Compliance 

shall be determined by an aggregate of the individual 

fifteen second opacity observations which exceed 

20 percent in any one hour.

Chapter 115 Section (3)(E)(5)(d) Establish and maintain a continued program of BMPs 

for suppression of fugitive particulate matter during any 

period of construction, reconstruction, or operation 

which may result in fugitive dust, and submit a 

description of the program to the BAQ upon request.

In Maine, dispersion models or analysis of other air quality impacts (visibility, vegetation 

damage, etc.) are required to evaluate a new major source or at a new minor source with a PTE 

that exceeds 50 tpy for SO2, 250 tpy for CO, 25 tpy for PM10, 100 tpy for NO2, 0.6 tpy for lead, 

or 0.2 tpy for total chromium. The level of impact analysis required for smaller sources is 

generally determined by Maine DEP on a case-by-case basis based on various factors, including 

existing air quality levels; the adequacy of proposed stack heights to avoid high impacts on local 

areas; the proximity to Class I areas, integral vistas, or nonattainment areas; the extent to which 

available air quality may be limited due to the consumption of increment by other sources; and 

the availability of existing analytic air model results for similar sources. Maine DEP can also 

require post-construction monitoring if it determines there is a need. 

4.11.1.5 Potential Impacts and Mitigation

4.11.1.5.1 Waterway for LNG Marine Traffic

No LNG vessels would be present during construction; therefore, there are no adverse effects 

anticipated. During operations, LNG vessels would arrive (and egress in reverse order) at the 

terminal through the Head Harbour, Western Passage, and Passamaquoddy Bay. The total 

distance from the seaward Pilot Station to the import terminal berth is 16.6 nautical miles. Pilots 

would board the vessel at the Pilot Station located about 1.5 nautical miles offshore of East 

Quoddy Head.

During normal operating conditions some impact on air quality would occur along the entire 

waterway from the territorial seas to the terminal. We do not know the magnitude of current 

emissions from current ship traffic, thus we cannot quantitatively determine the percentage 

increase in air impacts due to the increase in ship traffic from LNG vessels and support vessels. 

However, the emissions affecting any localized area would be temporary as the LNG tanker and 

support vessels make the transit. The majority of the route is between 1,500 and 3,000 feet from 

the shore. At locations closer than 1,500 feet, residences may smell vessel exhaust odors and 

have short term impacts in excess of the NAAQS and Maine AAQS. At locations farther away, 

the distance would allow for considerable pollutant dispersion/dilution. Thus while we cannot 

quantify the impacts, we do expect a minor decrease in air quality along the waterway. The 

impacts (based upon wind speed, direction, number of LNG tanker support vessels, and fuel 

mixtures) may be considerably above ambient air quality levels, but for very short periods in any 
4-261 4.11 – Air Quality and Noise

one location. Estimated criteria pollutant and GHG emissions from vessel activities are shown in 

table 4.11.1.5.1-1. These emission totals include estimated emissions from inbound transit along 

the waterway, time at berth, outbound transit, and standby diesel generator operations.

TABLE 4.11.1.5.1-1

Criteria Pollutant and Greenhouse Gas Emissions due to Vessel Activity

Associated with Terminal Operations (tons per year)

Emissions Vessels Tugs Escort a/ Total

CO2 7590 1872 58 9521

CH4 0.07 0.2 0.01 0.28

N2O 0.524 0.1 0.002 0.626

CO2e b/ 7748 1907 59 9715

NOx 23.2 22 0.8 46.0

CO 2.9 13.6 0.1 16.6

PM10 0.54 1.3 0.03 1.87

PM2.5 0.24 1.3 0.03 1.57

VOC 0.92 1.2 0.02 2.14

SO2 3.60 1.7 0.05 5.35

a/ One Coast Guard escort vessel per delivery was assumed to estimate potential emissions.

b/ CO2e emissions were calculated using the following global warming potentials: 1 for CO2, 25 for CH4, and 298 for N2O.

CH4 = methane.

4.11.1.5.2 LNG Terminal 

Construction

During construction, a temporary reduction in ambient air quality may result from emissions and 

fugitive dust generated by construction equipment. Fugitive dust emission levels would vary in 

relation to moisture content, composition, and volume of soils disturbed. Fugitive dust and other 

emissions from construction activities generally do not result in a significant increase in regional 

pollutant levels, although local pollutant levels could increase temporarily. Downeast would 

implement dust control measures as necessary during certain construction activities, such as 

transporting soil or rock, trenching, grading, pile driving, and use of access roads. These 

measure would include frequent water applications on access roads and in construction work 

areas; vehicle speed restrictions; use of gravel or asphalt at site exit points to remove dirt from 

tires and tracks; and replanting disturbed areas as soon as possible following construction.

Criteria pollutant and GHG emissions during construction equipment would result from 

combustion of gasoline and diesel fuels, primarily NOx, CO, VOCs, PM10, PM2.5, SO2, and CO2e, 

as well as small amounts of HAPs. 

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 about 30 months from the start of site work. The other terminal 

facilities would be constructed in about 18 months with marine construction taking around 
4.11 – Air Quality and Noise 4-262

6 months. Sendout pipeline construction would take about 9 months. Construction activities that 

may generate air pollutant emissions include: 

• tree and brush removal;

• topsoil removal and storage;

• excavation and backfill;

• roadway construction and maintenance;

• erection of facilities (e.g., tanks, structures, process equipment); and

• construction support (deliveries, portable lights, etc.).

Construction emissions would be produced by:

• heavy duty diesel equipment such as excavators, dozers, and cranes (includes both 

exhaust emissions and fugitive dust emissions);

• delivery vehicles, fuel trucks, water trucks, dump trucks (includes both exhaust emissions 

and fugitive dust emissions);

• marine equipment, such as tugs, other support vessels, and cranes;

• portable engines such as compressors, welders, light tower systems, generators, and pile 

hammers; and

• employee-owned vehicles, both on-site and from inbound commute (includes both 

exhaust emissions and fugitive dust emissions).

We received a comment from the EPA relative to the public health impacts from diesel exhaust. 

As demonstrated in table 4.11.1.5.2-1, the criteria and HAP emissions due to terminal 

construction would be relatively low, and these effects would be distributed over four years. All 

emissions would be only a fraction of the major emission source threshold levels. An estimate of 

the combined GHG emissions from commuter vehicles, on-site vehicles, and diesel-fired 

construction equipment during an assumed 35-month construction period spread over four 

calendar years is shown in table 4.11.1.5.2-2. To address these EPA concerns, prior to the start 

of construction activities Downeast would incorporate contract language (summarized below) to 

address the public health impacts from the diesel exhaust of construction vehicles and 

equipment:

• All motor vehicles and/or construction equipment (both on-highway and non-road) shall 

comply with all pertinent State and Federal regulations relative to exhaust emission 

controls and safety;

• All diesel-powered, non-road construction equipment and generators with engine 

horsepower (hp) of 60 hp and above that are on the project or are assigned to the contract 

for a period in excess of 30 consecutive calendar days, shall (1) operate on Clean Fuels or 

(2) be modified through the installation of Retrofit Emission Control Devices to achieve a 

reduction in the emissions of CO, HC, NOx, and PM10;

• Retrofit Emission Control Devices shall consist of oxidation catalysts, or similar retrofit 

equipment control technology that (1) is included on the EPA Verified Retrofit 
4-263 4.11 – Air Quality and Noise

Technology List and (2) is verified by EPA or certified by the manufacturer to provide a 

minimum emissions reduction of 20 percent PM10, 40 percent CO, and 50 percent HC;

• Clean Fuels shall consist of diesel fuel that (1) can be used without engine modification 

(2) is certified to provide a minimum emissions reduction of 30 percent PM10 and 

10 percent NOx when compared to Number 2 Diesel Fuel, and (3) is included on the 

California Air Research Board Verification List;

• Construction shall not proceed until the contractor submits a certified list of the non-road 

diesel powered construction equipment that will be retrofitted with emission control 

devices or that will use Clean Fuels. The list shall include (1) the equipment number, 

type, make, and contractor or subcontractor name (2) the emission control device make, 

model, and EPA verification number and/or (3) the type and source of fuel to be used;

• The construction contractor shall submit monthly summary reports, update the same 

information stated above, and include certified copies of the Clean Fuel delivery slips for 

the report time period, and note which vehicles received the fuel. The addition or 

deletion of non-road diesel equipment shall be included on the monthly report; and

• Downeast shall require coordination among the contractors and its own onsite 

environmental management to establish appropriate zones to stage diesel powered 

vehicles that await to load or unload material at the contract area. These zones will be 

located where the diesel emissions from the trucks will have minimum impact on abutters 

and the general public. Idle of delivery and/or dump trucks or other diesel powered 

equipment will not be permitted for periods of non-active use and will comply with State 

anti-idle laws.

In addition, blasting activities would be required on certain land portions of the site, especially to 

develop roadway access to the marine receiving terminal and to prepare for construction of the 

slab foundations for the LNG tanks. Blasting activities would occur in the first year of 

construction but would generally be performed in a manner to minimize dust emissions. For this 

reason, air emissions of PM10 and PM2.5 from blasting activities are expected to be minimal.

Fugitive dust generation would be primarily a function of the area of construction, silt and 

moisture contents of the soil, wind speed, frequency of precipitation, amount of vehicle traffic, 

vehicle types and paved roadway characteristics. Fugitive dust may be produced during all 

phases of construction. Emissions would be greater over the first 12 months and in areas of finetextured soils. If nuisance conditions result from fugitive dust generated by construction 

activities, Downeast would prepare a dust control plan to minimize dust generation. Ground 

surfaces would be watered as necessary to minimize generation of fugitive dust. No dredging 

activities are proposed. An off-site concrete batch plant would provide the entire concrete 

requirements of the land-side construction and a portion of the marine terminal requirements. 

The remainder of the marine construction requirements would be satisfied by concrete from 

other sources and transported by barge. Emissions from the off-site plants are not considered 

part of the terminal construction emissions. 
4.11 – Air Quality and Noise 4-264

TABLE 4.11.1.5.2-1

Estimated Criteria and HAP Emissions from LNG Terminal Construction

Year a/ Emission Category

Total Emissions of Category (tpy)

NOx VOC CO SO2 PM10 PM2.5

Total 

HAPs

One Construction Equipment b/ 27.48 1.48 9.20 0.02 1.34 1.30 1.01

Commute/Delivery Vehicles 0.19 0.09 1.38 0.00 0.01 0.00 0.03

On-site Vehicle Engines 0.28 0.05 0.66 0.00 0.01 0.01 0.02

Earth Movement Fugitives N/A N/A N/A N/A 7.84 2.11 N/A 

On-site Wind Erosion N/A N/A N/A N/A 0.71 0.11 N/A 

On-site Vehicle Re-suspended PM N/A N/A N/A N/A 27.52 2.97 N/A 

Total 27.95 1.62 11.25 0.03 37.42 6.48 1.06

Two Construction Equipment b/ 45.29 2.74 10.74 0.04 1.88 1.82 1.64

Commute/Delivery Vehicles 0.84 0.64 9.95 0.01 0.03 0.02 0.21

On-site Vehicle Engines 0.34 0.05 0.64 0.00 0.01 0.01 0.02

Earth Movement Fugitives N/A N/A N/A N/A 1.18 0.26 N/A 

On-site Wind Erosion N/A N/A N/A N/A 0.774 0.12 N/A 

On-site Vehicle Re-suspended PM N/A N/A N/A N/A 13.80 1.40 N/A 

Total 46.47 3.42 21.34 0.05 17.68 3.62 1.87

Three Construction Equipment b/ 44.02 2.39 9.10 0.04 1.53 1.49 1.59

Commute/Delivery Vehicles 0.75 0.59 9.49 0.01 0.03 0.02 0.20

On-site Vehicle Engines 0.26 0.05 0.59 0.00 0.01 0.01 0.01

Earth Movement Fugitives N/A N/A N/A N/A 1.18 0.26 N/A 

On-site Wind Erosion N/A N/A N/A N/A 0.12 0.02 N/A 

On-Site Vehicle Re-suspended PM N/A N/A N/A N/A 11.55 1.17 N/A 

Total 45.03 3.02 19.18 0.05 14.43 2.95 1.80

Four Construction Equipment b/ 2.19 0.16 0.55 0.00 0.14 0.13 0.08

Commute/Delivery Vehicles 0.10 0.05 0.72 0.00 0.00 0.00 0.02

On-site Vehicle Engines 0.07 0.02 0.22 0.00 0.00 0.00 0.01

Earth Movement Fugitives N/A N/A N/A N/A 0.00 0.00 N/A 

On-site Wind Erosion N/A N/A N/A N/A 0.02 0.00 N/A 

On-site Vehicle Re-suspended PM N/A N/A N/A N/A 3.30 0.33 N/A 

Total 2.36 0.22 1.48 0.00 3.45 0.47 0.10

a/ We have used the schedule Downeast provided in its application to estimate construction emissions. 

b/ Construction equipment includes offshore marine vessels and equipment.
4-265 4.11 – Air Quality and Noise

TABLE 4.11.1.5.2-2

Estimated Greenhouse Gas Emissions from Terminal Construction

Greenhouse Gas

Terminal Construction

(Years One- Four)

(tpy)

CO2 12,437

CH4 0.67

N2O 0.31

Total Emissions in CO2 equivalence 12,545

Operation

The main source of emissions during operations at the LNG terminal would be from the three 

SCVs that would operate on a regular basis. The fourth SCV is a backup. All other emissions 

due to LNG terminal operation would be from maintenance activities or potential emergency 

conditions. As shown in table 4.11.1.5.2-3, estimated criteria pollutant emissions would be well 

below the threshold of a major source. Combined HAP emissions are 3.1 tpy, and the maximum 

single HAP emission is 3 tpy (hexane); therefore, MACT is not required. Estimated GHG

emissions are shown in table 4.11.1.5.2-4.

TABLE 4.11.1.5.2-3

Criteria Pollutant Emissions due to LNG Terminal Operations (Stationary Sources Only)

Emission Unit(s) Number

of Units

PTE (tpy)

NOx CO PM10 PM2.5 VOC SO2

Submerged Combustion Vaporizers (SCVs) 4 61.2 50 2.4 2.4 13.2 1.2

1,000-kW Emergency Generator 1 3.88 0.09 0.02 0.02 0.04 0.13

Diesel Fire Pump 1 0.73 0.02 0.00 0.00 0.06 0.01

Seawater Fire Pump 7 5.08 0.14 0.03 0.03 0.41 0.06

Emergency Venting 1 -- -- -- -- 3 --

Total 70.9 50.3 2.5 2.5 16.7 1.4

TABLE 4.11.1.5.2-4

Estimated Greenhouse Gas Emissions due to LNG Terminal Operations (Stationary Sources Only)

Emissions Unit Number

of Units CO2 NH4 N2O CO2e

Submerged Combustion Vaporizers (SCVs) 4 197,500 3.3 3.3 198,600

1,000-kW Emergency Generator 1 401 0.02 0.00 402

Diesel Fire Pump 1 27 0.00 0.00 27

Seawater Fire Pump 7 188 0.01 0.00 189
4.11 – Air Quality and Noise 4-266

Vessel Emissions

During operation of the LNG terminal one LNG vessel could arrive every five to seven days in 

the winter, and one vessel could arrive every eight to ten days in the summer. The entire 

sequence from arrival to departure would last around 21 hours. The LNG vessel would use 

onboard pumps to transfer LNG to the storage tanks on land. Maximum expected time to unload 

the LNG is about 13 hours. Anticipated vessel emissions associated with terminal operations are 

presented in table 4.11.1.5.1-1. Vessel emissions would be generated by the travel of the LNG 

import vessel, three or four tugs, and an unspecified number of escort vessels within the 

safety/security zone. Emissions in the fixed zone (vessel moored) would be generated by the 

LNG import vessel, one standby tug as the cargo is unloaded, and one escort vessel to enforce 

the fixed zone. These emissions are considered secondary and are thus not included in the PTE 

for the LNG terminal permit. Estimated criteria pollutant and GHG emissions from vessel 

activities are shown in table 4.11.1.5.1-1. These emission totals include estimated emissions 

from time at berth and standby diesel generator operations while at berth, as well as inbound and 

outbound transit along the waterway.

4.11.1.5.3 Sendout Pipeline 

Construction

The Downeast LNG Project would include construction of a 29.8-mile, 30-inch-diameter 

pipeline that would extend from the project site to the M&NE Baileyville Compressor Station at 

Baileyville, Maine. Pipeline construction would extend over two years with the most

construction taking place during the first year. Construction activities that may generate air 

pollutant emissions include:

• tree and brush removal;

• topsoil removal and storage;

• excavation, backfill, and compaction; and

• support activities (e.g., water and fuel deliveries). 

Pipeline construction emissions would be produced by:

• heavy equipment exhaust;

• light equipment and pick-up truck exhaust;

• delivery vehicle exhaust;

• worker-owned vehicle exhaust;

• fugitive particulate generated by earth-movement activities; and

• fugitive particulate generated by vehicle tires on unpaved surfaces.

Small amounts of air pollutant emissions from worker and delivery vehicle use on public 

roadways would also be attributable to the construction project. The coating of the pipeline 

welds would utilize a heat-shrinkable sleeve which produces VOC emissions, but the quantities 

are negligible. Ground surfaces would be watered to minimize generation of dust. Estimates of 

annual criteria and HAP emissions due to sendout pipeline construction are shown in

table 4.11.1.5.3-1. We received a comment from the EPA relative to the public health impacts 
4-267 4.11 – Air Quality and Noise

from diesel exhaust. As table 4.11.1.5.3-1 shows, all anticipated emissions from pipeline 

construction would be only a fraction of the PSD major emission source threshold levels. 

Nevertheless, we encourage Downeast to use new equipment, retrofit existing equipment, and/or 

use clean fuels to reduce diesel emissions. An estimate of the combined GHG emissions from 

pipeline construction activities during the two-year construction period is shown in 

table 4.11.1.5.3-2.

TABLE 4.11.1.5.3-1

Estimated Emissions from Construction of Sendout Pipeline in Washington County, Maine

Year a/ Emission Category

Total Emissions of Category (tpy)

NOx VOC CO SO2 PM10 PM2.5 Total HAPs

One Construction Equipment 116.1 5.63 35.9 0.10 5.33 5.17 4.33 

Worker's Vehicles 0.62 0.45 7.01 0.01 0.02 0.01 0.16 

Off-Road and Mobile Vehicle Fugitives 0.00 0.00 0.00 0.00 8.31 1.02 0.00 

Materials Handling Fugitive Emissions 0.00 0.00 0.00 0.00 2.29 1.68 0.00 

Total 116.70

6.09 42.9 0.11 16.0 7.88 4.48 

Two Construction Equipment 15.9 0.89 4.40 0.01 0.81 0.79 0.60 

Worker's Vehicles 0.07 0.05 0.82 0.00 0.00 0.00 0.02 

Off-Road and Mobile Vehicle Fugitives 0.00 0.00 0.00 0.00 3.06 0.40 0.00 

Materials Handling Fugitive Emissions 0.00 0.00 0.00 0.00 0.51 0.30 0.00 

Total 15.9 0.94 5.22 0.01 4.39 1.49 0.62 

a/ We have used the schedule Downeast provided in its application for the purposes of estimating construction emissions.

TABLE 4.11.1.5.3-2

Estimated Greenhouse Gas Emissions from Pipeline Construction Activities (tons)

Greenhouse Gas Pipeline Construction

(Years One and Two)

CO2 12,900

CH4 0.72

N2O 0.33

Total Emissions in CO2 equivalence 13000

Operation

The main source of emissions during operation of the 29.8-mile-long sendout pipeline would be 

due to fugitive pipeline emissions (very minor leakage) at pipe valves and connections. These 

emissions would be small and would be distributed over a large area, and are therefore 

negligible.
4.11 – Air Quality and Noise 4-268

4.11.1.5.4 Operational Regional Air Quality Impact

To determine the impact on local and regional air quality in the area, as well as to determine the 

impacts to Class I areas, the EPA-approved AERMOD air quality dispersion model was applied 

to evaluate air quality impacts attributable to:

• the Downeast LNG Project stationary emission sources and related maritime vessel 

emissions; and 

• combined emissions from the Downeast LNG Project operations, Domtar Paper Plant 

operations, and potential operations at the previously proposed Calais LNG facility. 

Downeast consulted with the Maine DEP, the NPS, and the FWS to coordinate the technical 

approach for the Class I air modeling evaluation and receive guidance on the impact evaluation 

for nearby Class I areas (RCIP, MWABU, and MWAEU). At the request of the NPS, St. Croix 

Island, located near the town of Calais on the St. Croix River, an International Historic Site 

managed by the NPS, was also evaluated. The guidance from the Maine DEP/NPS/FWS 

consultations was incorporated into the Class I air modeling evaluation.

Model inputs for the Domtar Paper Plant sources were provided by Maine DEP. Model inputs 

for the Calais LNG facility were extracted from the AERMOD model input files that Calais LNG 

provided to Maine DEP as part of their minor source air emissions license application submitted 

in January 2010. For conservatism, all four of the planned SCVs at the Downeast LNG facility 

were assumed to operate continuously (8760 hours per year), even though one of the SCVs is a 

standby unit and the other three units would not operate continuously. Estimated annual 

emissions from the Downeast LNG Project operations and associated vessel activities are shown 

in table 4.11.1.5.5-1. Estimated annual emissions associated with the previously proposed Calais 

LNG and Domtar facilities are shown in tables 4.11.1.5.5-2 and 4.11.1.5.5-3, respectively.

TABLE 4.11.1.5.5-1

Estimated Annual Emissions from Downeast LNG Terminal Operations and Associated Vessel Activities

Pollutant

Terminal 

Operations 

(tpy)

Vessel Activities 

(tpy)

Total

(tpy)

Portion from

Vessel Activities

CO 50.3 16.6 66.9 24.8%

NOx 70.9 46.0 117 39.3%

PM10 2.5 1.87 4.37 42.8%

PM2.5 2.5 1.57 4.07 38.6%

SO2 1.4 5.35 6.75 79.3%

VOC 16.7 2.14 18.8 11.4%
4-269 4.11 – Air Quality and Noise

TABLE 4.11.1.5.5-2

Estimated Annual Emissions from Calais LNG Terminal Operations and Associated Vessel Activities

Pollutant

Terminal 

Operations 

(tpy)

Vessel Activities 

(tpy)

Total

(tpy)

Portion from

Vessel Activities

CO 84.2 13.6 97.8 13.9%

NO2 147 152 299 50.9%

PM10 22.1 6.1 28.2 21.5%

PM2.5 22.1 6.1 28.2 21.5%

SO2 1.9 55.8 57.7 96.8%

VOC 16.6 5.2 21.8 23.9%

TABLE 4.11.1.5.5-3

Estimated Annual Emissions from Domtar Operations

Pollutant Plant Operations (tpy)

CO 8,070

NOx 1,710

PM10 756

PM2.5 756

SO2 3,560

For all areas outside Class I areas, the air quality evaluation is simply a comparison of the 

predicted pollutant concentrations against the Maine AAQS and the NAAQS to ensure the 

emissions would not cause (or contribute to) an exceedance of these standards. For Class I areas, 

the increase in regional pollutant concentrations are compared to significant impact levels (SILs). 

Ambient pollutant concentration increases below the SILs are not considered to be significant, 

and those that exceed the SILs may require further analysis or mitigation. SILs for this 

assessment are listed in table 4.11.1.5.5-4.

TABLE 4.11.1.5.5-4

Significant Impact Levels (μg/m3

)

Average NO2 PM10 PM2.5 SO2

3-Hour NA NA NA 0.48

24-Hour NA 0.27 0.08 0.07

Annual 0.03 0.08 0.04 0.03

An evaluation was also performed, in cooperation with guidance from the Federal Land 

Manager, to determine the impact on Air Quality Related Values (AQRVs) at the nearby Class I 

areas. AQRVs are resources sensitive to air quality and include a wide array of vegetation, soils, 

water, fish and wildlife, and visibility. The AQRV evaluation includes:
4.11 – Air Quality and Noise 4-270

• a deposition evaluation in which nitrogen and sulfur deposition rates are compared to the 

Deposition Analysis Thresholds (DATs); and

• a visibility evaluation in which plume visibility is measured in terms of perceptibility 

based on color contrast (Delta-E) and a spectral, green wavelength plume contrast 

criterion.

NO2 and SO2 deposition impacts in a Class I area are acceptable if they are less than 

0.01 kilogram per hectacre per year. Visibility impacts are acceptable if emissions do not cause 

a short term (one hour) visible plume where the color change (designated as delta-E) exceeds 

2.0, and the absolute value of the spectral, green wavelength plume contrast remains less than or 

equal to 0.05. Visibility impacts are evaluated with the EPA approved VISCREEN software 

program. VISCREEN analyzes plume transport times up to 12 hours. The potential for visibility 

plume overlap impacts was also evaluated. The results of the air impact and AQRV evaluations 

are tabulated and described below for each geographic area of concern. 

Compliance with Ambient Air Quality Standards - Downeast LNG Terminal 

For areas near the facility not in a Class I area, we have estimated the impacts as shown in 

table 4.11.1.5.5-5. The sum of background pollutant levels and the maximum predicted regional 

pollutant concentrations for Class II areas attributable to the Downeast LNG Project are well 

below the MAAQS and NAAQS. All impacts attributable to the Downeast LNG Project only are 

well below the MAAQS and NAAQS.

TABLE 4.11.1.5.5-5

Air Quality Impacts to Class II Areas Based on Emissions

from Downeast LNG Terminal Operations and Associated Vessel Activities

Pollutant Average

Background 

Concentration 

(μg/m3)

Maximum 

Impact

(μg/m3)

Background + 

Impact

(μg/m3)

MAAQS/NAA

QS (μg/m3) Exceedance

CO 1-Hour 4568 417.2 4985 40,000 No

CO 8-Hour 43.8 2284 2328 10,000 No

NO2 1-Hour 47.0 77.6 124.6 188 No

NO2 Annual 11.0 5.9 16.9 100 No

SO2 1-Hour 33.0 2.0 35.0 195 No

SO2 3-Hour 24.0 1.7 25.7 1,150 No

SO2 24-Hour 13.0 0.7 13.7 230 No

SO2 Annual 5.0 0.1 5.1 57 No

PM10 24-Hour 42.0 1.5 43.5 150 No

PM10 Annual 10.0 0.3 10.3 40 No

PM2.5 24-Hour 18.6 1.5 20.1 35 No

PM2.5 Annual 5.7 0.3 6.0 15 No
4-271 4.11 – Air Quality and Noise

Impacts to Class I Areas – Downeast LNG Terminal

Table 4.11.1.5.5-6 shows the maximum predicted increase in ambient pollutant concentrations at 

nearby Class I areas for comparison with SIL, based on estimated Downeast LNG Project 

emissions only. All impacts are below the SILs except for the annual NO2 impact at MWABU. 

It is important to note that although the annual NO2 SIL is exceeded by 23 percent, the prediction 

was made using all 4 SCVs instead of just the 3 that would be operating, and this should 

decrease the magnitude of emissions by 25 percent. Because only three SCVs would be operated 

simultaneously, and less than continually throughout the year, it is likely that the predicted 

impact would be less than the SIL if the actual SCV emissions were used as an input to the 

model. As stated previously while St. Croix Island is not a listed Class I area, NPS requested 

that it be treated as such to determine the air quality impacts on the site. Air quality impacts on

Class I areas due to the Downeast LNG Project operations would not be significant. 

TABLE 4.11.1.5.5-6

Comparison of Air Quality Impacts to SILs for Nearby Class I Areas Based on Emissions

from Downeast LNG Terminal Operations and Associated Vessel Activities

Pollutant Average SIL

(μg/m3)

Maximum Class I Impact (μg/m3)

MWABU MWAEU RCIP St. Croix Island

NO2 Annual 0.03 0.037 0.02 0.02 0.029

SO2 3-Hour 0.48 0.18 0.13 0.11 0.1

SO2 24-Hour 0.07 0.02 0.02 0.01 0.01

SO2 Annual 0.03 0.001 0.0003 0.001 0.001

PM10 24-Hour 0.27 0.06 0.04 0.04 0.03

PM10 Annual 0.08 0.002 0.001 0.001 0.002

PM2.5 24-Hour 0.08 0.06 0.04 0.04 0.03

PM2.5 Annual 0.04 0.002 0.001 0.001 0.002

Impacts from Nitrogen and Sulfur Deposition on Class I Areas – Downeast LNG Terminal

Table 4.11.1.5.5-7 shows the predicted nitrogen and sulfur deposition levels at nearby Class I 

areas for comparison with DATs (based on Downeast LNG Terminal only). All predicted 

deposition rates are below the DATs except for nitrogen deposition at St. Croix Island, which 

exceeds the DAT by only five percent. It is important to note that although the DAT is 

exceeded, the result is based on the continuous operation of four SCVs. Because only three 

SCVs would be operated simultaneously, and they would not be operated continually throughout

the year, the magnitude of emissions would be about 25 percent less. Therefore, it is likely that 

the predicted deposition rate would be less than the DAT if the actual SCV emissions were used 

as an input to the model. Therefore we conclude that deposition impacts on nearby Class I areas

at St. Croix Island due to the Downeast LNG Project operations would not be significant.
4.11 – Air Quality and Noise 4-272

TABLE 4.11.1.5.5-7

Deposition Impacts at Nearby Class I Areas Attributable to Downeast LNG Terminal Operations

and Associated Vessel Activities

Parameter DAT

(kg/ha/yr)

MWABU

(kg/ha/yr)

MWAEU

(kg/ha/yr)

RCIP

(kg/ha/yr)

St. Croix Island

(kg/ha/yr)

Nitrogen Deposition 0.010 0.0020 0.0010 0.0060 0.0105

Sulfur Deposition 0.010 0.0001 0.0001 0.0002 0.0004

Visibility Impacts on Class I Areas – Downeast LNG Terminal

Table 4.11.1.5.5-8 shows the visibility impacts on nearby Class I areas for comparison with 

visibility impact threshold levels (Delta-E ≤ 2 and Spectral, Green Wavelength Contrast Level 

≤ 0.05). All predicted visibility values are below the acceptable threshold levels and would not 

be a significant impact on visibility at Class I areas and St. Croix Island.

TABLE 4.11.1.5.5-8

Visibility Impacts at Nearby Class I Areas Attributable to Downeast LNG Terminal Operations

and Associated Vessel Activities

Sensitive Area

Delta-E from LNG 

Terminal Stationary 

Emissions (%)

Delta-E from Maritime 

Transit Emissions (%)

Spectral, Green 

Wavelength Contrast 

Level from LNG 

Terminal Stationary 

Emissions (%)

Spectral, Green 

Wavelength Contrast 

Level from Maritime 

Transit Emissions (%)

MWABU 0.419 0.178 -0.002 -0.001

MWAEU 0.224 0.155 0.001 0.001

RCIP 0.519 0.504 -0.003 0.002

St. Croix Island 0.946 0.509 -0.004 0.002

Compliance with Ambient Air Quality Standards – All Regional Sources

Table 4.11.1.5.5-9 shows the maximum predicted air quality impacts based on emissions from all 

potential regional sources including Downeast LNG, the previously proposed Calais LNG

project, and Domtar. As shown, the maximum impacts would violate the one hour standards for 

NO2 and SO2; however, the air impact analysis reveals that 93 percent of the one hour NO2

impact and more than 99 percent of the SO2 impacts are attributable to emissions from other 

regional sources (not Downeast LNG).

TABLE 4.11.1.5.5-9

Maximum Air Quality Impacts Based on Emissions from All Regional Sources

(Downeast LNG, Calais LNG, Domtar)

Pollutant Average

Background

Concentration 

(μg/m3)

Maximum 

Impact

(μg/m3)

Background 

+ Impact 

(μg/m3)

MAAQS/NAAQS 

(μg/m3) Exceedance

CO 1-Hour 4,568 1,603 6171 40,000 No

CO 8-Hour 2,284 362 2646 10,000 No
4-273 4.11 – Air Quality and Noise

TABLE 4.11.1.5.5-9

Maximum Air Quality Impacts Based on Emissions from All Regional Sources

(Downeast LNG, Calais LNG, Domtar)

Pollutant Average

Background

Concentration 

(μg/m3)

Maximum 

Impact

(μg/m3)

Background 

+ Impact 

(μg/m3)

MAAQS/NAAQS 

(μg/m3) Exceedance

NO2 1-Hour 47 1,199 1246 188 Yes

NO2 Annual 11 10.4 21 100 No

SO2 1-Hour 33 778 811 195 Yes

SO2 3-Hour 24 383 407 1,150 No

SO2 24-Hour 13 52 65 230 No

SO2 Annual 5 2.2 7 57 No

PM10 24-Hour 42 10.8 53 150 No

PM10 Annual 10 0.8 11 40 No

PM2.5 24-Hour 18.6 10.8 29 35 No

PM2.5 Annual 5.7 0.8 7 15 No

Table 4.11.1.5.5-10 through table 4.11.1.5.5-13 show the maximum predicted air quality impacts 

on the four nearby Class I areas based on emissions from all regional sources (Downeast LNG, 

previously proposed Calais LNG, and Domtar). The combined emissions from these sources 

would not cause or contribute to a violation of an air quality standard at any nearby Class I area.

TABLE 4.11.1.5.5-10

Maximum Air Quality Impacts at the MWABU Based on Emissions

from All Regional Sources (Downeast LNG, Calais LNG, Domtar)

Pollutant Average

Background

Concentration 

(μg/m3)

Maximum 

Impact

(μg/m3)

Background + 

Impact 

(μg/m3)

MAAQS/NAA

QS (μg/m3) Exceedance

NO2 1-Hour 47 64.8 111.8 188 No

NO2 Annual 11 0.4 11.4 100 No

SO2 1-Hour 33 45.2 78.2 195 No

SO2 3-Hour 24 26.8 50.8 1,150 No

SO2 24-Hour 13 7.7 20.7 230 No

SO2 Annual 5 0.7 5.7 57 No

PM10 24-Hour 42 1.8 43.8 150 No

PM10 Annual 10 0.2 10.2 40 No

PM2.5 24-Hour 18.6 1.8 20.4 35 No

PM2.5 Annual 5.7 0.2 5.9 15 No

Note: As shown in table 4.11.1.5.5-9, the maximum air quality impacts from CO for all regional sources are below the 

MAAQS/NAAQS; therefore, CO impacts at MWABU are not shown in this table.
4.11 – Air Quality and Noise 4-274

TABLE 4.11.1.5.5-11

Maximum Air Quality Impacts at the MWAEU Based on Emissions

from All Regional Sources (Downeast LNG, Calais LNG, Domtar)

Pollutant Average

Background

Concentration 

(μg/m3)

Maximum 

Impact

(μg/m3)

Background 

+ Impact 

(μg/m3)

MAAQS/NAA

QS (μg/m3) Exceedance

NO2 1-Hour 47 16.4 63.4 188 No

NO2 Annual 11 0.1 11.1 100 No

SO2 1-Hour 33 9.2 42.2 195 No

SO2 3-Hour 24 6 30 1,150 No

SO2 24-Hour 13 1.6 14.6 230 No

SO2 Annual 5 0.2 5.2 57 No

PM10 24-Hour 42 0.5 42.5 150 No

PM10 Annual 10 0.05 10 40 No

PM2.5 24-Hour 18.6 0.5 19.1 35 No

PM2.5 Annual 5.7 0.05 5.7 15 No

Note: As shown in table 4.11.1.5.5-9, the maximum air quality impacts from CO for all regional sources are below the 

MAAQS/NAAQS; therefore, CO impacts at MWAEU are not shown in this table.

TABLE 4.11.1.5.5-12

Maximum Air Quality Impacts at the RCIP Based on Emissions

from All Regional Sources (Downeast LNG, Calais LNG, Domtar)

Pollutant Average

Background

Concentration 

(μg/m3)

Maximum 

Impact

(μg/m3)

Background 

+ Impact 

(μg/m3)

MAAQS/NAAQS 

(μg/m3) Exceedance

NO2 1-Hour 47 38.8 85.8 188 No

NO2 Annual 11 0.2 11.2 100 No

SO2 1-Hour 33 12.3 45.3 195 No

SO2 3-Hour 24 7 31 1,150 No

SO2 24-Hour 13 1.3 14.3 230 No

SO2 Annual 5 0.2 5.2 57 No

PM10 24-Hour 42 0.4 42.4 150 No

PM10 Annual 10 0.04 10 40 No

PM2.5 24-Hour 18.6 0.4 19 35 No

PM2.5 Annual 5.7 0.04 5.7 15 No

Note: As shown in table 4.11.1.5.5-9, the maximum air quality impacts from CO for all regional sources are below the 

MAAQS/NAAQS; therefore, CO impacts at RCIP are not shown in this table.
4-275 4.11 – Air Quality and Noise

TABLE 4.11.1.5.5-13

Maximum Air Quality Impacts at the St. Croix Island Based on Emissions

from All Regional Sources (Downeast LNG, Calais LNG, Domtar)

Pollutant Average

Background 

Concentration 

(μg/m3)

Maximum 

Impact

(μg/m3)

Background 

+ Impact 

(μg/m3)

MAAQS/NAAQS 

(μg/m3) Exceedance

NO2 1-Hour 47 117.5 164.5 188 No

NO2 Annual 11 1.1 12.1 100 No

SO2 1-Hour 33 41.5 74.5 195 No

SO2 3-Hour 24 25 49 1,150 No

SO2 24-Hour 13 5.1 18.1 230 No

SO2 Annual 5 0.4 5.4 57 No

PM10 24-Hour 42 0.8 42.8 150 No

PM10 Annual 10 0.1 10.1 40 No

PM2.5 24-Hour 18.6 0.8 19.4 35 No

PM2.5 Annual 5.7 0.1 5.8 15 No

Note: As shown in table 4.11.1.5.5-9, the maximum air quality impacts from CO for all regional sources are below the 

MAAQS/NAAQS; therefore, CO impacts at St. Croix Island are not shown in this table.

Impacts from Nitrogen and Sulfur Deposition on Class I Areas – All Regional Sources

Table 4.11.1.5.5-14 shows the predicted cumulative nitrogen and sulfur deposition levels at 

nearby Class I areas for comparison with DATs. All predicted deposition rates exceed the 

DATs. However, the evaluation also reveals that emissions attributable to Calais LNG alone 

would yield a sulfur DAT exceedance at St. Croix Island and a nitrogen DAT exceedance at all 

four nearby Class I areas. Emissions from the Domtar pulp mill also contribute to or exceed the 

DATs at some of the areas. The nitrogen deposition rate at St. Croix Island attributable to 

Downeast LNG is more than an order of magnitude below the cumulative nitrogen deposition 

impact. As these Class I areas and St. Croix Island would have an impact in excess of the DATs 

there may be an impact on these Class I areas. St. Croix Island is a national historic site without 

significant wilderness habitat. It is unlikely that deposition should have a significant effect on 

AQRVs for the island. Impacts on the MWABU, MWAEU, and RCIP would be larger and may 

contribute to an adverse impact on AQRVs for the Class I areas. 

TABLE 4.11.1.5.5-14

Deposition Impacts at Nearby Class I Areas Based on Emissions from All Regional Sources

(Downeast LNG, Calais LNG, Domtar)

Parameter DAT

(kg/ha/yr)

MWABU

(kg/ha/yr)

MWAEU

(kg/ha/yr)

RCIP

(kg/ha/yr)

St. Croix Island

(kg/ha/yr)

Nitrogen Deposition 0.010 2.081 0.234 0.229 1.035

Sulfur Deposition 0.010 0.472 0.051 0.075 0.753
4.11 – Air Quality and Noise 4-276

Visibility Impacts on Class I Areas – All Regional Sources

To illustrate the impact of other sources in the region, table 4.11.1.5.5-15 shows the visibility 

impacts at nearby Class I areas based strictly on emissions from Calais LNG. Delta-E visibility 

thresholds are exceeded for each nearby Class I Area. Similarly, table 4.11.1.5.5-16 shows the 

visibility impacts at nearby Class I areas based strictly on emissions from the Domtar facility. 

All of the Delta-E visibility thresholds and spectral contrast thresholds are exceeded for each 

nearby Class I Area.

TABLE 4.11.1.5.5-15

Visibility Impacts at Nearby Class I Areas Attributable to Calais LNG Terminal Operations

and Associated Vessel Activities

Sensitive Area

Delta-E from LNG 

Terminal Stationary 

Emissions (%)

Delta-E from Maritime 

Transit Emissions (%)

Spectral, Green 

Wavelength Contrast 

Level from LNG 

Terminal Stationary 

Emissions (%)

Spectral, Green 

Wavelength Contrast 

Level from Maritime 

Transit Emissions (%)

MWABU 6.6 2.50 -0.029 -0.011

MWAEU 2.7 0.74 -0.012 -0.003

RCIP 2.8 5.54 -0.013 -0.025

St. Croix Island 7.3 18.95 -0.019 0.020

TABLE 4.11.1.5.5-16

Visibility Impacts at Nearby Class I Areas Attributable to Domtar Operations

Sensitive Area Delta-E (%) Spectral, Green Wavelength Contrast 

Level (%)

MWABU 31.8 0.248

MWAEU 7.8 0.061

RCIP 5.9 0.05

St. Croix Island 13.7 0.087

Based on the relative geographic locations of regional sources, only MWAEU and RCIP would 

potentially be affected by plume overlap from stationary sources or vessel transit activities. As 

shown in table 4.11.1.5.5-17, the cumulative impacts would exceed the Delta-E threshold for 

each of these Class I areas. However, at MWAEU, the Downeast vessel transit activities and 

Downeast LNG terminal operations represent only 11 percent and 8 percent of the cumulative 

Delta-E. At RCIP, the Downeast vessel transit activities represent about one-fourth of the 

cumulative Delta-E impact.

TABLE 4.11.1.5.5-17

Cumulative Visibility Impacts at MWAEU and RCIP

Sensitive Area Delta-E (%) Spectral, Green Wavelength Contrast 

Level (%)

MWAEU 3.1 -0.014

RCIP 7.2 0.061
4-277 4.11 – Air Quality and Noise

Although not the primary cause, the Downeast LNG terminal may contribute to a significant 

adverse visibility impact on the Class I areas and St. Croix Island.

Impacts on the Canadian Province of New Brunswick

Downeast modeled air quality impacts in the near field and on nearby Class I areas for 

comparison with National and Maine AAQS. The nearest Canadian land is just across the bay in 

the town of St. Andrews in New Brunswick. Air quality impacts for this area were not 

specifically modeled; however, based on the near field impacts described above, pollutant 

concentrations attributable to the Downeast LNG Project would be well within the Canadian 

National Ambient Air Quality Objectives.

Engineering Controls for Methane Emissions and the Energy STAR Program

The composition of natural gas typically includes between 90 and 95 percent methane. As a part 

of operations at the proposed facilities, small quantities of methane (a greenhouse gas) could be 

released to the atmosphere. Some methane would be intentionally vented to maintain equipment 

safety under abnormal operational conditions, and some would be released through unintentional 

leaks. Various engineering design features would be applied to minimize the potential for 

unintentional methane emissions from the LNG storage tanks, marine facilities, and sendout 

pipeline.

In an effort to mitigate methane emissions from oil and natural gas operations, the EPA 

established the Natural Gas STAR program. This program is a flexible, voluntary partnership 

that encourages oil and natural gas companies — both domestically and abroad — to adopt 

proven, cost-effective technologies and practices that improve operational efficiency and reduce 

methane emissions. The program provides a framework to encourage partner companies to 

implement methane emission reduction technologies and practices and to document their 

voluntary emission reduction activities. Downeast has agreed to join the Natural Gas STAR 

program, and has appointed a Natural Gas STAR Program Implementation Manager responsible 

for the implementation of this voluntary agreement.

In summary, the engineering design of the Downeast LNG terminal would minimize fugitive 

methane emissions. In addition, although the terminal design includes a natural gas vent stack, 

there is no normal mode of operation in which it would be used (i.e. methane would only be 

vented during abnormal or emergency events).

Thus through implementation of construction work practices, the limited duration of construction 

activities, a review of the estimated emissions from construction and operations, and an analysis 

of the modeled air quality impacts from operation of the Downeast LNG terminal, ship emissions 

and other facilities, we do not believe there would be regionally significant impacts on air quality

from construction and operation of the facility.

Potential impact of the project on global GHG emissions is discussed in section 4.13 of this EIS. 
4.11 – Air Quality and Noise 4-278

4.11.2 Noise

4.11.2.1 Background and Noise Standards

Noise would affect the local environment during both the construction and operation of the 

proposed Downeast LNG terminal. At any location, both the magnitude and frequency of 

environmental noise may vary considerably over the course of the day and throughout the week. 

This variation is caused in part by changing weather conditions and the effects of seasonal 

vegetative cover. Two measures used by federal agencies to relate the time-varying quality of 

environmental noise to its known effect on people are the 24-hour equivalent sound level (Leq(24)) 

and the day-night sound level (Ldn). The Leq(24) is the level of steady sound averaged over a 

24-hour period. The Ldn is the Leq(24) with 10 decibels on the A-weighted scale (dBA) added to 

the nighttime sound levels between the hours of 10 p.m. and 7 a.m. to account for the greater 

sensitivity of people to sound during the nighttime hours. For a perspective on how noise is 

perceived by a human listener, a 3 dBA increase is the threshold of the human perceptibility, a 

6 dBA increase is clearly noticeable, and a 10 dBA increase is perceived as a doubling of noise, a 

significant increase to a human listener. 

In 1974, the EPA published Information on Levels of Environmental Noise Requisite to Protect 

Public Health and Welfare with an Adequate Margin of Safety (EPA 1974). This publication 

evaluates the effects of environmental noise with respect to health and safety. The document 

provides information for state and local governments to use in developing their own ambient 

noise standards. The EPA has determined that in order to protect the public from activity 

interference and annoyance outdoors in residential areas, noise levels should not exceed an Ldn of 

55 dBA. 

The FERC has adopted this criterion for new compression and associated pipeline facilities 

(18 CFR 380.12), and it is used here to evaluate the potential noise impact from operation of the 

Downeast LNG terminal. An Ldn of 55 dBA is equivalent to a continuous noise level of 

48.6 dBA for facilities that operate at a constant level of noise. Our guidelines also require that 

new pipeline facilities not result in a perceptible increase in vibration at any noise sensitive area 

(NSA). In addition, a sound level of 55 dBA (Ldn) can be used as a “benchmark noise criterion” 

for assessing the noise impact of temporary or intermittent noise. In addition to noise 

requirements, the Commission requires that LNG import or export terminal operations not result 

in any perceptible increase in vibration.

The Maine DEP Site Location of Development Regulation Chapter 375.10, Control of Noise, 

establishes quantitative noise limits for new projects in Maine such as the Downeast LNG 

Project (Maine DEP 2006b). Under this regulation, hourly sound level limits apply at facility 

property boundaries and at nearby “protected locations.” Protected locations are defined as “any 

location accessible by foot, on a parcel of land containing a residence or approved subdivision..”. 

Protected locations also include schools, state parks, and designated wilderness areas.

The Maine DEP exempts daytime construction noise that occurs between the hours of 7 a.m. and 

7 p.m. or daylight hours, whichever is longer. However, nighttime construction must comply 

with the same nighttime sound level limits as routine operation.

Maine DEP Chapter 375.10, Section B.1 requires consideration of local quantifiable noise 

standards. Under this provision, when a development is located in a municipality that has a 
4-279 4.11 – Air Quality and Noise

quantifiable noise standard, then the Maine DEP is to apply the local noise standard rather than 

the Maine DEP standard. Further, when noise produced by a facility is received in another 

municipality, the quantifiable noise standards of the other municipality must be taken into 

consideration.

Maine DEP noise standards are based on existing ambient sound levels and can be more 

stringent than the FERC requirements. In addition, state noise limits for nighttime periods are 

usually more stringent than daytime limits. The project would operate continuously for 24 hours 

per day. Consequently, to the extent the state limits apply, noise from the LNG project would 

generally be limited by noise standards applicable during nighttime hours.

The Town of Robbinston Land Use and Development Code (Amended March 1995) contains a 

noise standard for Conditional Uses (Section 12) Paragraph B.vi. The Robbinston noise standard 

provides only qualitative criteria for noise. The intent of these criteria is consistent with both the 

FERC and Maine DEP noise limits to protect surrounding noise sensitive land uses from adverse 

noise impact. Consequently, by complying with the FERC and Maine DEP noise regulations, 

the project would meet the intent of the noise control standard established by the Town of 

Robbinston, Maine. A summary of applicable noise standards are presented in table 4.11.2.1-1.

TABLE 4.11.2.1-1

Summary of Applicable Sound Requirements by Agency, Criterion, and Associated Metric

Agency Criterion

(dBA)

Metric

(Leq) Measurement Location / Condition 

FERC 55

48.6

24-hour Ldn

Hourly

Nearby NSA

Nearby NSA

Maine DEP 75

60 a/

50 a/

55 a/

45 a/

Hourly

Daytime Hourly

Nighttime Hourly

Daytime Hourly

Nighttime Hourly

Facility Property Line

Protected Location a/

Protected Location a/

Protected Location with low ambient levels

Protected Location with low ambient levels

Town of Robbinston Not applicable Qualitative Comply with federal and state requirements

a/ The nighttime limits at protected locations apply within 500 feet of sleeping quarters. At distances greater than 500 feet, or 

where no sleeping quarters exist (e.g., school), daytime limits apply during all operating hours.

NSA – Noise sensitive area.

4.11.2.2 Waterway for LNG Marine Traffic

The transit to the proposed LNG terminal passes Campobello Island, Indian Island, Deer Island, 

a number of smaller islands, and the Maine Coast with open water ranging from less than 

1.0 mile in width to over 2.0 miles wide. Much of the shoreline is comprised of wooded hillsides 

and rocky shores meeting the water’s edge. Concentrated development occurs in a few locations 

such as Eastport, Maine, and St. Andrews, New Brunswick. Additional seasonal and year-round 

residential development is found at scattered locations along the length of the transit route.

Ambient noise sources in the vicinity of the marine transit route include natural sounds from 

wind, waves, water currents and flow, marine species and other animals. Man-made underwater 
4.11 – Air Quality and Noise 4-280

noise sources include cargo ships such as those traveling to the Bayside terminal facility north of 

the site, commercial fishing boats, and recreational boats. 

No construction activity would occur along the marine transit route; therefore, there would be no 

impacts during the construction phase with the exception of any construction deliveries via 

barge. During project operation, noise would be produced from the operation of LNG vessels 

during transit to the LNG terminal site. Equipment onboard the LNG vessel includes boilers, 

steam-driven turbines, compressors, pumps, ventilation fans, and hydraulic systems. Of these, 

the ventilation fans are the predominant noise source as the majority of all the other equipment is 

contained within the double-hull vessel, which significantly attenuates the transmission of noise.

Noise generated by LNG vessel traffic along the waterway from the territorial sea to the 

proposed LNG terminal would be similar to noise from other large ships currently using the 

waterway. Downeast prepared a noise assessment for four of the closest points to land along the 

route to verify that the day/night level would not exceed 55 dBA. Assumptions used in this 

assessment included: (1) a vessel speed of 5 knots to provide a worst-case assessment in terms of 

duration of the noise at any point; (2) four accompanying tugs at half power with a noise level of 

79 dBA at 50 feet; and (3) a vessel noise level similar to the tugs. A 30-minute and 1-hour Leq

level was then computed for every 500-foot segment of shoreline on both the United States and 

Canadian sides of the route. Day/night levels were then computed assuming that the transit first 

occurred during the day and again if the transit occurred at night. The results of this analysis are 

presented in table 4.11.2.2-1. The highest day/night level of 51 dBA was predicted for a 

nighttime transit past the east shore of Moose Island at a close-in distance of 600 feet.

TABLE 4.11.2.2-1

Sound Level Estimates During LNG Vessel Transit

Shoreline

Location

Distance from 

Transit Route

Transit

Operation

Combined Sound Level (dBA) During Transit Pass-By

30-Minute Hourly 

LAeq

Day-Night Ldn

Day Event Night Event

East Shore of Moose Island 600 ft LNG Vessel & Tugs 58 55 41 51

Kendall Head 1,300 ft LNG Vessel & Tugs 54 51 37 47

South Shore of Deer Island 1,300 ft LNG Vessel & Tugs 54 51 37 47

North End of Grand Manaan 

Island

1,300 ft LNG Vessel Only 47 44 30 40

Note: Except for transit off the north end of Grand Manaan Island, assumes transit speed of 5 knots with one LNG vessel escorted 

by up to four tugboats.

In the marine environment, increased vessel traffic from the other marine projects in the area 

would result in increased ambient background underwater noise. These cumulative noise levels 

could cause auditory trauma, temporary or permanent loss of hearing sensitivity, habitat 

exclusion, habituation, and disruption of other normal behavior patterns, such as feeding, 

migration, and communication, to marine mammals and sea turtles. However, noise associated 

with the normal operation of additional vessels along the waterway would likely cause an 

insignificant incremental increase in noise impacts. See further discussion of underwater noise 

during project operation in section 4.11.2.3.3.
4-281 4.11 – Air Quality and Noise

4.11.2.3 LNG Terminal

4.11.2.3.1 Ambient Noise

Sound levels in the vicinity of the proposed LNG terminal were monitored for a minimum 

24-hour period to determine existing ambient sound levels at six NSAs and protected locations in 

the vicinity of the project site (figure 4.11-1). A summary of ambient monitoring results are 

presented in this section. 

The primary surrounding land use is rural residential intermixed with undeveloped wooded land 

and commercial or public land uses. Several residential properties are located to the south and 

west of the site, generally along U.S. Route 1. The nearest residences to the proposed LNG 

terminal are along U.S. Route 1 across from the project site. To the south, there are a few 

residences 1,500 feet or more from U.S. Route 1 moving toward the shoreline. These residences 

are over 2,000 feet from the project site. To the northwest, there is a cluster of residential 

properties along Ridge Road near the intersection of U.S. Route 1. There is also a local utility 

station and small retail store in this area. North of the site, several residential properties, a 

church, elementary school, and fire station are located along U.S. Route 1. There are also 

several waterfront homes on Passamaquoddy Bay northeast of the site. 

Existing pre-development sound level readings taken for the Robbinston site are summarized in 

table 4.11.2.3-1. Calculated values are the FERC daytime Leq (7 a.m. to 10 p.m.), nighttime Leq

(10 p.m. to 7 a.m.), and Ldn. The Ldn levels ranged from 39 dBA at monitoring position MP-6 to 

57 dBA at monitoring positions MP-3 and MP-4. The Leq represents the average energy level of 

all sounds present during the measurement period. The one-hour Leq is the parameter specified 

for use by the Maine DEP for establishing pre-development ambient sound levels.

TABLE 4.11.2.3-1

Existing Sound Levels and Noise Limits

Monitoring 

Position

Existing Day-Night Sound Level (Ldn)

Average Nighttime Leq

(7 pm to 7 am) a/

Sound Level Limits (dBA)

At Monitoring 

Position

At Nearby

NSAs a/ FERC Ldn

Maine DEP 

Nighttime b/

MP-1 44 44 32

55 dBA at NSA

(Leq = 48.6)

45

MP-2 48 44 to 57 41 50

MP-3 57 50 to 57 44 50

MP-4 57 48 to 59 47 50

MP-5 52 48 to 59 42 50

MP-6 39 39 31 45

a/ Based on distance from primary traffic noise source (U.S. Route 1 or Ridge Road).

b/ Nighttime limits at a protected location apply within 500 feet of a residence. 
Figure 4.11-1 

Downeast LNG Project

Vicinity Site Map

4-282
4-283 4.11 – Air Quality and Noise

4.11.2.3.2 LNG Terminal Construction Noise Impacts

The proposed LNG terminal would consist of land-based and marine-based facilities that would 

be constructed in parallel. Activities during construction would have the potential to cause noise 

impacts on the surrounding area. Noise associated with most construction equipment would be 

intermittent and all major construction activity would be limited to daytime or daylight hours. 

Marine-Based Facilities

Construction of the pier is expected to be done on an 8 to 12 hours per day (daylight hours) basis 

and last for approximately 16 months. The major marine work would include the following key 

activities: pile construction, dolphin construction, and decking construction. Powered 

mechanical equipment, including marine crafts, and pile-driving hammers may be the principal 

sources of noise during the construction phase of the marine work. Most diesel powered 

construction equipment produces a sound level of 80 to 85 dBA at 50 feet in air. Tugboat levels 

can be as high as 90 dBA in air. During impact type pile driving, the maximum sound levels (in 

air) upon impact range from 105 to 115 dBA at 50 feet.

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 use of a 

vibratory hammer to drive piles, rather than an impact hammer, would reduce noise impacts on 

the surrounding area. In a filing with the Commission on May 3, 2013 Downeast stated that on 

the basis of its current design and engineering, vibratory hammering would be used exclusively 

for pile driving, and committed to using only vibratory hammering for pile driving.

Underwater Noise

Underwater noise from construction of the project may have the potential to affect marine 

mammals in Passamaquoddy Bay. This section describes some of the basic acoustics associated 

with underwater noise along with guidelines of the NOAA Fisheries designed to protect marine 

mammals from “acoustic harassment.” This discussion complements the discussion found in the 

aquatic resources section on marine mammals (section 4.5.2) and endangered and threatened 

species (section 4.6). The hearing capabilities and frequency responses of marine mammals and 

aquatic life vary significantly. The dBA scale for in air sound, which was designed specifically 

for the human ear frequency response, is inappropriate in the analysis of underwater sound. 

NOAA Fisheries has established interim guidelines for what constitutes harassment and acoustic 

takes on marine mammals under the MMPA and the ESA as a result of exposure to 

anthropogenic noise in the marine environment. Two levels of acoustic harassment have been 

defined in the MMPA. The current thresholds are 180 dB re 1 μPa for Level A harassment and 

160 dB re 1 μPa (impulse) and 120 decibels (dB) re 1 microPascal (μPa) (continuous) for Level 

B harassment. Exceedance of these thresholds may result in adverse impacts on marine 

mammals. These criteria are currently undergoing review and are subject to change.

Underwater noise during construction activities could result in temporary behavioral changes of 

birds, fish, and ocean mammals in the immediate area of the active construction. However, due 

to the temporary nature of construction activity, long-term noise impacts are not expected to be 

significant.
4.11 – Air Quality and Noise 4-284

The loudness of underwater sound is dependent on the radiated sound power of the source and 

the propagation and attenuation characteristics of the medium through which the sound passes 

(sea water). Similar to in-air sound, the standard unit of measure for underwater sound is the 

decibel. Because of the different physical properties of air and water, identical sound pressure 

waves in-air and underwater would have different values in the two fluids. Thus, no attempt 

should be made to equate decibel levels reported for water with those in-air, or vice-versa. 

Underwater noise impacts are identified in dB relative to the reference sound pressure level of

1 μPa while in air, decibels are assumed to use the reference sound pressure level of 20 μPa. 

Downeast has filed sound contour maps of the underwater noise impacts along the vessel 

corridor and during terminal construction (see figures 8 through 12 in Appendix Q). The report 

includes estimates of source data terms and an explanation of the acoustic engineering 

methodology used for the calculation of underwater sound propagation and resultant contours. 

Noise contours are provided in Appendix Q. The results of this study are summarized below.

Modeling was completed with a proprietary acoustic model that is used to predict the directional 

transmission loss of a single or multiple sources. 

All data are reported as root mean square (RMS) sound pressure level upon which NOAA 

Fisheries safety radius requirements are based, except for underwater noise generated during pile 

driving, which are reported as both a one second sound exposure level and RMS to properly 

account for this noise source, similar but not exactly the same as the maximum A‐weighted

sound pressure level (LAmax). Results are also summarized in tables in terms of the 95 percent 

radius to received level, including thresholds relevant to NOAA Fisheries criteria for Level A 

and Level B harassment. The 95 percent radius is defined as the radius of a circle that 

encompasses 95 percent of the points whose value is equal to or greater than the threshold value

(meaning that 95 percent of the time the noise within that radius will be equal to or below the 

identified noise level). 

The marine construction activity at the Downeast LNG terminal that would produce underwater 

noise would be primarily from tugboats, operation of barge-mounted equipment, and pile driving 

(vibratory hammering). Neither dredging nor offshore drilling are anticipated at the Downeast 

LNG Project, and as such, has not been evaluated relative to noise impacts. With the exception 

of mooring dolphins, pier construction would use “over the top” method that limits the use of 

tugs and work barges. However, in deeper waters, construction may require the use of tugs and 

barges and these were assumed to ensure worst-case conservative results.

The sound generated by construction vessels would be proportionate to vessel size, speed, engine 

load, and revolutions per minute with broadband source levels driven primarily by propeller 

cavitations, hydrodynamic flow over the hull and hull appendages, and operation of machinery 

onboard. Broadband linear source values were estimated at 185 dB re 1 μPa for a tug movement 

at half speed and 193 dB re 1 μPa for a tug with engines at full load as would occur during 

pushing or pulling operations. Broadband barge source levels were estimated at 175 dB 

re 1 μPa. Source levels were based on field measurements of tug and barge operations during 

construction of a similar project. 

Aside from tug operations, the primary sources of underwater noise during construction of the 

LNG terminal would be the installation of the steel pilings. In a filing with the Commission on 
4-285 4.11 – Air Quality and Noise

May 3, 2013 Downeast stated that on the basis of its current design and engineering, vibratory 

hammering would be used exclusively for pile driving, and committed to using only vibratory 

hammering for pile driving. Underwater noise generated during pile driving would be dependent 

on the length and diameter of the pile and the impact energy exerted by the hammer. The steel 

pilings used in construction of the pier would be 4 feet in diameter, with a wall thickness of 1 

inch. Broadband source values used for the Downeast underwater noise modeling for vibratory

pile driving was 199 dB re 1 μPa, with a source depth of 7 meters at the terminal and 3 meters 

mid-trestle. In reality, sound would radiate from all areas of the pilings. The mid-trestle value is 

a conservative estimate of the depth for an equivalent point source, as losses would be less for a 

source at mid-trestle than one close to the sea floor. The radii for modeled construction 

scenarios are presented in table 4.11.2.3-2. 

TABLE 4.11.2.3-2

Radius of Underwater Noise Levels During Construction

Noise

(dB a/)

Noise Source(s)

Barge at the 

Terminal, 

Barge + Tug 

Mid-Trestle

Vibratory Hammer at the 

Terminal

Vibratory Hammer + Barge MidTrestle

Barge + Vibratory Hammer at the 

Terminal, Barge + Tug MidTrestle

Unmitigated Mitigated Unmitigated Mitigated Unmitigated Mitigated

190 5 m 5 m -- 5 m -- 5 m < 5 m

180 b/ 457 m 11 m < 5 m 11 m < 5 m 455 m 455 m

170 470 m 60 m 14 m 81 m 14 m 457 m 457 m

160 529 m 394 m 63 m 376 m 88 m 522 m 522 m

150 c/ 732 m 1.86 km 409 m 2.4 km 409 m 1.93 km 834 m

140 1.59 km 6.8 km 1.92 km 10.2 km 2.46 km 10.0 km 1.92 km

130 4.5 km 11.7 km 7.5 km 11.0 km 10.3 km 11.7 km 7.49 km

120 d/ 10.5 km 16.0 km 12.4 km 11.3 km 11.1 km 16.0 km 12.4 km

a/ dB referenced to 1 μPa

b/ Level A Harassment

c/ Atlantic sturgeon criterion

d/ Level B Harassment

Example: for the vibratory hammer at the terminal, the maximum noise would be 190 dB re 1 μPa or below within 5 meters of the

hammer, 180 dB between 5 meters and 11 meters, 170 dB between 11 meter and 60 meters, etc.

Radii corresponding to Level A and Level B harassment criteria are identified in table 4.11.2.3-2. 

This distance represents the minimum distance from a given source or activity to a received 

underwater sound level. For example, for the vibratory hammer at the terminal, the maximum 

noise would be 190 dB re 1 μPa or below within 5 meters of the hammer, 180 dB dB re 1 μPa 

between 5 meters and 11 meters, 170 dB re 1 μPa between 11 meters and 60 meters, etc. 

Received sound levels above the 180 decibels dB re 1 μPa on the unweighted scale (dBL) 

NOAA Fisheries criterion would occur during pile driving directly in the water column. Figures 

14 through 17 of Appendix Q present estimated underwater received sound level contour maps 

resulting from unmitigated pile-driving activities.
4.11 – Air Quality and Noise 4-286

In order to minimize underwater noise impacts, Downeast has also analyzed the use of a bubble 

curtain as mitigation, which has been shown to provide a mean 1/3 octave band attenuation in the 

63-6300 Hz range of approximately 10 dB. The derived attenuation values of the bubble curtain 

were applied to the source levels of the vibratory pile driving. The broadband source level for 

vibratory pile driving was reduced from 199 dB re 1 μPa to 187 dB re 1 μPa using the bubble 

curtain. In construction areas where vibratory hammering is used, this reduction would allow for 

corridors of safe passage (where received levels are less than 150 dB re 1 μPa) for Atlantic 

sturgeon in the following areas:

• west of St. Andrews, NB;

• the St. Croix River;

• between St. Andrews and Deer Island, NB; and

• between Deer Island, NB and Eastport, ME.

In addition, as identified in section 4.6.2.2, Downeast has accepted several recommendations 

from NOAA Fisheries to mitigate noise impacts on aquatic species.

Figures 1 through 4 of Appendix Q Addendum present estimated underwater sound level contour 

maps resulting from mitigated pile-driving activities.

Land-Based Facilities

Each LNG storage tank would be built on a reinforced concrete slab foundation supported on 

un-weathered bedrock. Construction of the pier abutment and lower access road would require 

removal of 20 to 35 vertical feet of rock. Where removal of significant thickness of rock is 

required at the project site, controlled drilling and blasting techniques would be utilized. To the 

extent possible, rock would be processed and reused on-site such as to construct the shoreside 

rock barrier around the LNG storage tanks.

Construction of land-based facilities at the LNG terminal, including drilling and blasting, would 

normally occur during daylight hours or between the hours of 7 a.m. to 7 p.m. Construction is 

expected to last for a period of 35 to 36 months.

A variety of construction equipment would be used to construct the proposed facilities. This 

would include earth moving equipment for land clearing, excavation, and grading. Typical earth 

moving equipment, such as loaders, excavators, and bulldozers, generates a sound level of 75 to 

88 dBA at a distance of 50 feet. Equipment used for drilling, hammering or excavation of rock 

have the potential to generate higher sound levels depending upon the specific type of equipment 

used. Areas where bedrock would be removed are located on the east side of the project site, 

which is considerably further away from the nearest NSAs and protected locations (refer to 

figure 4.11-1).

Sound level estimates at the NSAs for general construction of the terminal and for onshore pile 

driving are presented in table 4.11.2.3-3.
4-287 4.11 – Air Quality and Noise

TABLE 4.11.2.3-3

Sound Level Estimates for LNG Terminal Construction Activity

NSA

Distance/Direction from 

Compressor/Blower 

Building (feet)

Typical Construction Activity Pile Driving a/

Hourly Leq Ldn b/ LAmax Hourly Leq c/ Ldn b/

1 NE at 2,850 47 44 75 65 62

2 N at 2,300 47 44 72 62 59

3 NW at 2,100 44 41 64 54 51

4 WSW at 800 54 51 65 55 52

5 S at 1,400 50 47 67 57 54

6 SE at 3,300 42 39 64 54 51

a/ Estimates are for impact pile driving however Downeast has committed to using only vibratory pile driving which would result 

in sound levels below these estimates. 

b/ Based on a construction period of 7 am to 7 pm.

c/ Based on impact noise occurring 10% of the period in one hour.

Noise from pile driving has the potential to exceed the FERC guideline of 55 Ldn and Maine DEP 

hourly noise limits at some nearby locations. In addition, pile driving impacts have a LAmax,

which is the measurement of instantaneous noise. Typical noise metrics, Leq, Ldn, do not capture 

the maximum noise from instantaneous noise. As can be seen in table 4.11.2.3-3, the maximum 

instantaneous noise from pile driving would be from 64 to 75 dBA, which is slightly above the 

level of human speech and at the higher level (above 70 dBA) may have a mild effect on speech 

intelligibility. Sound level estimates shown in table 4.11.2.3-3 are for impact hammer pile 

driving. Downeast has now committed to using only vibratory pile driving, which would result 

in sound levels below those estimated for impact pile driving.

While the noise from standard onshore pile driving would result in high levels, or noise for an 

extended period of time could be significant, Downeast has commited to using a vibratory pile 

driver. This would reduce noise impacts below the level of interference with human speech 

intelligibility. Because of the temporary nature and moderate magnitude noise from pile driving, 

no adverse or long-term effects are anticipated. Noise from pile driving and other construction 

activity may be noticeable at nearby residences, especially during periods of extensive earthwork 

using heavy equipment. Local traffic during the construction phase is also expected to increase, 

along with associated vehicle noise.

The mobile nature of construction noise sources and the continuous manner in which 

construction work must be done makes complete control of construction noise infeasible. 

Downeast would perform major construction activity between the hours of 7 a.m. and 7 p.m., or 

daylight hours, and therefore, would be exempt from relevant state of Maine construction noise 

limits during these hours. Other measures to mitigate construction noise would include 

compliance with federal regulations limiting noise from trucks and portable compressors, and 

ensuring that equipment and sound muffling devices provided by the manufacturer are kept in 

good working condition.
4.11 – Air Quality and Noise 4-288

4.11.2.3.3 LNG Terminal Operation Noise Impacts

During operation of the LNG terminal, sound would be generated by watercraft during berthing 

and de-berthing of LNG vessels, and full operation of the terminal during unloading and 

vaporization of LNG. Section 2.0 of this EIS provides a detailed description of the equipment 

and operations.

Marine-Based Facilities

The primary noise sources at the offshore terminal are the LNG vessels and tugboats that would 

only be used during berthing and de-berthing of LNG vessels. Equipment onboard the LNG 

vessel includes boilers, steam-driven turbines, compressors, pumps, ventilation fans, and 

hydraulic systems. Of these, the ventilation fans are the only noticeable sources of noise since 

all the other equipment is contained within the double-hull vessel which greatly attenuates the 

noise. Salt water ballast tanks surround the engineering spaces and provide a significant level of 

attenuation of the engine noise into the water and air. Similar noise levels would be expected 

from diesel powered vessels because of these isolating tanks. The diesel powered tugs would 

operate at high power levels when pushing or pulling LNG vessels during berthing operations. 

Consequently, the highest sound levels would occur during the berthing process, which is 

expected to occur over a period of approximately 30 minutes. The estimated sound level from a 

single tug operating at full power is 89 dBA at 50 feet. The estimated sound levels at the NSAs 

during the berthing cycle, including four tugboats and one LNG vessel, are presented in 

table 4.11.2.3-4 and illustrated in figures 10 through 12 of Appendix Q. The noise level of the 

LNG vessel during unloading of LNG would be insignificant.

TABLE 4.11.2.3-4

Sound Level Estimates During LNG Vessel Berthing

NSA

Distance/Direction

from LNG Pier

(feet)

Sound Level During Berthing (dBA)

30-Minute Cycle Hourly Leq Ldn

1 WNW at 3,100 48 45 31

2 W at 4,100 45 42 28

3 W at 5,850 37 34 20

4 WSW at 5,700 42 39 25

5 SW at 5,500 42 39 25

6 SSW at 5,500 38 36 22

The sound level for the 30-minute cycle is based on tugs operating at full power for the entire 

30-minute period. During the berthing cycle, there are likely to be intermittent periods of 

operations at less than full power. Although watercraft underway is exempt from Maine DEP 

sound limits, the estimated sound levels during the berthing cycle are at or below the nighttime 

limit of 45 dBA for protected locations in quiet areas.

Operation Underwater Noise Impacts

During terminal operation, underwater noise from the offshore marine facility would be 

produced primarily from the operation of LNG vessels and support vessels (tugboats) during 

transit, and docking/undocking activities. Ambient underwater noise sources in the vicinity of 
4-289 4.11 – Air Quality and Noise

the LNG terminal site include natural sounds from wind, waves, water currents and flow, 

precipitation, and biological noise from marine mammals and other species. Man-made 

underwater noise sources include cargo ships such as those traveling to the Bayside terminal 

facility north of the site, commercial fishing boats and bottom trawlers, and recreational boats. 

Underwater noise generated during facility operation would be principally due to the addition of 

LNG vessel traffic. Transit of LNG vessels to and from the terminal through the Bay of Fundy

would occur along the designated shipping lanes. Downeast expects that transit through the Bay 

of Fundy would be unescorted, but shortly before entering Head Harbour Passage, a pilot and 

four tugs would join the vessel and would assist in docking/undocking operations. Downeast 

expects that three of the tugs would be active during docking/undocking activities, while one 

would remain on standby.

At typical cruising speeds, source sound levels emitted by LNG vessels are dominated by 

propeller cavitation; therefore, factors such as propeller diameter, propeller speed, and number of 

blades impacts the source sound level. The predicted noise for an LNG vessel cruising at halfspeed is 175 dB re 1 μPa. Tugs used for docking/undocking activities would likely be powered 

by two main 3,300 hp diesel engines, equipped with an azimuthal propulsion system. Predicted 

noise for a similar tug operating at half-speed and at maximum load are 185 dB re 1 μPa and 

193 dB re 1 μPa, respectively. Underwater noise associated with the pilot vessel would be 

expected to be negligible in comparison to that generated from the vessel and tugs.

Newer LNG vessels are equipped with bow and/or stern thrusters, which can have highly 

variable sound output. Not all LNG vessels have such thrusters and in most cases the vessel’s 

thrusters would not operate at full power simultaneously with all three tugs at maximum load. 

Use of the LNG’s vessel’s thrusters alone or in combination with tug support is at the discretion 

of the vessel’s captain, in consultation with the attending pilot, and is dependent on the weather 

and sea condition during the berthing of the LNG vessel. For the purposes of the model, three 

tugs operating at high power were included without the addition of the vessel’s thrusters. For 

docking, the vessel was not included at all as its sound would be negligible compared to the tugs. 

Five separate sites were used in modeling project operations to represent the different transit 

routes and docking station potentially used by the LNG vessel and support vessels. Sites 1 and 2 

model the vessel at half speed while in transit through the Bay of Fundy. Sites 3 and 4 model the 

vessel at half speed with four tugs at half speed as they approach Passamaquoddy Bay. 

Modeling Site 5 represents the docking/undocking scenario, which only includes three tugs at 

high power and one tug on standby at half speed. The 95th percentile radii for operational 

scenarios are presented in table 4.11.2.3-5. Radii corresponding to Level A and Level B 

harassment criteria are identified in the table. This table represents the worst-case seasonal and 

tidal conditions. This distance is the linear distance from a given activity at which exceedances 

may occur. For example, for Site 1 LNG Vessel, Transiting, the maximum noise is expected to 

be 160 dB re 1 μPa or below within 5 meters, 150 dB between 5 meters and 18 meters, 

140 dB between 18 meters and 55 meters, etc. Received sound levels above the 180 dBL 

NOAA Fisheries criterion are not likely at any appreciable distance during facility operations.
4.11 – Air Quality and Noise 4-290

TABLE 4.11.2.3-5

Radius of Underwater Noise Levels During Operation

Noise

(dB a/)

Noise Source(s)

Site 1

LNG vessel, 

Transiting

Site 2

LNG Vessel, 

Transiting

Site 3

LNG Vessel + 4 

Tugs, Transiting

Site 4

LNG Vessel + 4 

Tugs, Transiting

Site 5

LNG Vessel + 4 Tugs, 

Docking

190 -- -- < 5 m < 5 m < 5 m

180 b/ -- -- < 5 m < 5 m 10 m

170 < 5 m < 5 m 14 m 14 m 38 m

160 5 m 5 m 41 m 42 m 207 m

150 18 m 18 m 225 m 267 m 700 m

140 55 m 53 m 898 m 814 m 2.0 km

130 312 m 257 m 2.9 km 2.9 km 4.8 km

120 c/ 1.03 km 1.06 km 9.8 km 8.5 km 10.4 km

a/ dB referenced to 1 μPa

b/ Level A Harassment

c/ Level B Harassment

Example: for Site 1 LNG Vessel, Transiting, the maximum noise would be 160 dB re 1 μPa or below within 5 meters , 150 dB 

between 5 m and 18 m, 140 dB between 18m and 55 m, etc.

Sound contour maps showing estimated underwater received sound levels resulting from LNG 

vessels and tugs in transit and during docking/undocking are provided in figures 8 through 13 of 

Appendix Q. Figures 22 and 23 in Appendix Q show estimated underwater received sound 

levels during LNG vessel docking/undocking, accounting for seasonal and tidal variability.

Land-Based Facilities

This section provides estimates of the resulting sound levels at NSAs from operation of the LNG 

terminal. Predicted sound levels are based on full operation of the facility at the peak sendout 

rate during unloading of an LNG vessel and with the design noise mitigation measures installed. 

Noise from other routine operating modes is expected to be at or below these predicted sound 

levels. 

Downeast’s site development plan incorporates several key design elements to mitigate 

environmental impacts such as noise. Primary equipment would be located inside buildings, and 

storage tanks or vessels would contain noise from many of the pumps. Similar noise mitigation 

measures have been installed at other LNG facilities in the United States where sound testing has 

demonstrated that these LNG terminals operate within applicable FERC noise limits. 

Noise levels of LNG terminal equipment are based on equipment and material specifications, 

performance data, measurements of similar equipment at existing LNG facilities, and technical 

literature. 

Sound level estimates of project operation at nearby NSAs and protected locations were 

calculated using the DataKustik CadnaA noise prediction model. Modeling assumptions 

consisted of minimal ground absorption and vertically elevated noise sources to reduce 

attenuation from intervening terrain and buildings or structures. Table 4.11.2.3-6 presents
4-291 4.11 – Air Quality and Noise

estimates of sound levels from the Downeast LNG terminal at nearby NSAs and protected 

locations. The distances found in table 4.11.2.3-6 are measured from the center of the 

compressor/blower building to the locations where noise limits apply based on the FERC and 

Maine DEP noise regulations. Distances to other noise sources such as those operating at the 

unloading platform may vary considerably (refer to figure 4.11-1). Because Maine DEP limits 

apply to the entire parcel containing a residence, distances to protected locations are typically 

less than distances to nearby NSAs where the FERC limits apply. The sound level estimates are 

compared to the FERC and Maine DEP noise limits and show that the LNG project would 

operate below those limits under full load conditions. Day/night sound levels from the terminal 

would range from 38 to 51 dBA at the NSAs.

TABLE 4.11.2.3-6

Sound Level Estimates and Limit Comparison for Peak Sendout at 625 MMscfd

FERC Limit - Ldn = 55 dBA at NSA

NSA

Direction and Distance

(feet) a/

Existing Ldn

at NSA

Ldn from 

LNG Terminal

Future 

Ambient Ldn 

Increase in 

Ambient Ldn

1 NE at 2,850 44 41 46 2

2 N at 2,300 46 43 48 2

3 NW at 2,100 55 44 55 0

4 WSW at 800 52 51 55 3

5 S at 1,400 46 46 49 3

6 SE at 3,300 39 38 42 3

Maine DEP Limits – Hourly Leq at Protected Locations

Protected 

Location

Direction and Distance 

(feet) b/

Estimated Hourly Leq

From LNG Terminal Operation

Maine DEP Sound Level Limits (dBA)

Daytime Nighttime

1 NE at 2,800 35 55 45

2 N at 2,200 37 55 45

3 NW at 1,970 38 60 50

4 WSW at 750 46 60 50

5 S at 1,200 41 55 45

6 SE at 3,300 33 55 55

a/ Distances are from center of compressor/blower building to nearby NSA as defined by FERC.

b/ Distances are from center of compressor/blower building to nearby protected location as defined by Maine DEP.

In addition to sound levels from the LNG project, table 4.11.2.3-6 also provides estimates of 

future ambient sound levels (Ldn) at nearby NSAs and the expected increase above existing 

ambient sound levels. As a result of operations at the LNG terminal, sound levels at nearby 

NSAs are expected to increase from 0 to 3 dBA.

Because the terminal operational noise levels discussed above are estimates, we recommend 

that:

• Downeast should file a full load noise survey with the Secretary no later than 60 

days after placing the Downeast LNG terminal and meter station into service. If a 

full load condition noise survey is not possible, Downeast should file an interim 

survey at the maximum possible load within 60 days of placing the Downeast LNG 

terminal and meter station into service and file the full load survey results with the 
4.11 – Air Quality and Noise 4-292

Secretary within 6 months of the in-service date. If the noise attributable to the 

operation of all the equipment of the Downeast LNG terminal and meter station at 

full operation exceeds 55 dBA Ldn at any nearby NSAs, Downeast should install 

additional noise controls to meet the level within 1 year of the in-service date. 

Downeast should confirm compliance with this requirement by filing a second full 

load noise survey with the Secretary no later than 60 days after it installs the 

additional noise controls. 

A number of the scoping comments received by the Commission indicated stakeholder concern 

about noise from the proposed LNG terminal adversely affecting the existing quality of life of 

area residents. The analyses presented above indicate that adequate measures would be taken in 

all aspects of the project to ensure that the FERC and state of Maine noise standards would be 

met and that there would be no significant noise impact on any residence. Although noise from 

construction activities may be audible at times, they would occur primarily during the day and 

would be temporary in nature. Noise from facility operations would be ongoing but at a lower 

level than construction, and it would generally not be noticeable at most residences. 

4.11.2.4 Sendout Pipeline

Land use along the proposed sendout pipeline right-of-way is primarily existing rights-of-way 

and rural, forested land. Ambient sound was not measured for this assessment, but for this type 

of land use could be generally described as sounds associated with wildlife (animals, birds, and 

insects). Other sounds likely found along the proposed route include occasional vehicles at road 

crossings, and in the winter, occasional sounds from recreational ATVs.

4.11.2.4.1 Pipeline Construction Noise Impacts

Construction of the sendout pipeline is primarily land-based, but would also rely on special 

techniques for crossing waterbodies, roads, railroads, and utilities. Activities during the 

construction phase have the potential to cause noise impacts on the surrounding area. Noise 

associated with most construction equipment would be intermittent and all major construction 

activity would be limited to daytime or daylight hours. 

Pipeline construction would proceed at 100 to 200 feet per day, limiting the duration of noise 

exposure at any single location. In addition, Downeast would require certain mitigation 

measures as follows:

• all construction equipment would be required to be properly maintained and have 

muffling equipment;

• hours of construction activities would generally be limited to normal daylight working 

hours; and

• equipment operations adjacent to residences would be restricted to those specifically 

required for the pipeline installation (i.e., restricted access for vehicular passage along the 

pipeline right-of-way).

Horizontal Directional Drilling

For construction of the sendout pipeline, Downeast is proposing to implement HDDs for 

installation of the pipeline at numerous locations. Using this technology would enable drilling or 

tunneling under certain environmental features to minimize disturbance to residences, 
4-293 4.11 – Air Quality and Noise

waterbodies, wildlife habitat, and other sensitive areas. Figures R-1 through R-12 in 

Appendix R, are a series of aerial plans that identify the planned HDD locations in relation to 

surrounding land uses and NSAs. From entry to exit points, the length of the HDD crossings 

range from approximately 141 feet (HDD Site No. C-37-109-01) to 6,621 feet (1.26 miles) along 

the United States side of the St. Croix River (HDD Site No. C-24-03). The lengths of the HDD 

crossings vary by location as summarized in table 4.11.2.4-1 in relation to pipeline mileposts.

Equipment planned for use at the HDD sites also varies somewhat depending on the length and 

depth of each drill, and subsurface soil and bedrock conditions. For longer HDD crossings with 

deeper bedrock penetration, equipment would include a drill rig, hydraulic crane, mud pump, 

generators, a screening/filter system for drill cuttings, and mobile support equipment. The 

primary HDD equipment would be powered by diesel engines ranging from 150 to 600 hp. The 

majority of equipment would be located on the drill entry site where the total connected power 

would be approximately 1,900 hp. The diesel engines would be mounted on skids or trailers and 

equipped with exhaust mufflers. Equipment requirements may be slightly reduced for shallow 

HDD crossings less than 1,000 feet (e.g., no mud pump at drill exit site).

At most locations, HDD operations would be conducted for 12 hours per day during daytime or 

daylight hours. Due to its extended length and depth, drilling equipment at HDD Site 

No. C-24-03 (St. Croix River) would operate 24 hours per day to improve the likelihood of 

completing a successful drill and reducing the number of days that drilling would be required. 

Drilling may also be conducted during nighttime hours at other sites depending upon subsurface 

conditions. Most HDD crossings would be completed in 15 days or less. The estimated duration 

of the longer crossings ranges from 24 days for HDD Site No. C-29-171 to 75 days for HDD Site 

No. C-24-03. Drilling may require longer durations where an initial drill fails or difficult 

subsurface conditions are encountered. Estimates of the expected number of days for drilling 

operations are provided in table 4.11.2.4-1.

Existing ambient Ldn at NSAs near drill entry and exit sites have been estimated from previous 

ambient sound level monitoring conducted in June 2006 in the vicinity of the proposed terminal 

site in Robbinston, Maine. For each HDD location, the estimated Ldn values have been 

calculated based on the distance of the nearest NSA to U.S. Route 1, which is a prominent 

existing noise source in the vicinity of the proposed pipeline route. 

TABLE 4.11.2.4-1

Location, Estimated Length, and Estimated Duration of HDD Crossings

HDD Site No. Milepost Estimated Length of HDD 

Crossing in Feet

Estimated Duration of HDD 

Activity (Days)

R-09-15 1.2 1,850 23

R-06-03 3.2 850 10

R-03-03 3.6 530 7

R-03-04 4.2 1,270 16

C-37-224 5.1 740 8

C-37-109-01 6.7 210 4

C-33-112 8.6 2,750 31

C-32-97 9.0 630 8
4.11 – Air Quality and Noise 4-294

TABLE 4.11.2.4-1

Location, Estimated Length, and Estimated Duration of HDD Crossings

HDD Site No. Milepost Estimated Length of HDD 

Crossing in Feet

Estimated Duration of HDD 

Activity (Days)

C-32-131 9.2 690 9

C-32-135 9.5 580 7

C-29-147 10.4 690 9

C-29-171 12.0 2,480 25

C-26-14 12.8 740 7

C-24-03 14.6 6,650 75

BP-06-03 18.0 2,480 40

B-11-02 21.3 320 4

B-14-15 24.4 690 9

B-03-14 25.2 2,750 34

B-03-15A1 29.0 1,110 13

B-03-15A2 29.2 1,000 13

B-03-15A3 29.8 690 8

Based on field measurements of similar HDD activity for pipeline construction, the combined 

sound level from the drilling equipment at the entry sites is expected to be no more than 77 dBA 

at 196 feet. For each HDD crossing, sound level estimates from HDD operation have been 

calculated at the nearest residential NSA and the Moosehorn NWR boundary to drill entry and 

exit points. Although sound levels at exit sites may be lower than entry sites, these estimates 

were derived using sound levels for drill entry sites and calculating attenuation due to distance 

and atmospheric absorption. Measured source levels and calculated sound levels at NSAs and 

the Moosehorn NWR boundary are presented in table 4.11.2.4-2. Actual sound levels may vary 

from those presented in table 4.11.2.4-2. In some cases, received sound levels may be less than 

predicted due to additional attenuation provided by intervening terrain and vegetation that has 

not been factored into the calculations.

TABLE 4.11.2.4-2

Estimated HDD Sound Levels at the Nearest NSA and Moosehorn NWR

HDD Site No. Access Point 

Milepost

Distance to NSA 

(ft)

Estimated Sound 

Level at NSA

(dBA) a/

Distance to 

Moosehorn NWR 

(ft)

Estimated 

Sound Level 

(dBA) a/

R-09-15 1.11 –Exit 449 68 > 12,000 <35

1.46 – Entry 105 82 > 12,000 <35

R-06-03 3.09 – Exit 1,348 56 > 12,000 <35

3.25 – Entry 907 61 > 12,000 <35

R-03-03 3.64 – Entry 1,420 56 > 12,000 <35

3.74 – Exit 1,880 52 > 12,000 <35

R-03-04 4.13 – Exit 2,595 47 > 12,000 <35

4.37 – Entry 1,634 54 > 12,000 <35

C-37-224 5.09 – Entry 293 73 > 12,000 <35

5.23 – Exit 470 68 > 12,000 <35

C-37-109-01 6.68 – Entry 5,066 36 > 12,000 <35
4-295 4.11 – Air Quality and Noise

TABLE 4.11.2.4-2

Estimated HDD Sound Levels at the Nearest NSA and Moosehorn NWR

HDD Site No. Access Point 

Milepost

Distance to NSA 

(ft)

Estimated Sound 

Level at NSA

(dBA) a/

Distance to 

Moosehorn NWR 

(ft)

Estimated 

Sound Level 

(dBA) a/

6.72 - Exit 5,183 36 > 12,000 <35

C-33-112 8.30 – Entry 2,555 47 8,200 <35

8.82 – Exit 1,432 56 6,200 <35

C-32-97 8.96 – Exit 1,252 57 5600 <35

9.08 – Entry 1,453 55 5300 35

C-32-131 9.18 – Entry 1,863 52 4800 37

9.31 – Exit 1,544 55 4500 38

C-32-135 9.48 – Entry 688 64 3500 43

9.59 – Exit 231 75 2900 46

C-29-147 10.38 – Exit 644 65 500 67

10.51 – Entry 1,232 57 800 62

C-29-171 11.74 – Entry 3,716 42 3600 42

12.21 – Exit 5,844 <35 1600 54

C-26-14 12.75 – Exit 3,839 41 50 89

12.89 – Entry 3,432 43 50 89

C-24-03 14.08 – Entry 937 61 (Ldn = 67) 700 64 (Ldn = 70)

15.34 – Exit 851 62 (Ldn = 68) 1000 60 (Ldn = 66)

BP-06-03 17.70 –Entry 384 70 250 74

18.17 – Exit 743 63 2200 50

B-11-02 21.26 – Entry 1,228 58 > 12,000 <35

21.32 – Exit 903 61 > 12,000 <35

B-14-15 24.28 – Exit 120 81 > 12,000 <35

24.41 – Entry 197 76 > 12,000 <35

B-03-14 25.06 – Exit 2,719 46 > 12,000 <35

25.58 – Entry 2,331 49 > 12,000 <35

B-03-15A1 28.81 – Exit 5,083 36 > 12,000 <35

29.02 – Entry 5,734 <35 > 12,000 <35

B-03-15A2 29.15 – Exit 6,341 <35 > 12,000 <35

29.34 – Entry 7,252 <35 > 12,000 <35

B-03-15A3 29.68 – Exit 9,634 <35 > 12,000 <35

29.81 – Entry 8,970 <35 > 12,000 <35

a/ Hourly equivalent sound level except at HDD C-24-03, where Ldn is also shown to reflect 24 hour per day drilling.

From measurements of similar HDD operations, estimates show that sound levels within 

approximately 1,500 feet of the drill site would have the potential to exceed 55 dBA. Where 

24-hour drilling is necessary and Ldn sound levels at NSAs are expected to exceed 55 dBA, 

Downeast would reduce noise levels at the NSAs by implementing noise control measures such 

as full or partial equipment enclosures, enhanced exhaust mufflers, and temporary noise barriers. 

These mitigation measures would reduce sound levels from HDD operations up to levels ranging 

from 10 to 15 dBA. To ensure that this mitigation is sufficient, we recommend that:

• Prior to construction of the pipeline facilities, Downeast should file with the 

Secretary, for the review and written approval by the Director of OEP, an HDD 

noise mitigation plan for HDDs R-09-15, C-34-224, C-32-135, C-29-147, C-24-03, 

BP-06-03, and BP-14-15. The plan should identify mitigation measures designed to 
4.11 – Air Quality and Noise 4-296

reduce the noise impacts on the NSAs from HDD activities. During drilling 

operations, Downeast should implement the approved plan, monitor noise levels, 

and make all reasonable efforts to restrict the noise attributable to the drilling 

operations to no more than an Ldn of 55 dBA at the NSAs.

In addition, we recommend that:

• Downeast should file in its weekly construction status reports the following for HDD 

operations that last more than 10 days:

a. the HDD entry point noise measurements from the nearest NSA, obtained at the 

start of drilling operations;

b. the noise mitigation that Downeast implemented prior to the start of drilling 

operations; and

c. any additional mitigation measures that Downeast would implement if the initial 

noise measurements exceeded an Ldn of 55 dBA at the nearest NSA.

By Maine law, construction activity such as HDD work is exempt from the Maine DEP noise 

regulation during daytime (7 a.m. to 7 p.m.) or daylight hours, whichever is longer. Downeast 

would be required to apply noise mitigation to meet Maine DEP noise limits during nighttime 

HDD operations.

Downeast has proposed using HDD to avoid impacts on several residences that are within 50 feet 

of the sendout pipeline construction right-of-way (see section 4.7.2). We have concurred with 

these HDD route variations and require that Downeast conduct noise analyses prior to 

construction to assess the impacts on the NSAs in these locations.

4.11.2.4.2 Pipeline Operation Noise Impacts

The buried pipeline would not contribute to aboveground noise levels. Operational noise 

associated with the sendout pipeline would be limited to the immediate vicinity of the three 

mainline block valves, located at each end of the pipeline and at MP 17.2. Some minor noise 

may be heard immediately around the metering station; however, the meter station is located 

within the LNG terminal site. To ensure that the noise impacts at the NSA near the meter station

do not exceed 55 dBA Ldn, we have included the meter station in our recommendation above 

(see section 4.11.2.3.3) that Downeast file a full load noise survey with the Secretary no later 

than 60 days after placing the Downeast LNG terminal and meter station into service. If the 

noise attributable to the operation of the Downeast LNG terminal and meter station exceeds 

55 dBA Ldn at any nearby NSAs, Downeast should install additional noise controls to meet the 

level within 1 year of the in-service date.

With implementation of the measures proposed by Downeast and our recommendations, impacts 

related to noise during construction and operation would be not be significant at the nearest 

NSAs, sensitive species, or aquatic habitats. In addition, we require that Downeast comply with 

our requirement to ensure that there would be no perceptible vibration at NSAs from operation of 

the LNG terminal. During operation, noise would be negligible, except for the meter station and 

the LNG terminal, which would constitute a minor to moderate long term noise impact.
4-297 4.12 – Reliability and Safety

4.12 RELIABILITY AND SAFETY

4.12.1 Regulatory Agencies

Three federal agencies share regulatory authority over the siting, design, construction and 

operation of LNG import terminals: the Coast Guard, the DOT, and the FERC. The Coast 

Guard regulates the safety of an LNG facility’s marine transfer area and LNG marine traffic, and 

regulates security plans for the entire LNG facility and LNG marine traffic. Those standards are 

codified in 33 CFR 105 and 127. The DOT establishes federal safety standards for siting, 

construction, operation, and maintenance of onshore LNG facilities, as well as for the siting of 

marine cargo transfer systems at waterfront LNG plants. Those standards are codified in 49 CFR 

193. Under the Natural Gas Act and delegated authority from the U.S. Department of Energy 

(DOE), the FERC authorizes the siting and construction of LNG import and export facilities.

In 1985, the FERC and DOT entered into a Memorandum of Understanding regarding the 

execution of each agency’s respective statutory responsibilities to ensure the safe siting and 

operation of LNG facilities. In addition to FERC’s existing ability to impose requirements to 

ensure or enhance the operational reliability of LNG facilities, the Memorandum of 

Understanding specified that FERC may, with appropriate consultation with DOT, impose more 

stringent safety requirements than those in Part 193.

In February 2004, the Coast Guard, DOT, and FERC entered into an Interagency Agreement to 

ensure greater coordination among these three agencies in addressing the full range of safety and 

security issues at LNG terminals, including terminal facilities and tanker operations, and 

maximizing the exchange of information related to the safety and security aspects of the LNG 

facilities and related marine operations. Under the Interagency Agreement, the FERC is the lead 

federal agency responsible for the preparation of the analysis required under NEPA for impacts 

associated with terminal construction and operation. The DOT and Coast Guard, when 

necessary, participate as cooperating agencies.

As part of the review required for a FERC authorization, Commission staff must ensure that all 

proposed facilities operate safely and securely. The design information that must be filed in the 

application to the Commission is specified by Title 18 CFR 380.12 (m) and (o). The level of 

detail necessary for this submittal requires the project sponsor to perform substantial front-end 

engineering of the complete facility. The design information is required to be site-specific and 

developed to the extent that further detailed design would not result in changes to the siting 

considerations, basis of design, operating conditions, major equipment selections, equipment 

design conditions, or safety system designs which we considered during our review process. 

FERC’s filing regulations also require each applicant to identify how its proposed design would 

comply with DOT’s siting requirements of 49 CFR 193, Subpart B. As part of our NEPA 

review, we use this information from the applicant, developed to comply with DOT’s 

regulations, to assess whether or not a facility would have a public safety impact. As a 

cooperating agency, DOT assists FERC staff in evaluating whether an applicant’s proposed 

siting meets the DOT requirements. If a facility is constructed and becomes operational, the 

facility would be subject to DOT’s inspection program. Final determination of whether a facility 

is in compliance with the requirements of 49 CFR 193 would be made by DOT staff.
4.12 – Reliability and Safety 4-298

In accordance with 33 CFR 127, the Coast Guard provided FERC with an LOR regarding the 

suitability of the waterway for LNG carrier traffic. Section 4.12.7 includes the results of the 

Coast Guard’s review on waterway suitability.

4.12.2 Hazards

The principal hazards associated with the storage and vaporization of LNG result from loss of 

containment, vapor dispersion characteristics, flammability, and the ability to produce damaging 

overpressures. A loss of the containment provided by storage tanks, process piping, or

equipment (pumps, vaporizers, etc.) would result in the formation of flammable vapor near the 

release location, as well as near LNG that pooled. Releases occurring in the presence of an 

ignition source would most likely result in a fire located at the vapor source. A spill without 

ignition would form a vapor cloud that would travel with the prevailing wind until it either 

dispersed below the flammable limits or encountered an ignition source. In some instances, 

ignition of a vapor cloud may produce damaging overpressures. These hazards are described in 

more detail below.

Loss of Containment

A loss of the containment is the initial event that results in all other potential hazards. The initial 

loss of containment can result in a liquid and/or gaseous release with the formation of vapor at 

the release location, as well as from any liquid that pooled. The fluid released may present low 

or high temperature hazards, and may result in the formation of flammable vapors. The extent of 

the hazard will depend on the material released, the storage and process conditions, and the 

volumes released.

Downeast would store LNG on-site at atmospheric pressure and at a cryogenic temperature of 

approximately -260 degrees Fahrenheit (°F). Loss of containment of LNG could lead to the 

release of both liquid and vapor into the immediate area. Exposure to either cold liquid or vapor 

could cause freeze burns and, depending on the length of exposure, more serious injury or death. 

However, spills would be contained within the terminal and the cold state of these releases would 

be greatly limited due to the continuous mixing with the warmer air. The cold temperatures from 

the release would not present a hazard to any person outside the terminal.

LNG is a cryogenic liquid that quickly cools any materials contacted by the liquid on release, 

causing extreme thermal stress in materials not specifically designed for such conditions. These 

thermal stresses could subsequently subject the material to brittleness, fracture, or other loss of 

tensile strength. These temperatures, however, would be accounted for in the design of 

equipment and structural supports, and would not be substantially different from the hazards 

associated with the storage and transportation of liquid oxygen (-296oF) or several other 

cryogenic liquids that have been routinely produced and transported in the United States. 

A rapid phase transition (RPT) can occur when a cryogenic liquid is spilled onto water and 

changes from liquid to gas, virtually instantaneously. Unlike an explosion that releases energy 

and combustion products from a chemical reaction, an RPT is the result of heat transferred to the 

liquid inducing a change to the vapor state. RPTs have been observed during LNG test spills 

onto water. In some test cases, the overpressures generated were strong enough to damage test 

equipment in the immediate vicinity of the LNG release point. The sizes of the overpressure 

events have been generally small and are not expected to cause significant damage. The average 
4-299 4.12 – Reliability and Safety

overpressures recorded at the source of the RPTs during the Coyote tests have ranged from 

0.2 pounds per square inch (psi) to 11 psi28. These events are typically limited to the area within 

the spill and are not expected to cause damage outside of the area engulfed by the LNG pool. 

However, a RPT may affect the rate of pool spreading and the rate of vaporization for a spill on 

water.

Vapor Dispersion

In the event of a loss of containment, LNG would vaporize when released from any storage or 

process facilities. Depending on the size of the release, LNG may form a liquid pool and 

vaporize. Additional vaporization would result from exposure to ambient heat sources, such as 

water or soil. When released from a containment vessel or transfer system, LNG will generally 

produce 620 to 630 standard cubic feet of natural gas for each cubic foot of liquid. 

If the loss of containment does not result in immediate ignition of the natural gas vapors, the 

vapor cloud would travel with the prevailing wind until it either encountered an ignition source 

or dispersed below its flammable limits. An LNG release would form a denser-than-air vapor 

cloud that would sink to the ground due to the cold temperature of the vapor. As the LNG vapor 

cloud disperses downwind and mixes with the warm surrounding air, the LNG vapor cloud may 

become buoyant. However, experimental observations and vapor dispersion modeling indicate 

the LNG vapor cloud would not typically be warm, or buoyant, enough to lift off from the 

ground before the LNG vapor cloud becomes too diluted to be flammable. As a result, 

estimating the dispersion of the vapor cloud is an important step in addressing potential hazards 

and is discussed in section 4.12.5 of this EIS.

Methane, the primary component of LNG, is classified as a simple asphyxiate and may pose 

extreme health hazards, including death, if inhaled in significant quantities within a limited time. 

Very cold methane vapors may also cause freeze burns. However, the locations of 

concentrations where cold temperatures and oxygen-deprivation effects could occur are greatly 

limited due to the continuous mixing with the warmer air surrounding the spill site. Exposure 

injuries from contact with releases of methane normally represent negligible risks to the public.

Vapor Cloud Ignition

Flammability of the LNG vapor cloud would be dependent on the concentration of the vapor 

when mixed with the surrounding air. In general, higher concentrations within the vapor cloud 

would exist near the spill, and lower concentrations would exist near the edge of the cloud as it 

disperses downwind. Mixtures occurring between the lower flammability limit (LFL) and the 

upper flammability limit (UFL) could be ignited. Concentrations above the UFL or below the 

LFL would not ignite. The LFL and UFL for methane are approximately 5 percent by volume 

(%-vol) and 15%-vol in air, respectively. If the flammable portion of a vapor cloud encounters 

an ignition source, a flame would propagate through the flammable portions of the cloud. In 

most circumstances, the flame would be driven by the heat it generates, a process known as a 

deflagration. A methane vapor cloud deflagration in an uncongested and unconfined area travels 

at slower speeds and does not produce significant pressure waves. Confined and congested 

 28 The Lawrence Livermore National Laboratory conducted seven tests (the Coyote series) on vapor cloud 

dispersion, vapor cloud ignition, and RPTs at the Naval Weapons Center in China Lake, California in 1981.
4.12 – Reliability and Safety 4-300

methane vapor clouds may produce higher flame speeds and overpressures, and are discussed 

later in section 4.12.5 under “Overpressure Considerations.”

A deflagration may propagate back to the spill site if the vapor concentration along this path is 

sufficiently high to support the combustion process. When the flame reaches vapor 

concentrations above the UFL, the deflagration could transition to a fireball and result in a pool 

or jet fire back at the spill source. A fireball could occur if the fire reaches a fuel rich portion of 

the cloud, such as near the source of the release, and would be of a relatively short duration 

compared to an ensuing jet or pool fire. 

The extent of the affected area and the severity of the impacts on objects either within an ignited 

cloud or in the vicinity of a pool fire would primarily be dependent on the quantity and duration 

of the initial release, the surrounding terrain, and the environmental conditions present during the 

dispersion of the cloud. Radiant heat and dispersion modeling for the on-shore facilities are 

discussed in section 4.12.5. Impacts from LNG spills over water along the LNG carrier transit 

route are discussed in section 4.12.7.

A vapor cloud fire can ignite combustible materials within the cloud and can also cause severe 

burns and death. Resultant pool and jet fires may also cause failures of nearby storage vessels, 

piping, and equipment. The failure of a pressurized vessel could cause fragments of material to 

fly through the air at high velocities, posing damage to surrounding structures and a hazard for 

operating staff, emergency personnel, or other individuals in proximity to the event. In addition, 

failure of a pressurized vessel when the liquid is at a temperature significantly above its normal 

boiling point could result in a boiling-liquid-expanding-vapor explosion (BLEVE). BLEVEs of 

flammable liquids can produce overpressures and a subsequent fireball when the superheated 

liquid rapidly changes from a liquid to a vapor upon the release from the vessel. Atmospheric 

storage tanks, such as those proposed for LNG storage in this project are unlikely to BLEVE due 

to their lower design pressures.

Overpressures

If the deflagration in a flammable vapor cloud accelerates to a sufficiently high rate of speed, 

pressure waves would be generated. As a deflagration accelerates to super-sonic speeds, larger 

pressure waves are produced, and a shock wave created. This shock wave, rather than the heat, 

would begin to drive the flame, resulting in a detonation. Deflagrations or detonations are often 

characterized more generally as explosions when the rapid movement of the flame and pressure 

waves associated with them cause additional damage. The amount of damage an explosion 

causes is dependent on the amount the pressure wave is above atmospheric pressure (i.e. an 

overpressure) and its duration (i.e., pulse). For example, a 1 psi overpressure is often cited as a 

safety limit in regulations and is associated with glass shattering and traveling with velocities

high enough to lacerate skin. Flame speeds and overpressures are primarily dependent on the 

reactivity of the fuel, the ignition strength and location, the degree of congestion and 

confinement of the area occupied by the vapor cloud, and the flame travel distance. 

The potential for detonation of a vapor cloud is given special attention because it would produce 

much higher consequences; however, detonation is not the only scenario of concern. Large 

overpressures can still exist from high-order deflagrations and the propensity of a vapor cloud to 

deflagrate with damaging overpressures is similarly influenced by the fuel composition, level of 
4-301 4.12 – Reliability and Safety

confinement, and congestion (i.e., turbulence) surrounding the vapor cloud. However, it is still 

important to understand the potential of each occurrence, as explained below.

The potential for unconfined LNG vapor cloud detonations was investigated by the Coast Guard 

in the late 1970s at the Naval Weapons Center in China Lake, California. Using methane, the 

primary component of natural gas, several experiments were conducted to determine whether 

unconfined LNG vapor clouds would detonate. Unconfined methane vapor clouds ignited with 

low-energy ignition sources (13.5 joules), produced flame speeds ranging from 12 to 20 miles 

per hour (mph). These flame speeds are much lower than the flame speeds associated with a 

deflagration with damaging overpressures or a detonation. The tests indicated unconfined 

methane-air mixtures could be ignited, but no test produced unconfined detonation.

The Coast Guard conducted additional series of tests to quantify explosion hazards of LNG 

spills. Phase I included an analytical evaluation of the possible magnitude and damage potential 

of a spill of LNG. Phase II included tests igniting a range of methane concentrations using small 

and large boosters in a 1.8-meter-long, 0.6-meter-diameter shock tube and spark ignition sources 

in both 3.6-meter-long, 0.6-meter-diameter shock tube and thin film hemispheres. The intent

was to evaluate potential from deflagration to detonation in unconfined flammable vapor clouds. 

Additional phases were conducted for spills of LNG and LPG and gasoline onto water for 

comparative reasons. These phases involved additional thin film hemisphere tests to evaluate 

whether a detonation initiated by a high explosive charge or a detonation exiting a tube could be 

sustained within an unconfined flammable vapor cloud. 

In Phase II, spark ignition tests yielded velocities ranging from 45-63 m/s with overpressures of 

0.2 to 0.4 psi. The Coast Guard also performed 5 meter and 10 meter radius hemisphere tests of 

unconfined stoichiometric methane-air mixtures ignited by spark igniters in the center of the 

hemisphere. During the 5 meter tests, flame speeds were approximately 5.2-7.3 m/s and a 

pressure wave was not recorded, indicating the pressure was less than the approximately 1.5 psi 

lower limit of the pressure sensing equipment. In one of the tests, simple obstacles were added 

and in another test, open tubes were added. Both of these failed to significantly alter the flame 

velocity. 

Large explosive charge tests yielded velocities ranging from 910 m/s to 1,050 m/s with 

overpressures of 5.4 to 7.8 bar (78 to 113 psi). However, it is unclear as to whether the tube was 

long enough to obtain an accurate measure of the pressure induced by the methane versus the 

booster ignition source. Two attempts were also made to detonate a stoichiometric methane air 

mixture in 5 meter hemispheres using explosive boosters. During these tests, flame speeds were 

observed to propagate much more slowly than the initial detonation product expansion, measured 

at approximately 34 m/s.

In an additional phase (Phase III), tests were conducted to examine the level of sensitivity of an 

unconfined cloud to the presence of heavier hydrocarbons, such as ethane and propane. A series 

of tests on ambient-temperature fuel mixtures of methane-ethane and methane-propane indicated 

that the addition of heavier hydrocarbons influenced the tendency of an unconfined vapor cloud 

to detonate. Tests utilizing 57.6%, 76.8%, 81.6%, 86.4%, and 90% methane with the remainder 

of the fuel mixture made up of heavier hydrocarbons were examined. Methane concentrations 

above 81.6% failed to produce a vapor cloud detonation. Tests with 86-96% methane near 

stoichiometric proportions using exploding charges as the ignition source produced 
4.12 – Reliability and Safety 4-302

overpressures of 4 bar (58 psi), which was approximately the same overpressure produced during 

the calibration test involving the exploding charge ignition source alone. It remains unclear that 

the overpressure was attributable to the vapor deflagration.

In the last phase (Phase V) of the project, tests were conducted to determine whether methane 

could sustain a detonation initiated by an ignition source with high explosives or from an 

existing detonation emerging from a culvert. Tests indicated that 10 meter radius vapor clouds 

of nearly pure methane (99.9%) would not detonate from high explosives and the flame speeds 

and pressures rapidly decreased after initiation of the explosive charge. The second set of 

experiments used sheet explosive to create a detonation wave in a 6-meter-long culvert (1.8- and 

2.4-meter-diameter) buried vertically in the ground filled with a flammable mixture of LNG with 

a 5- and 10 meter radius unconfined methane-propane and heavier hydrocarbon-air vapor cloud 

at the exit of the culvert. The experiments indicated that an unconfined vapor cloud with 

methane concentrations above 85% could not sustain a detonation from a 1.8-meter-diameter 

culvert. The experiment also indicated that an unconfined vapor cloud with a methane 

concentration of 99.9% could not sustain a detonation from a 2.4-meter-diameter diameter 

culvert. However, the experiments indicated that an unconfined vapor cloud with methane 

concentrations of up to 94% could sustain a detonation from a 2.4-meter-diameter culvert.

A separate study investigated the detonation sensitivity of methane-ethane-air stoichiometric 

mixtures from pure methane-air to pure ethane-air. The results of tests indicated that very strong 

ignition sources were necessary to initiate a detonation with ethane concentrations greater than 

10% in the fuel mixture (or approximately 1% of total fuel-air mixture).

Tests in the early 1970s also investigated the effects of ignition end location within a pipe. A 

40-meter-long, 1.4-meter-diameter pipe with one open end and one closed end was filled with 

methane-air and ignited at the respective ends of the pipe to examine the difference in flame 

speeds. The highest flame speed was observed when the gas was ignited in the closed end and 

the other end was open. When ignition was at the open end, the flow velocity and the turbulence 

level ahead of the flame were very low and the flame propagated at low velocities through the 

pipe.

In the early 1980s, tests investigated the effects of repeated baffle plates inside a 10-meter-long, 

2.5-meter-diameter pipe with one end open. Configurations using 1, 3, 5, and 6 equally spaced 

baffle plates with area blockage ratios of 16%, 30%, and 50% were examined. Using spark 

igniters, five equally spaced baffle plates with blockage ratios of 50% produced an average 

maximum overpressure of approximately 4 bar (58 psi) within the pipe, a maximum overpressure 

of 4.3 bar (62 psi) immediately outside of the pipe, and a maximum overpressure of 0.39 bar 

(6 psi) located 10 meters downstream of the pipe exit. Similar experiments were conducted 

using propane and found to produce an average maximum overpressure of approximately 7 bar 

(102 psi) within the pipe, a maximum overpressure of 13.9 bar (202 psi) immediately outside of 

the pipe, and a maximum overpressure of 0.61 bar (9 psi) located 10 meters downstream of the 

pipe exit.

Tests conducted in the late 1980s investigated whether flames propagating over and around 

repeated obstructions could generate high flame speeds. The tests ignited natural gas-air 

mixtures in a 45-meter-long long open-sided rig, in which pipe arrays, obstructions, and grids 

were located to simulate obstacles found on most gas processing and storage sites. The first set 
4-303 4.12 – Reliability and Safety

of tests had 1.5 meter spaced pipe arrays arranged with an area blockage ratio of approximately 

40% over the first 18 meters of the test rig. Maximum flame speeds of approximately 50 m/s 

attained in the tests were up to 10 times higher than in unobstructed tests, but with peak 

overpressures in the range of only 0.4 to 1 psi.

Further tests were conducted with the same pipe array setup covering the first 22.5 meters of the 

test rig. Immediately after the flame emerged from the obstructed region into the unobstructed 

part of the cloud, the flame rapidly decelerated to a level that produced an overpressure less than 

0.15 psi. Natural gas-air tests with the same pipe array setup spanning the full 45 meters of the 

test rig showed flame speeds of approximately 80 m/s with peak overpressure inside the test-rig 

of approximately 1.5 psi.

In an attempt to achieve a limiting flame speed for natural gas, the test-rig was modified to 

completely enclose the first 9 meters of the rig to study whether the flame speed would 

accelerate or decelerate from the flame emerging from the confined region. Pipe arrays were 

varied within the confined region to produce flame speeds emerging from the confined region 

between 100 and 1,000 m/s, but remained the same in the unconfined region. For experiments 

with initiating flame speeds from the confined area of less than approximately 500 m/s the flame 

rapidly decelerated to approximately 30 to 40 m/s. For experiments with initiating flame speeds 

from the confined area of 600 to 700 m/s, the flame sustained approximately 500 m/s over the 

full length of the test-rig. In a further test with an initiating flame speed from the confined area 

of 1,000 m/s, the flame initially decelerated and then sustained at approximately 500 m/s.

To confirm that congestion was needed to sustain the high flame speeds, an experiment was 

conducted in which obstacles were located only over the first half of the test-rig. Similar to the 

unconfined tests, these tests also showed that immediately after the flame emerged from the 

congested region into the unobstructed part of the cloud, the flame rapidly decelerated to less 

than 10 m/s at the end of the test-rig. Additional tests showed that rapid deceleration occurred 

once the blockage ratio was reduced below 24% or the spacing between arrays exceeded 2.4 

meters.

It was also shown that although more closely packed pipe arrays (down to 0.5 meters) could 

produce high flame speeds, there was not any evidence to suggest that in a longer region of more 

closely spaced pipe arrays (down to 0.5 meters) that higher flame speeds would have occurred 

compared to the previous tests.

Later tests of near stoichiometric proportions of methane-air were also conducted by the 

Explosion Research Cooperative to form the updated Baker-Strehlow-Tang (BST) blast wave 

curves for low reactivity substances. The tests ignited methane-air mixtures in an unconfined 

12-ft-wide by 48-ft-long by 6-ft-high module test rig consisting of a 2x8 array of 6 foot cubical 

modules. Each 6 foot cubical module was outfitted with 2-inch-diameter schedule 40 pipe arrays 

of varying congestion. The low congestion set of tests had a 4x4 array of pipes with a pitch to 

diameter ratio of 7.6, an area blockage ratio of approximately 13% and volume blockage ratio of 

approximate 1.5%. The medium congestion set of tests had a 7x7 array of pipes with a pitch to 

diameter ratio of 4.3, an area blockage ratio of approximately 23% and volume blockage ratio of 

approximate 4.3%. The high congestion set of tests had alternating rows of 4 and 7 pipes with a 

pitch to diameter ratio of 3.1, an area blockage ratio of approximately 23% and volume blockage 

ratio of approximate 5.7%. According to those tests that form the BST blast wave curves, 
4.12 – Reliability and Safety 4-304

methane should not produce high flame speeds or associated large overpressures in areas of low 

congestion, even with partial confinement.

Numerous tests, reflective of offshore facilities, have also been conducted. These tests have 

shown similar trends of increased confinement and congestion resulting in larger overpressures. 

However, offshore facilities are not necessarily reflective of onshore, as offshore facilities are 

generally more congested and often contain multiple platform levels that can provide for 

confinement. This increase in congested and confinement can be attributed to the smaller 

footprint associated with offshore facilities.

This history of natural gas explosion tests provides a frame of reference for informing our sitespecific evaluation on the potential for LNG facilities to produce damaging overpressures. To 

examine the potential for detonation of an unconfined natural gas cloud containing heavier 

hydrocarbons that are more reactive, such as ethane and propane, the Coast Guard conducted 

further tests on ambient-temperature fuel mixtures of methane-ethane and methane-propane. The 

tests indicated that the addition of heavier hydrocarbons influenced the tendency of an 

unconfined natural gas vapor cloud to detonate. Natural gas with greater amounts of heavier 

hydrocarbons would be more sensitive to detonation. 

Although it is possible to produce damaging overpressures and detonations of unconfined LNG 

vapor clouds, the LNG proposed for importation to the Downeast project would have lower 

ethane and propane concentrations than those that resulted in damaging overpressures and 

detonations. The substantial amount of initiating explosives needed to create the shock initiation 

during the limited range of vapor-air concentrations also renders the possibility of detonation of 

these vapors at an LNG plant as unrealistic. Ignition of a confined LNG vapor cloud could result 

in higher overpressures. In order to prevent such an occurrence, measures are taken to mitigate 

the vapor dispersion and ignition into confined areas, such as buildings. In general, the primary 

hazards to the public from an LNG spill that disperses to an unconfined area, either on land or 

water, would be from dispersion of the flammable vapors or from radiant heat generated by a 

pool fire. Discussion of these hazards and potential mitigation are in section 4.12.5 for the onshore facilities and in section 4.12.7 for the LNG carrier transit route.

Past LNG Facility Incidents

With the exception of the October 20, 1944, failure at an LNG facility in Cleveland, Ohio, the 

operating history of the U.S. LNG industry has been free of safety-related incidents resulting in 

adverse effects on the public or the environment. The 1944 incident in Cleveland led to a fire 

that killed 128 people and injured 200 to 400 people.29 The failure of the LNG storage tank was 

due to the use of materials inadequately suited for cryogenic temperatures. LNG migrating 

through streets and into underground sewers, due to the lack of adequate spill impoundments at 

the site, was also a contributing factor. Current regulatory requirements ensure that proper 

materials suited for cryogenic temperatures are used and that spill impoundments are designed 

and constructed properly to contain a spill at the site.

 29 For a description of the incident and the findings of the investigation, see “U.S. Bureau of Mines, Report on the 

Investigation of the Fire at the Liquefaction, Storage, and Regasification Plant of the East Ohio Gas Co., Cleveland, 

Ohio, October 20, 1944,” dated February 1946.
4-305 4.12 – Reliability and Safety

Another operational accident occurred in 1979 at the Cove Point LNG facility in Lusby, 

Maryland. A pump seal failure resulted in gas vapors entering an electrical conduit and settling 

in a confined space. When a worker switched off a circuit breaker, the gas ignited, causing 

heavy damage to the building and a worker fatality. With the participation of the FERC, lessons 

learned from the 1979 Cove Point accident resulted in changing the national fire codes to ensure 

that the situation would not occur again.

On January 19, 2004, a blast occurred at Sonatrach’s Skikda, Algeria, LNG liquefaction facility, 

which killed 27 and injured 56 workers. No members of the public were injured. Findings of the 

accident investigation suggested that a cold hydrocarbon leak occurred at Liquefaction Train 40 

and was introduced to the high-pressure steam boiler by the combustion air fan. An explosion 

developed inside the boiler firebox, which subsequently triggered a larger explosion of the 

hydrocarbon vapors in the immediate vicinity. The resulting fire damaged the adjacent 

liquefaction process and liquid petroleum gas separation equipment of Train 40, and spread to 

Trains 20 and 30. Although Trains 10, 20, and 30 had been modernized in 1998 and 1999, Train 

40 had been operating with its original equipment since start-up in 1981. To ensure that this 

potential hazard is addressed at the proposed Project, Downeast would install hazard detection 

devices at all combustion and ventilation air intake equipment to enable isolation and 

deactivation of any combustion equipment whose continued operation could add to or sustain an 

emergency.

On March 31, 2014, an explosion and fire occurred at Northwest Pipeline Corporation’s LNG 

peak-shaving facility in Plymouth, Washington. The facility was immediately shut down, and 

emergency procedures were activated, which included notifying local authorities and evacuating 

all plant personnel. No members of the public were injured. The accident investigation is still in 

progress. Once developed, measures to address any causal factors which led to this incident will 

be applied to all facilities under Commission jurisdiction.

4.12.3 Technical Review of the Preliminary Engineering Design

Operation of the proposed facility poses a potential hazard that could affect the public safety if 

strict design and operational measures to control potential accidents are not applied. The 

primary concerns are those events that could lead to an LNG spill of sufficient magnitude to 

create an off-site hazard as discussed in section 4.12.2. However, it is important to recognize the 

stringent requirements in place for the design, construction, operation, and maintenance of the 

facility, as well, as the extensive safety systems proposed to detect and control potential hazards. 

As part of a project’s preliminary safety review, Downeast’s design development team 

conducted a hazard and operability review (HAZOP) analysis of the Front-End Engineering

Design (FEED) to identify the major hazards that may be encountered during the operation of 

facilities. The HAZOP study addresses hazards of the process, engineering and administrative 

controls, and provides a qualitative evaluation of a range of possible safety, health, and 

environmental effects which may result from the design or operation of the facility. 

Recommendations to prevent or minimize these hazards are generated from the results of the 

HAZOP review. These studies help establish the required safety control levels and identify 

whether additional process and safety instrumentation, mitigation, and/or administrative controls

would be needed. In addition, Downeast’s design development team would perform another

HAZOP review of the completed design during the detailed design phase. 
4.12 – Reliability and Safety 4-306

Once the design has been subjected to a HAZOP review, the design development team tracks 

changes in the facility design, operations, documentation, and personnel. Downeast would 

evaluate these changes to ensure that the safety, health, and environmental risks arising from 

these changes are addressed and controlled. FERC staff would monitor resolutions of the 

recommendations generated by the HAZOP review of the final completed design. We have 

included a recommendation that Downeast should file a HAZOP study on the completed final 

design. 

Based on these analyses, Downeast would include various layers of protection or safeguards 

would in the facility design to reduce the risk of a potentially hazardous scenario from 

developing into an event that could impact the off-site public. These layers of protection are 

independent of one another so that anyone would perform its function regardless of the action or 

failure of any other protection layer or initiating event. These layers of protection typically 

include:

• A facility design that prevents hazardous events through the use of suitable materials of 

construction; operating and design limits for process piping, process vessels, and storage 

tanks; adequate design for wind, flood, seismic, and other outside hazards;

• Control systems, including monitoring systems and process alarms, remotely-operated 

control and isolation valves, and operating procedures to ensure the facility stays within 

the established operating and design limits;

• Safety-instrumented prevention systems, such as safety control valves and emergency 

shutdown systems, to prevent a release if operating and design limits are exceeded;

• Physical protection systems, such as appropriate electrical area classification, proper 

equipment and building spacing, pressure relief valves, spill containment, and structural 

fire protection, to prevent escalation to a more severe event;

• Site security measures for controlling access to the facility, including security inspections 

and patrols; response procedures to any breach of security; and liaison with local law 

enforcement officials; and

• On-site and off-site emergency response, including hazard detection and control 

equipment, firewater systems, and coordination with local first responders to mitigate the 

consequences of a release and prevent it from escalating to an event that could impact the 

public.

The use of these protection layers would mitigate the potential for an initiating event to develop 

into an incident that could damage the facility, injure operating staff, or impact the safety of the 

off-site public. In addition, siting of the facility with regard to potential off-site consequences is 

required by DOT’s regulations in 49 CFR 193, Subpart B to ensure that impact on the public 

would be minimized. These siting requirements are discussed in section 4.12.4.

As part of the application, Downeast provided a FEED for the project. The FEED and 

specifications submitted for the proposed facilities to date are preliminary, but would serve as the 

basis for any detailed design to follow. During the FERC review process, we analyzed the 

information filed by Downeast to determine the extent that layers of protection or safeguards to 

enhance the safety, operability, and reliability of the facility are included in the FEED.
4-307 4.12 – Reliability and Safety

As a result of the technical review of the information provided by Downeast in the submittal 

documents, we identified a number of concerns relating to the reliability, operability, and safety 

of the proposed design. In response to staff’s questions, Downeast provided written responses 

prior to the technical conference held on April 25, 2007. However, some of these responses 

indicated that corrections or modifications would be made to the design in order to address issues 

raised in the information request. As a result, we recommend that:

• Prior to construction of the final design, Downeast should provide 

information/revisions related to those responses in their April 10, 2007 filing that 

state that corrections or modifications would be made to the design. The final 

design should specifically address response numbers 2, 8, 10, 13, 15, 23, 24, 25, 26, 

27, 30, 31, 33, 34, 38, 51, 54, 56, 59, 61, and 70 using management of change 

procedures.

The objectives of our FEED review focused on the engineering design and safety concepts of the 

various protection layers, as well as the projected operational reliability of the proposed 

facilities. The design would use materials of construction suited to the pressure and temperature 

conditions of the process design. Piping would be designed in accordance with American 

Society of Mechanical Engineers (ASME) B31.3. Pressure vessels would be designed in 

accordance with ASME Section VIII and the storage tanks would be designed in accordance with 

American Petroleum Institute (API) Standard 620 per 49 CFR 193 and the National Fire 

Protection Association’s Standard 59A (NFPA 59A). Valves and other equipment would be 

designed to recommended and generally accepted good engineering practices. Downeast states it 

would design the LNG storage tanks to withstand the effects of hurricane force winds with a 

design wind velocity of 150 mph.

As part of its role as a cooperating agency on this document, DOT provided comments indicating 

that additional equipment should be designed to withstand this windspeed. DOT requires the use 

of an assumed sustained wind velocity of not less than 150 mph for all equipment used for 

transferring, storing, or vaporizing LNG. Alternative wind speeds may be approved by DOT 

provided they are justified by adequate wind data and an acceptable probabilistic methodology. 

As such, Downeast either must design the facilities to accommodate wind forces based on a 

sustained wind velocity of 150 mph or may request DOT approval for use of a lower wind speed 

under the regulatory means listed in § 193.2067(b). As a result, we recommend that:

• Prior to the construction of the final design, Downeast should file with the Secretary 

for review and written approval by the Director of OEP, certification that the final 

design has been modified to be consistent with the wind speed requirements of 49 

CFR § 193.2067 or that DOT has approved the use of a lower wind speed as allowed 

by § 193.2067(b). Downeast should consult with DOT on any actions necessary to 

demonstrate compliance with Part 193. 

All onshore structures at the terminal would be at a height of 50 feet or greater above sea level 

(North American Vertical Datum of 1988) to minimize the risk of flooding. The dock would be 

19.1 feet NAVD88. These elevations exceed the 100 year and 500 year return period of 14.3 feet 

and 14.6 feet NAVD88, respectively. The onshore facilities would also be well above the 

predicted maximum water level of approximately 21 feet NAVD88 defined by NOAA for a 

Category 4 Hurricane for the area. As discussed in section 4.1.4, we also examined the seismic 
4.12 – Reliability and Safety 4-308

and structural design of the facility and provided recommendations to deal with the issues 

identified.

Downeast would install process control valves and instrumentation to safely operate and monitor 

the facility. Alarms would have visual and audible notification in the control room to warn 

operators that process conditions may be approaching design limits. Operators would have the 

capability to take action from the control room to mitigate an upset. 

Downeast would develop facility operations procedures after completion of the final design; this 

timing is fully consistent with accepted industry practice. We are recommending that Downeast 

provide more information on the operating and maintenance procedures as they are developed, 

including safety procedures, hot work procedures and permits, abnormal operating conditions 

procedures, training of personnel. In addition, we are recommending measures, such as 

equipment/pipe labeling and valve car-seals/locks, to address human factor considerations and 

improve facility safety. An alarm management program would also be in place to ensure 

effectiveness of the alarms.

Safety valves and instrumentation would be installed to monitor, alarm, shutdown, and isolate 

equipment and piping during process upsets or emergency conditions. Safety instrumented 

systems would comply with International Society for Automation (ISA) Standard 84.01 and 

other recommended and generally accepted good engineering practices. We are also 

recommending changes to the design, installation, and commissioning of instrumentation and 

emergency shutdown equipment to ensure appropriate cause and effect alarm or shutdown logic 

and enhanced representation of the emergency shutdown valves in the facility control system.

Safety relief valves and vent stacks would be installed to protect the process equipment and 

piping. The safety relief valves would be designed to handle process upsets and thermal 

expansion within piping, per NFPA 59A and ASME Section VIII, and would be designed based 

on API 520, API 521, API 526, API 527, and other recommended and generally accepted good 

engineering practices. In addition, we are making recommendations for changes to the design 

and installation of pressure and vacuum relief devices to ensure appropriate discharge and 

separate handling of LNG and natural gas.

In order to minimize the risk of an intentional event, Downeast would provide security fencing, 

lighting, camera systems, and intrusion detection to deter, monitor, and detect intruders into the 

facility. In addition, as discussed in section 4.12.6, Downeast would be required to develop a 

Facility Security Plan in accordance with the Coast Guard’s regulations found in 33 CFR 105, 

Subpart D. We are also recommending that Downeast provide site access control during 

construction and security and incident reporting during operation.

In the event of a release, Downeast would provide drainage systems from LNG storage and 

process facilities direct a spill away from equipment in order to minimize flammable vapors from 

dispersing to confined, occupied, or public areas and to minimize heat from impacting adjacent 

equipment and public areas if ignition occurs. Spacing of vessels and equipment between each 

other, from ignition sources, and to the property line would comply with 49 CFR Part 193 and 33 

CFR Part 127.105. In addition, Coast Guard requiremented outline in 33 CFR Part 127.105 

discuss LNG impounding spaces to minimize or prevent structural damage to an LNG vessel 

moored or berthed at a waterfront facility handling LNG. We are also making recommendations 
4-309 4.12 – Reliability and Safety

on the spacing and design of impoundments to minimize damage to equipment and buildings. 

Impoundment systems are further discussed in section 4.12.5.

Downeast performed a preliminary fire protection evaluation to ensure that adequate hazard 

detection, hazard control, and firewater coverage would be installed to detect and address any 

upset conditions. Structural fire protection, proposed to prevent failure of structural supports of 

equipment and piperacks, would comply with NFPA 59A and other recommended and generally 

accepted good engineering practices. Downeast would also install hazard detection systems to 

detect, alarm, and alert personnel in the area and control room to initiate an emergency shutdown 

and/or initiate appropriate procedures, and would meet NFPA 72, ISA 12.13, and other 

recommended and generally accepted good engineering practices. Hazard control devices would 

be installed to extinguish or control incipient fires and releases, and would meet NFPA 59A and 

NFPA 10, 11, 12, and 17 requirements, and other recommended and generally accepted good 

engineering practices. Automatic firewater systems and monitors would be provided for use 

during an emergency to cool the surface of storage vessels, piping, and equipment exposed to 

heat from a fire, and would meet NFPA 59A, 20, 22, 24, and 25 requirements. We are also 

making recommendations for the provision of a clean agent system in the power distribution 

building and for Downeast to provide a finalized fire protection evaluation. In addition, we are 

making recommendations for Downeast to provide more information on the design, installation, 

and commissioning of hazard detection, hazard control, and firewater systems as Downeast 

would further develop this information during the final design phase.

Downeast would also have emergency procedures in accordance with 49 CFR 193 and 33 CFR 

127. The emergency procedures would provide for protection of personnel and the public as 

well as the prevention of property damage that may occur as a result of incidents at the facility. 

Downeast would also be required to develop an emergency response plan (ERP) in accordance 

with the Energy Policy Act of 2005 (EPAct 2005), as discussed further in section 4.12.8.

If authorization is granted by the Commission, the next phase of the project would include 

development of the final design, including final selection of equipment manufacturers, process 

conditions, and resolution of some safety-related issues. To ensure the final design would be 

consistent with the safety and operability characteristics identified in the FEED, information 

regarding the development of the final design, as detailed below, would need to be filed with the 

Secretary of the Commission (Secretary) for review and written approval by the Director of the 

Office of Energy Projects (OEP) before equipment construction at the site would be authorized.

In addition to the final design review, we would conduct inspections during construction and 

would review additional materials, including quality assurance and quality control plans, 

non-conformance reports, and cooldown and commissioning plans to ensure that the installed 

design would be consistent with the safety and operability characteristics of the FEED. We 

would also conduct inspections during operation to ensure that the facility would be operated and 

maintained in accordance with the filed design throughout the life of the facility.

To ensure that the concerns we identified relating to the reliability, operability, and safety of the 

proposed design are addressed by Downeast, and would be subject to the Commission’s 

construction and operational inspection program, we recommend that the following measures 

be applied to the Downeast LNG terminal. Information pertaining to these specific 

recommendations should be filed with the Secretary for review and written approval by the 
4.12 – Reliability and Safety 4-310

Director of OEP either: prior to initial site preparation; prior to construction of final 

design; prior to commissioning; prior to introduction of hazardous fluids; or prior to 

commencement of service, as indicated by each specific condition. Specific engineering, 

vulnerability, or detailed design information meeting the criteria specified in Order No. 683 

(Docket No. RM06-24-000), including security information, should be submitted as critical 

energy infrastructure information (CEII) pursuant to 18 CFR 388.112. See CEII Order 

No. 683, 71 Fed. Reg. 58,273 (October 3, 2006), FERC Stats. & Regs. ¶31,228 (2006). 

Information pertaining to items such as: offsite emergency response; procedures for public 

notification and evacuation; and construction and operating reporting requirements would 

be subject to public disclosure. All information should be filed a minimum of 30 days 

before approval to proceed is requested. 

• Prior to initial site preparation, Downeast should file the quality assurance and 

quality control procedures for construction activities.

• Prior to initial site preparation, Downeast should include a plot plan of the final 

design showing all major equipment, structures, buildings, and impoundment 

systems.

• Prior to initial site preparation, Downeast should file an overall project schedule. 

• Prior to initial site preparation, Downeast should provide procedures for controlling 

access during construction.

• Prior to initial site preparation, Downeast should file a complete specification of the 

proposed LNG tank design and installation.

• Prior to initial site preparation, Downeast should file drawings of the storage tank 

piping support structure and support of horizontal piping at grade including pump 

columns, relief valves, pipe penetrations, instrumentation, and appurtenances.

• Prior to initial site preparation, Downeast should file complete plan drawings of the 

security fencing and of facility access and egress, including the details of the fence 

and control access and egress from the pipe trestle and dock. 

• The final design should provide change logs that list and explain any changes made 

from the Front-End Engineering Design provided in Downeast’s application and 

filings. A list of all changes with an explanation for the design alteration should be 

provided and all changes should be clearly indicated on all diagrams and drawings. 

• The final design should provide an equipment list, process and mechanical data 

sheets, and specifications.

• The final design should include spill containment system drawings with dimensions 

and slopes of curbing, trenches, and impoundments. 

• The final design should include electrical area classification drawings.

• The final design should include the sizing basis and capacity for the final design of 

pressure and vacuum relief valves for major process equipment, vessels, storage 

tanks, and vent stacks.
4-311 4.12 – Reliability and Safety

• The final design should provide the procedures for pressure/leak tests which 

address the requirements of ASME VIII and ASME B31.3, as required by 49 CFR 

193.

• The final design should include up-to-date Process Flow Diagrams (PFDs) and 

Piping and Instrumentation Diagrams (P&IDs). The PFDs should include heat and 

material balances. The P&IDs should include the following information:

a. equipment tag number, name, size, duty, capacity, and design conditions; 

b. equipment insulation type and thickness;

c. storage tank pipe penetration size or nozzle schedule;

d. piping with line number, piping class specification, size, and insulation type 

and thickness;

e. piping specification breaks and insulation limits;

f. all control and manual valves numbered;

g. valve high pressure side and internal and external vent locations;

h. relief valves with set points; and

i. drawing revision number and date.

• The final design should include an updated fire protection evaluation carried out in 

accordance with the requirements of NFPA 59A 2001, chapter 9.1.2 as required by 

49 CFR 193. A copy of the evaluation, a list of recommendations and supporting 

justifications, and actions taken on the recommendations should be filed. The fire 

protection evaluation should address measures on the prevention of caustic water 

from entering the firewater tank. 

• The final design should include complete drawings and a list of the hazard detection 

equipment. Drawings should clearly show the location and elevation of all detection 

equipment. The list should include the instrument tag number, type and location, 

alarm indication locations, set points, and shutdown functions of the proposed 

hazard detection equipment.

• The final design should provide a technical review of its proposed facility design 

that:

a. identifies all combustion/ventilation air intake equipment and the distances 

to any possible hydrocarbon release (LNG, flammable refrigerants, 

flammable liquids and flammable gases); and

b. demonstrates that these areas are adequately covered by hazard detection 

devices and indicates how these devices would isolate or shut down any 

combustion equipment whose continued operation could add to or sustain an 

emergency.

• The final design should provide drawings and a list of the fixed and wheeled drychemical, hand-held fire extinguishers, and other hazard control equipment. 

Drawings should clearly show the location by tag number of all fixed, wheeled, and 
4.12 – Reliability and Safety 4-312

hand-held extinguishers. The list should include the equipment tag number, type, 

capacity, equipment covered, discharge flow rate, and automatic and manual 

remote signals initiating discharge of the units.

• The final design should provide facility plans and drawings showing the location of 

the firewater and any foam systems. Drawings should clearly show: firewater and 

foam piping; post indicator valves; and the location, and area covered by, each 

monitor, hydrant, water curtain, deluge system, foam system, sprinkler system, and 

water mist system. The drawings should also include piping and instrumentation 

diagrams of the firewater and foam systems.

• The final design should specify that the design pressure of sendout equipment 

containing LNG in low pressure service should be not less than the design pressure 

of the piping system.

• The final design should specify that LNG relief valves and LNG drains should not 

discharge into the vapor system.

• The final design should specify that LNG from relief valves and drains is to be 

returned to storage.

• The final design should include provision for vehicle access roads to and from the 

north and south of the LNG pump and vaporizer area.

• The final design of the vapor return system should include provisions for the 

addition of LNG transfer pumps to the Jetty Drum D-103. The vapor inlet piping to 

the drum should be designed to ensure that all LNG, from the desuperheater and 

LNG piping discharging to the drum, cannot back flow to the vapor return piping.

• The final design should include provisions for the future installation of LNG pumps 

for the boil-off gas (BOG) drum.

• The final design should specify that the vapor inlet piping to the BOG drum should 

be designed to ensure that all LNG, from the desuperheater and LNG piping 

discharging to the drum, cannot back flow to the vapor return piping.

• The final design should specify that the Low Point Drain Drum is to be equipped to 

remove residual liquids without personnel accessing the spill containment sump.

• The final design of the Low Point Drain Drum should include a pressure relief 

system, to protect the vessel in the event of isolation.

• The final design of the boil-off condenser system should include a relief valve 

between the vapor inlet check valve and the fail-closed LNG outlet control valve.

• The final design should include provisions to recycle the boil-off compressor 

discharge to upstream of the BOG drum desuperheater.

• The final design should include car-seal or locked closed bypass valves around the 

intank pump ESD2 discharge valves as opposed to minimum stop set points for 

ESD2 valves, for cooldown of the 20-inch diameter header and piping.
4-313 4.12 – Reliability and Safety

• The final design should include a shutoff valve at the suction and discharge of each 

high pressure pump.

• The final design should specify that the minimum flow recycle line from the high 

pressure LNG pumps to downstream of the isolation valve to the LNG storage tanks 

should be the same pressure and temperature rating as the piping at the discharge 

of the high pressure LNG pumps.

• The final design should include a relief valve or operated vent valve sized for 

thermal relief at the discharge of each vaporizer, upstream of the isolation valves. 

This relief valve is in addition to the relief valve specified in NFPA 59A (2001 ed.) 

Section 5.4.1 and should be set at a lower pressure.

• The final design should include LNG tank fill flow measurement with high flow 

alarm.

• The final design should include a discretionary vent valve for each LNG tank, 

operable through the Distributed Control System (DCS).

• The final design should include BOG flow and temperature measurement for each 

tank.

• The final design should specify that all emergency shutdown (ESD) valves are to be 

equipped with open and closed position switches connected to the DCS/Safety 

Instrumented System (SIS).

• The final design should include a clean agent system in the power distribution 

building.

• The final design should include an analysis of the structural integrity of the outer 

containment of the full containment storage tanks when exposed to a roof tank top 

fire or adjacent tank top fire.

• The final design should specify that all drains from high pressure LNG systems are 

to be equipped with double isolation and bleed valves.

• The final design should specify that for hazardous fluids, branch piping, and piping 

nipples less than 2 inches are to be no less than Schedule 160.

• The final design should specify that piping and equipment that may be cooled with 

liquid nitrogen is to be designed for liquid nitrogen temperatures, with regard to 

allowable movement and stresses.

• The final design should include details of the shut-down logic, including cause and 

effect matrices for the process instrumentation, hazard detection system, and 

emergency shutdown system for alarms and shutdowns, including set points and 

voting logic.

• The final design should include emergency shutdown of equipment and systems 

activated by hazard detection devices for flammable gas, fire, and cryogenic spills, 

when applicable.
4.12 – Reliability and Safety 4-314

• The final design should include drawings and details of how process seals or 

isolations installed at the interface between a flammable fluid system and an 

electrical conduit or wiring system meet the requirements of NFPA 59A.

• The final design should provide an air gap or vent installed downstream of process 

seals or isolations installed at the interface between a flammable fluid system and an 

electrical conduit or wiring system. Each air gap should vent to a safe location and 

be equipped with a leak detection device that: should continuously monitor for the 

presence of a flammable fluid; should alarm the hazardous condition; and should 

shut down the appropriate systems.

• The final design should include a hazard and operability review of the completed 

design prior to issuing the P&IDs for construction. A copy of the review, a list of 

recommendations, and actions taken on the recommendations should be filed.

• The final design should include provisions to install high pressure boil-off 

compression or BOG liquefaction in the event that sendout operation is curtailed, or 

ceased for a period in excess of thirty days. Details should include plans and 

drawings of the BOG recovery system and specifications of the equipment and 

compressors to be installed.

• The final design should include provisions to remove LNG from the inlet of the 

vaporizer due to shutdown sequence.

• The final design should include a plan for clean-out, dry-out, purging, and tightness 

testing. This plan should address the requirements of the American Gas 

Association’s Purging Principles and Practice required by 49 CFR 193, and should 

provide justification if not using an inert or non-flammable gas for cleanout, dryout, purging, and tightness testing.

• The final design should include a vent stack dispersion analysis to determine the 

proper placement of hazard detection devices that ensures venting is done in a safe 

manner.

• The final design should specify that the vent stack be equipped with a discharge 

piece designed for ignited discharge conditions. 

• Prior to commissioning, Downeast should file plans and detailed procedures for: 

testing the integrity of onsite mechanical installation; functional tests; introduction 

of hazardous fluids; operational tests; and placing the equipment into service.

• Prior to commissioning, Downeast should provide a detailed schedule for

commissioning through equipment startup. The schedule should include milestones 

for all procedures and tests to be completed: prior to introduction of hazardous 

fluids, and during commissioning and startup. Downeast should file documentation

certifying that each of these milestones has been completed before authorization to 

commence the next phase of commissioning and startup will be issued.

• Prior to commissioning, Downeast should file results of the LNG storage tank 

hydrostatic test and foundation settlement results.
4-315 4.12 – Reliability and Safety

• Prior to commissioning, Downeast should tag all instrumentation and valves in the 

field, including drain valves, vent valves, main valves, and car-sealed or locked 

valves.

• Prior to commissioning, Downeast should label equipment with equipment tag 

number and piping with fluid service and direction of flow in the field in addition to 

the pipe labeling requirements of NFPA 59A.

• Prior to commissioning, Downeast should file the design details and procedures to 

record and to prevent the tank fill rate from exceeding the maximum fill rate 

specified by the tank designer.

• Prior to commissioning, Downeast should file operation and maintenance 

procedures and manuals, as well as safety procedures.

• Prior to commissioning, Downeast should maintain a detailed training log to 

demonstrate that operating staff has completed required training.

• Prior to introduction of hazardous fluids, Downeast should file a cooldown plan. 

During cooldown, Downeast should report progress on the development of cooldown 

in daily reports.

• Prior to introduction of hazardous fluids, Downeast should complete all pertinent 

tests (Factory Acceptance Tests, Site Acceptance Tests, Site Integration Tests) 

associated with the Distributed Control System (DCS) and Safety Instrumented

System (SIS) that demonstrates full functionality and operability of the system.

• Prior to introduction of hazardous fluids, Downeast should complete a firewater 

pump acceptance test and firewater monitor and hydrant coverage test. The actual 

coverage area from each monitor and hydrant should be shown on facility plot 

plan(s). 

• Prior to commencement of service, Downeast should develop procedures for offsite 

contractors’ responsibilities, restrictions, and limitations and for supervision of 

these contractors by Downeast staff.

• Prior to commencement of service, Downeast should notify FERC staff of any 

proposed revisions to the security plan and physical security of the facility.

• Prior to commencement of service, Downeast should file progress on construction of 

the LNG terminal in monthly reports. Details should include a summary of 

activities, problems encountered, contractor non-conformance/deficiency logs, 

remedial actions taken, and current project schedule. Problems of significant 

magnitude should be reported to the FERC within 24 hours. 

In addition, the following measures should apply throughout the life of the facility: 

• The facility should be subject to regular FERC staff technical reviews and site 

inspections on at least an annual basis or more frequently as circumstances indicate. 

Prior to each FERC staff technical review and site inspection, Downeast should 

respond to a specific data request including information relating to possible design 

and operating conditions that may have been imposed by other agencies or 
4.12 – Reliability and Safety 4-316

organizations. Up-to-date detailed piping and instrumentation diagrams reflecting 

facility modifications and provision of other pertinent information not included in 

the semi-annual reports described below, including facility events that have taken 

place since the previously submitted annual report, should be submitted.

• Semi-annual operational reports should be filed with the Secretary to identify 

changes in facility design and operating conditions, abnormal operating experiences, 

activities (including ship arrivals/departures, quantity and composition of imported 

and exported LNG, liquefied and vaporized quantities, boil-off/flash gas, etc.), and 

plant modifications including future plans and progress thereof. Abnormalities 

should include, but not be limited to: unloading/loading shipping problems, 

potential hazardous conditions caused by off-site transportation, storage tank 

stratification or rollover, geysering, storage tank pressure excursions, cold spots on 

the storage tanks, storage tank vibrations and/or vibrations in associated cryogenic 

piping, storage tank settlement, significant equipment or instrumentation 

malfunctions or failures, nonscheduled maintenance or repair (and reasons 

therefore), relative movement of storage tank inner vessels, vapor or liquid releases, 

fires involving natural gas and/or from other sources, negative pressure (vacuum) 

within a storage tank and higher than predicted boil-off rates. Adverse weather

conditions and the effect on the facility should also be reported. Reports should be 

submitted within 45 days after each period ending June 30 and December 31. In 

addition to the above items, a section entitled "Significant Plant Modifications 

Proposed for the Next 12 Months (dates)" should also be included in the semiannual 

operational reports. Such information would provide the FERC staff with early 

notice of anticipated future construction/maintenance projects at the LNG facility.

• In the event the temperature of any region of any secondary containment, including 

imbedded pipe supports, becomes less than the minimum specified operating 

temperature for the material, the Commission should be notified within 24 hours

and procedures for corrective action should be specified.

• Significant non-scheduled events, including safety-related incidents (e.g., LNG, 

refrigerant or natural gas releases, fires, explosions, mechanical failures, unusual 

over pressurization, and major injuries) and security related incidents (i.e., attempts 

to enter site, suspicious activities) should be reported to FERC staff. In the event an 

abnormality is of significant magnitude to threaten public or employee safety, cause 

significant property damage, or interrupt service, notification should be made 

immediately, without unduly interfering with any necessary or appropriate 

emergency repair, alarm, or other emergency procedure. In all instances, 

notification should be made to FERC staff within 24 hours. This notification 

practice should be incorporated into the LNG facility's emergency plan. Examples 

of reportable LNG or refrigerant related incidents include:

a. fire;

b. explosion;

c. estimated property damage of $50,000 or more;
4-317 4.12 – Reliability and Safety

d. death or personal injury necessitating in-patient hospitalization;

e. release of hazardous fluids for five minutes or more;

f. unintended movement or abnormal loading by environmental causes, such as 

an earthquake, landslide, or flood, that impairs the serviceability, structural 

integrity, or reliability of an LNG facility that contains, controls, or processes 

gas, refrigerants, or LNG;

g. any crack or other material defect that impairs the structural integrity or 

reliability of an LNG facility that contains, controls, or processes gas, 

refrigerants, or LNG;

h. any malfunction or operating error that causes the pressure of a pipeline or 

LNG facility that contains or processes gas, refrigerants, or LNG to rise 

above its maximum allowable operating pressure (or working pressure for 

LNG facilities) plus the build-up allowed for operation of pressure limiting 

or control devices;

i. a leak in an LNG facility that contains or processes gas, refrigerants, or LNG 

that constitutes an emergency;

j. inner tank leakage, ineffective insulation, or frost heave that impairs the 

structural integrity of an LNG storage tank;

k. any safety-related condition that could lead to an imminent hazard and cause 

(either directly or indirectly by remedial action of the operator), for purposes 

other than abandonment, a 20 percent reduction in operation of a pipeline or 

an LNG facility that contains or processes gas, refrigerants, or LNG;

l. safety-related incidents to LNG or refrigerant transportation occurring at or 

en route to and from the LNG facility; or

m. an event that is significant in the judgment of the operator and/or 

management even though it did not meet the above criteria or the guidelines 

set forth in an LNG facility’s incident management plan.

In the event of an incident, the Director of OEP has delegated authority to take 

whatever steps are necessary to ensure operational reliability and to protect human 

life, health, property or the environment, including authority to direct the LNG 

facility to cease operations. Following the initial company notification, FERC staff 

would determine the need for a separate follow-up report or follow-up in the 

upcoming semi-annual operational report. All company follow-up reports should 

include investigations results and recommendations to minimize a reoccurrence of 

the incident.

4.12.4 Siting Requirements

The principal hazards associated with the substances involved in the, storage and vaporization of 

LNG result from cryogenic and flashing liquid releases; flammable vapor dispersion; vapor 

cloud ignition; pool fires; and overpressures. As discussed in section 4.12.3, our FEED review 

indicates that sufficient layers of protection would be incorporated into the facility design to 

mitigate the potential for an initiating event to develop into an incident that could impact the 
4.12 – Reliability and Safety 4-318

safety of the off-site public. Siting of the facility with regard to potential off-site consequences 

is also required by DOT’s regulations in 49 CFR 193, Subpart B as an additional safeguard to 

help ensure that impact on the public would be minimized. The Commission’s regulations under 

18 CFR 380.12(o)(14) require Downeast to identify how the proposed design complies with 

DOT’s siting requirements. As part of our review, we used Downeast’s information, developed 

to comply with DOT’s regulations, to assess whether or not the facility would have a public 

safety impact. The Part 193 requirements state that an operator or government agency must 

exercise control over the activities that can occur within an “exclusion zone,” defined as the area 

around an LNG facility that could be exposed to specified levels of thermal radiation or 

flammable vapor in the event of a release. Approved mathematical models must be used to 

calculate the dimensions of these exclusion zones. The 2001 edition of NFPA 59A, an industry 

consensus safety standard for the siting, design, construction, operation, maintenance, and 

security of LNG facilities, is incorporated into Part 193 by reference, with regulatory preemption 

in the event of conflict. The following sections of Part 193 specifically address the siting 

requirements applicable to each LNG container and LNG transfer system:

• Part 193.2001, Scope of part, excludes any matter other than siting provisions pertaining 

to marine cargo transfer systems between the marine vessel and the last manifold or valve 

immediately before a storage tank.

• Part 193.2051, Scope, states that each LNG facility designed, replaced, relocated or 

significantly altered after March 31, 2000, must be provided with siting requirements in 

accordance with Subpart B and NFPA 59A (2001). In the event of a conflict with NFPA 

59A (2001), the regulatory requirements in Part 193 prevail.

• Part 193.2057, Thermal radiation protection, requires that each LNG container and LNG 

transfer system have thermal exclusion zones in accordance with Section 2.2.3.2 of 

NFPA 59A (2001).

• Part 193.2059, Flammable vapor-gas dispersion protection, requires that each LNG 

container and LNG transfer system have a dispersion exclusion zone in accordance with 

Sections 2.2.3.3 and 2.2.3.4 of NFPA 59A (2001).

For the LNG facilities proposed for this project, these Part 193 siting requirements would be 

applicable to the following equipment:

• Two 42,267,530 gallon (net) full containment LNG storage tanks and associated piping 

and appurtenances - Parts 193.2057 and 2059 require the establishment of thermal and 

flammable vapor exclusion zones for LNG tanks. NFPA 59A (2001), section 2.2.3.2 

specifies four thermal exclusion zones based on the design spill and the impounding area. 

NFPA 59A (2001), sections 2.2.3.3 and 2.2.3.4 specify a flammable vapor exclusion zone 

for the design spill which is determined with section 2.2.3.5.

• A pier comprised of a single LNG carrier berth and a marine cargo transfer system, 

consisting of three 16-inch-diameter liquid transfer arms and one 16-inch-diameter vapor 

return arm, a single 36-inch-diameter LNG transfer pipe, and other associated process 

vessels, piping and appurtenances. Parts 193.2001, 2057, and 2059 require thermal and 

flammable vapor exclusion zones for the marine cargo transfer system. NFPA 59A 

(2001) does not address LNG transfer systems.
4-319 4.12 – Reliability and Safety

• Four 4,600 gallon per minute (gpm) low pressure in-tank pumps (two per tank; one 

operating and one spare) and associated piping and appurtenances; and four 1,400 gpm 

high pressure (HP) sendout pumps (three operating and one spare) and associated process 

vessels, piping, and appurtenances - Parts 193.2057 and 2059 require thermal and 

flammable vapor exclusion zones. NFPA 59A (2001) section 2.2.3.2 specifies the 

thermal exclusion zone and sections 2.2.3.3 and 2.2.3.4 specify the flammable vapor 

exclusion zone based on the design spills for containers and process areas.

• Four submerged combustion vaporizers (SCVs) and associated process vessels, piping, 

and appurtenances- Parts 193.2057 and 2059 require thermal and flammable vapor 

exclusion zones. NFPA 59A (2001) section 2.2.3.2 specifies the thermal exclusion zone 

and sections 2.2.3.3 and 2.2.3.4 specify the flammable vapor exclusion zone based on the 

design spill in a process area.

Previous FERC environmental assessments/impact statements for past projects have identified 

inconsistencies and areas of potential conflict between the requirements in Part 193 and NFPA 

59A (2001). Sections 193.2057 and 193.2059 require exclusion zones for each LNG container 

and LNG transfer system, and an LNG transfer system is defined in section 193.2007 to include 

cargo transfer system and transfer piping (whether permanent or temporary). However, 

NFPA 59A (2001) requires exclusion zones only for “transfer areas,” which is defined as the part 

of the plant where the facility introduces or removes the liquids, such as truck loading or shipunloading areas. The NFPA 59A (2001) definition does not include permanent plant piping, 

such as cargo transfer lines. Section 2.2.3.1 of NFPA 59A (2001) also states that transfer areas 

at the water edge of marine terminals are not subject to the siting requirements in that standard.

The DOT addressed some of these issues in a March 2010 letter of interpretation.30 In that letter, 

DOT stated that: (1) the requirements in the NFPA 59A (2001) for transfer areas for LNG apply

to the marine cargo transfer system at a proposed waterfront LNG facility, except where 

preempted by the regulations in Part 193; (2) the regulations in Part 193 for LNG transfer 

systems conflict with the NFPA 59A (2001) on whether an exclusion zone analysis is required 

for transfer piping or permanent plant piping; and (3) the regulations in Part 193 prevailed as a 

result of that conflict. The DOT determined that an exclusion zone analysis of the marine cargo 

transfer system is required.

In FERC environmental assessments/impact statements for past projects, we also noted that 

when the DOT incorporated NFPA 59A into its regulations, it removed the regulation that 

required impounding systems around transfer piping. As a result of that change, it is unclear 

whether Part 193 or the adopted sections of NFPA 59A (2001) require impoundments for LNG 

transfer systems. We note that Part 193 requires exclusion zones for LNG transfer systems, and 

that those zones are calculated based on impoundment systems. We also note that the omission 

of containment for transfer piping is not a sound engineering practice. For these reasons, we 

generally recommend containment for all LNG transfer piping within a plant’s property lines.

Federal regulations issued by the Occupational Safety and Health Administration (OSHA) under 

29 CFR § 1910.119 (Process Safety Management of Highly Hazardous Chemicals; Explosives 

 30 U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) 

Interpretation “Re: Application of the Siting Requirements in Subpart B of 49 CFR Part 193 to the Mount Hope Bay 

Liquefied Natural Gas Transfer System” (March 25, 2010).
4.12 – Reliability and Safety 4-320

and Blasting Agents (PSM)), and the U.S. EPA under 40 CFR 68 (Risk Management Plans) 

cover hazardous substances, such as methane, propane and ethylene at many facilities in the 

United States. However, OSHA and EPA regulations are not applicable to facilities regulated 

under 49 CFR 193. On October 30, 1992, shortly after the promulgation of the OSHA PSM 

regulations, OSHA issued a letter of interpretation that precluded the enforcement of PSM 

regulations over gas transmission and distribution facilities. In a subsequent letter on December 

9, 1998, OSHA further clarified that this letter of interpretation applies to LNG distribution and 

transmission facilities.

In addition, EPA’s preamble to its final rule in Federal Register, Volume 63, Number 3, 639-645, 

clarified that exemption from the requirements in 40 CFR 68 for regulated substances in 

transportation, including storage incident to transportation, is not limited to pipelines. The 

preamble further clarified that the transportation exemption applies to LNG facilities subject to 

oversight or regulation under 49 CFR 193, including facilities used to liquefy natural gas or used 

to transfer, store, or vaporize LNG in conjunction with pipeline transportation.

4.12.5 Siting Analysis

Suitable sizing of impoundment systems and selection of design spills on which to base hazard 

analyses are critical for establishing an appropriate siting analysis. Although impoundment 

capacity and design spill scenarios for storage tank impoundments are well described by Part 

193, a clear definition for other impoundments is not provided either directly by the regulations 

or by the adopted sections of NFPA 59A (2001). Under NFPA 59A (2001) Section 2.2.2.2, the 

capacity of impounding areas for vaporization, process, or LNG transfer areas must equal the 

greatest volume that can be discharged from any single accidental leakage source during a 10-

minute period or during a shorter time period based upon demonstrable surveillance and 

shutdown provisions acceptable to the DOT. However, no definition of single accidental leakage 

source is provided in the regulations.

We recommend that impoundments be sized based on the greatest flow capacity from any single 

pipe for 10 minutes, recognizing that different spill scenarios may be used for the single 

accidental leakage sources for calculation of Part 193 exclusion zones. A similar approach is 

used with impoundments for process vessels. We expect these impoundments be able to contain 

the contents of the largest process vessel served, while recognizing that smaller design spills may 

be appropriate for Part 193 exclusion zone calculations.

Impoundment Sizing

Part 193.2181 references NFPA 59A (2001) for siting, which specifies each impounding system 

serving an LNG storage tank must have a minimum volumetric liquid capacity of 110 percent of 

the LNG tank’s maximum design liquid capacity for an impoundment serving a single tank. We 

also consider it prudent design practice to provide a barrier to prevent liquid from flowing to an 

unintended area (i.e., outside the plant property) in the event that the full containment storage 

tank primary and secondary containers have a common cause failure. The purpose of the barrier 

is to prevent liquid from flowing off the plant property, and does not define containment or an 

impounding area for thermal radiation or flammable vapor exclusion zone calculations or other 

code requirements already met by sumps and impoundments throughout the site.
4-321 4.12 – Reliability and Safety

Downeast proposes two full-containment LNG storage tanks where the outer tank wall would 

serve as the impoundment system. As shown in table 4.12.5-1, the outer tank would have a 

volumetric capacity of 52,116,919 gallons, which exceeds the 110 percent requirement by 

4,737,902 gallons. The outer tank would contain 116 percent capacity of the inner tank, meeting 

the Part 193 requirements. Downeast also proposes to install an earthen rock barrier around the 

LNG tanks and associated process area to limit liquid from flowing off the plant property in the 

case of a common cause failure of the full containment storage tank primary and secondary 

containers. The structure would be 21 feet in height for the barrier and would enclose an area of 

approximately 10 acres. The structure's volumetric capacity would contain a single LNG tank's 

maximum liquid capacity and would meet our recommendation that a barrier be provided to 

prevent liquid from flowing off plant property.

Downeast proposes three insulated concrete impoundment basins to contain possible LNG spills

from piping and process areas: the Process Area Impoundment Basin; the Vaporizer Area 

Impoundment Basin; and the Transfer Area Impoundment Basin. 

The Process Area Impoundment Basin would serve the curbed area around the LNG storage 

tanks and the in-tank pumps. In this area, the greatest flow capacity from a single transfer pipe 

would be from the in-tank pump withdrawal header. Although each tank has space for three 

pumps, Downeast proposes to install only two pumps in this application, leaving the third pump 

column for future expansion. After the 2009 draft EIS was issued, Downeast revised the Process 

Area Impoundment Basin to have dimensions of 24-feet-wide by 24-feet-long by 22-feet-deep.31 

The sump would have a volume of 94,793 gallons to contain a header spill with the two in-tank 

pumps running at full rated capacity [(4,600 gpm rated flow) x (2 in-tank pumps) x (10 minutes) 

= 92,000 gallons]. The Process Area Impoundment Basin would also be able to contain the 

8,300 gallon HP Pump Drum, which is the largest process vessel serving the impoundment. The 

supplemental draft EIS using the pump rated flow neglects the potential maximum pump run-out 

flow rate of the in-tank pumps, which would produce a volume of 115,000 gallons [(5,750 gpm

maximum flow) x (2 in-tank pumps) x (10 minutes)]. As a result, Downeast revised the Process 

Area Impoundment Basin depth to 27 feet deep to accommodate the maximum pump run-out 

flow. Any future installation of a third in-tank pump would require another application to FERC 

under Section 3 of the Natural Gas Act and a new siting analysis. 

The Vaporizer Area Impoundment Basin would be located to the west of the vaporizers and 

would serve all four of the SCVs. After the 2009 draft EIS was issued, Downeast revised the 

Vaporizer Area Impoundment Basin to have dimensions of 20-feet-wide by 20-feet-long by 22-

feet-deep.32 The sump would have a volume of 65,828 gallons. There would be no process 

vessels which would drain to the Vaporizer Area Impoundment Basin. The supplemental draft 

EIS recognized using the failure of the 16-inch-diameter vaporizer inlet line and accounting for

the pump run-out flow rate of all four proposed pumps (including the backup pump that would 

be installed) would yield a sizing spill volume of 75,040 gallons [(1,876 gpm maximum pump 

 31 The original design of the Process Area Impoundment Basin listed in the application was 30-feet-wide by 30-feetlong by 22-feet-deep, equating to an available capacity of 148,114 gallons. This size appeared to be based on 

potential flow from a third in-tank pump, even though the application only proposed two pumps. 32 The original Vaporizer Area Impoundment Basin listed in the application was 30-feet-wide by 30 feet-long by 22-

feet-deep, equating to an available capacity of 148,114 gallons. 
4.12 – Reliability and Safety 4-322

run-out flow rate) x (4 high-pressure pumps) x (10 minutes)]. As a result, Downeast revised the 

Vaporizer Area Impoundment Basin depth to 26 feet deep to accommodate the larger spill.

The Transfer Area Impoundment Basin would serve the loading and recirculation lines and 

would have dimensions of 60-feet-wide by 60-feet-long by 24-feet-deep (this would also be 

equipped with internal weirs 45-feet-wide by 45-feet-long by 24-feet-deep). These dimensions 

yield an available capacity of 646,317 gallons. Downeast sized this impoundment basin for a 

full rupture of the unloading line during unloading operations. The 36-inch-diameter unloading 

line would have a flow rate of 61,745 gpm, equating to a sizing spill of 617,450 gallons over a 

10-minute period. The Transfer Area Impoundment Basin would contain the above-mentioned 

spill. The Transfer Area Impoundment Basin would also be able to contain the 5,300 gallon 

Jetty Drum, which is largest process vessel serving the impoundment.

The spill volumes and corresponding impoundment volumes are shown in table 4.12.5-1.

TABLE 4.12.5-1

Impoundment Area Sizing

Source

Spill Size

(gallons) Impoundment System

Impoundment 

Size

(gallons)

LNG Storage Tank 45,117,046 Outer Tank Concrete Wall 52,116,919

In-tank pump withdrawal header 115,000 Process Area Impoundment Basin (S-606) 116,337

HP pump discharge line 75,040 Vaporization Area Impoundment Basin (S-607) 77,797

36-inch Unloading Line 617,450 Transfer Area Impoundment Basin (s-608) 646,317

Design Spills

Design spills are used in the determination of vapor dispersion and thermal radiation exclusion 

zones required by Part 193. Prior to the incorporation of NFPA 59A in 2000, the design spill in 

Part 193 assumed the full rupture of “a single transfer pipe which has the greatest overall flow 

capacity” for not less than 10 minutes (old Part 193.2059(d)). With the adoption of NFPA 59A, 

the basis for the design spill for impounding areas serving only vaporization, process, or LNG 

transfer areas became the flow from any single accidental leakage source.

As neither Part 193 nor NFPA 59A (2001) defines “single accidental leakage source”, FERC 

staff sent a letter to the DOT on April 19, 2005, requesting concurrence on proposed procedures 

for determining a single accidental leakage source. As described in that letter, FERC staff based 

the determination of the single accidental leakage source on an evaluation of all small diameter 

attachments to the transfer piping for instrumentation, pressure relief, recirculation, etc., and any 

flanges that may be used at valves or other equipment, in order to determine the largest spill rate. 

The DOT affirmed this approach in a May 6, 2005 response.

However, this approach did not provide any quantitative justification for the selection of the 

design spill to be used in Part 193 hazard & exclusion zone calculations, and a wide variety of 

single accidental leakage sources, ranging from packing and flange leaks to full guillotine 

ruptures of ship unloading lines, were proposed in applications before the FERC. To achieve a 

more consistent approach, we began using equipment failure rates to establish a more 

quantitative threshold for single accidental leakage source under Part 193. Table 4.12.5-2
4-323 4.12 – Reliability and Safety

provides types of failures and associated failure rates (Mniszewski, 1984; GRI, 1981; Welker, 

1979; Pelto, 1984; Pelto, 1982; Mannan, 2005; RIVM, 1999; RIVM, 1992; RIVM, 1997; HSE, 

2011; RIVM, 2009). 

For storage tanks with over-the-top-fill and no penetrations below the liquid level, Part 193, 

through adopted portions of NFPA 59A (2001), defines the design spill as the largest flow from 

any single line that could be pumped into the impounding area with the container withdrawal 

pumps delivering the full-rated capacity. Based on published failure rates for LNG facilities, the 

rupture of a storage tank outlet line is on the order of one failure every 20,000 to 30,000 

equipment-years (6x10-5 to 3x10-5 failures per 8,760 hours of equipment operation). Because 

this failure rate applies to a design spill that is specified by Part 193, we believe it could be used 

as a threshold for determining single accidental leakage sources for impounding areas serving 

liquefaction process and transfer areas. Selecting a design spill based on equipment failure rates 

equivalent to the failure specified by Part 193 for storage tanks provides a more consistent 

quantitative basis for design spills. DOT concurred with this approach for Part 193 

calculations.33

TABLE 4.12.5-2

Equipment Failure Rates

Type of Failure Failures per equipment-year

Cryogenic Storage Tanks (General)

Rupture of Storage Tank Outlet Line 3E-5 (criteria)

Single Containment Atmospheric Storage Tanks

Catastrophic Failure of Inner Tank (Rupture) 5E-6 per tank

Catastrophic Failure of Tank Roof 1E-4 per tank

Release from a hole with effective diameter of 1m (~3ft) 8E-5 per tank

Release from a hole with effective diameter of 0.3m (~1ft) 2E-4 per tank

Release from a hole with effective diameter of 0.01m (0.4in) 1E-4 per tank

Double Containment Atmospheric Storage Tanks

Catastrophic Failure of Inner Tank (Rupture) 5E-7 per tank

Catastrophic Failure of Tank Roof 1E-4 per tank

Release from a hole with effective diameter of 1m (~3ft) 1E-5 per tank

Release from a hole with effective diameter of 0.3m (~1ft) 3E-5 per tank

Release from a hole with effective diameter of 0.01m (0.4in) 1E-4 per tank

Full Containment Atmospheric Storage Tanks

Catastrophic Failure of Inner Tank (Rupture) 1E-8 per tank

Catastrophic Failure of Tank Roof 4E-5 per tank

Release from a hole with effective diameter of 1m (~3ft) 1E-6 per tank

Release from a hole with effective diameter of 0.3m (~1ft) 3E-6 per tank

Release from a hole with effective diameter of 0.01m (0.4in) 1E-4 per tank

Process Vessels, Distillation Columns, Heat Exchangers, & Condensers

Catastrophic Failure (Rupture) 5E-6 per vessel

Release from a hole with effective diameter of 0.01m (0.4in) 1E-4 per vessel

 33 PHMSA Interpretation: Letter to Mr. Leon A. Bowdoin, Jr., Regarding The Applicability of 49 CFR 193.2059(c) 

to a Hypothetical Waterfront Liquefied Natural Gas Plant. (February 28, 2012)
4.12 – Reliability and Safety 4-324

TABLE 4.12.5-2

Equipment Failure Rates

Type of Failure Failures per equipment-year

Truck Transfer

Rupture of transfer arm 3E-4 per transfer arm

Release from a hole in transfer arm with effective diameter of 10% transfer arm 

diameter with maximum of 50mm (2-inches) 3E-3 per transfer arm

Rupture of transfer hose 4E-2 per transfer hose

Release from a hole in transfer hose with effective diameter of 10% transfer hose 

diameter with maximum of 50mm (2-inches) 4E-1 per transfer hose

Ship Transfer

Rupture of transfer arm 2E-5 per transfer arm

Release from a hole in transfer arm with effective diameter of 10% diameter with 

maximum of 50mm (2-inches) 2E-4 per transfer arm

Piping (General)

Rupture at Valve 9E-6 per valve

Rupture at Expansion Joint 4E-3 per expansion joint

Failure of Gasket 3E-2 per gasket

Piping: d< 50mm (2-inch)

Catastrophic rupture 1E-6 per meter of piping

Release from hole with effective diameter of 25mm (1-inch) 5E-6 per meter of piping

Piping: 50mm (2-inch) ≤d< 149mm (6-inch)

Catastrophic rupture 5E-7 per meter of piping

Release from hole with effective diameter of 25mm (1-inch) 2E-6 per meter of piping

Piping: 150mm (6-inch) ≤d< 299mm (12-inch)

Catastrophic rupture 2E-7 per meter of piping

Release from hole with effective diameter of 1/3 diameter 4E-7 per meter of piping

Release from hole with effective diameter of 25mm (1-inch) 7E-7 per meter of piping

Piping: 300mm (12-inch) ≤d< 499mm (20-inch)

Catastrophic rupture 7E-8 per meter of piping

Release from hole with effective diameter of 1/3 diameter 2E-7 per meter of piping

Release from hole with effective diameter of 10% diameter, up to 50mm (2-inches) 4E-7 per meter of piping

Release from hole with effective diameter of 25mm (1-inch) 5E-7 per meter of piping

Piping: 500mm (20-inch) ≤d

Catastrophic rupture 2E-8 per meter of piping

Release from hole with effective diameter of 1/3 diameter 1E-7 per meter of piping

Release from hole with effective diameter of 10% diameter, up to 50mm (2-inches) 2E-7 per meter of piping

Release from hole with effective diameter of 25mm (1-inch) 4E-7 per meter of piping

In addition, DOT requested in a letter to the FERC staff, dated August 6, 2013, that LNG facility 

applicants contact the Office of Pipeline Safety's Engineering and Research Division regarding 

the Part 193 siting requirements.34 Specifically, DOT stated that it required a technical review of 

 34 August 6, 2013 Letter from Kenneth Lee, Director of Engineering and Research Division, Office of Pipeline 

Safety to Terry Turpin, LNG Engineering and Compliance Branch, Office of Energy Projects. Filed in Docket 

Number CP07-52 on August 13, 2013. Accession Number 20130813-400 
4-325 4.12 – Reliability and Safety

the applicant’s design spill criteria for single accidental leakage sources on a case-by-case basis 

to determine compliance with Part 193. 

In response, Downeast provided DOT with its design spill criteria and identified leakage 

scenarios for the proposed equipment based on the failure rate approach described above. DOT 

reviewed the data and methodology Downeast used to determine the design spills based on the 

flow from various leakage sources, including piping, containers, and equipment containing

hazardous fluids. On January 30, 2014, DOT provided a letter to the FERC staff stating that 

DOT had no objection to Downeast's methodology for determining the single accidental leakage 

source for the candidate design spills to be used in establishing the Part 193 siting requirements 

for the proposed LNG liquefaction facilities.35,36 The design spills produced by this method 

were identified in the documents reviewed by DOT and have been filed in the docket for this 

project. These are the same design spills described in the following sections.

DOT’s conclusions on the candidate design spills used in the siting calculations required by Part 

193 was based on preliminary design information which may be revised as the engineering 

design progresses. If Downeast’s design or operation of the proposed facility differs from the 

details provided in the documents on which DOT based its review, then the facility may not 

comply with the siting requirements of Part 193. As a result, we recommend that: 

• Prior to the construction of the final design, Downeast should file with the Secretary 

for review and approval by the Director of OEP, certification that the final design is 

consistent with the information provided to DOT as described in the design spill 

determination letter dated January 30, 2014 (Accession Number 20140203-4005). In 

the event that any modifications to the design alters the candidate design spills on 

which the Title 49 CFR Part 193 siting analysis was based, Downeast should consult 

with DOT on any actions necessary to comply with Part 193. 

As design spills vary depending on the hazard (vapor dispersion, overpressure or radiant heat), 

the specific design spills used for the Downeast siting analysis are discussed under “Vapor 

Dispersion Analysis” and “Thermal Radiation Analysis” in this section.

Vapor Dispersion Analysis

As discussed in section 4.12.2, a large quantity of LNG spilled without ignition would form a 

flammable vapor cloud that would travel with the prevailing wind until it either dispersed below 

the flammable limit or encountered an ignition source. In order to address this hazard, 49 CFR § 

193.2059 requires each LNG container and LNG transfer system to have a dispersion exclusion 

 35 January 30, 2014 Letter “Re: Downeast LNG Project, FERC Docket No. CP07-52-000 and CP07-53-000, Design 

Spill Determination” from Kenneth Lee to Lauren H. O'Donnell. Filed in Docket Number CP07-52 on February 3, 

2014. Accession Number 20140203-4005 36 PHMSA based this decision on the following documents: (1) Downeast Response to FERC Data Request, 

Accession Number 20091029-5075; (2) Downeast Response to FERC Data Request, Accession Number 20121012-

5103; (3) Downeast Response to FERC Data Request, Accession Number 20121113-5487; (4) Downeast Response 

to FERC Data Request, Accession Number 20120523-5172; (5) FERC Supplemental Draft Environmental Impact 

Statement (DEIS), Accession Number 20130328-4001; (6) Downeast Response to the Supplemental DEIS, 

Accession Number 20130523-5131; (7) Downeast Response to FERC Data Request, Accession Numbers 

20130927-5214 & 5215; and (8) Downeast Response to PHMSA Data Request, Accession Numbers 20140130-5363 

and 20140130-5364
4.12 – Reliability and Safety 4-326

zone in accordance with sections 2.2.3.3 and 2.2.3.4 of NFPA 59A (2001). Taken together, Part 

193 and NFPA 59A (2001) require that flammable vapors either from an LNG tank 

impoundment or a single accidental leakage source do not extend beyond a facility property line 

that can be built upon. This is the Part 193 standard that we used in analyzing the siting of the 

proposed Project.

Title 49 CFR §193.2059 requires that dispersion distances be calculated for a 2.5 percent average 

gas concentration (one-half the LFL of LNG vapor) under meteorological conditions which 

result in the longest downwind distances at least 90 percent of the time. Alternatively, maximum 

downwind distances may be estimated for stability Class F, a wind speed of 4.5 mph, 50 percent 

relative humidity, and the average regional temperature.

The regulations in Part 193 specifically approve the use of two models for performing these 

dispersion calculations, DEGADIS and FEM3A. The use of alternative models is also allowed, 

but must be specifically approved by the DOT. Although Part 193 does not require the use of a 

particular source term model, modeling of the spill and resulting vapor production is necessary 

prior to the use of vapor dispersion models. In the past, applicants have typically used the 

SOURCE5 program to model the vapor production from an LNG spill.

Based on requests for clarification on the source term requirements of Part 193, the DOT issued 

two formal interpretations in July of 2010 regarding the regulations under 49 CFR 193.

37 In 

these interpretations, the DOT stated that:

• SOURCE5 could no longer be used to determine the vapor gas exclusion zone for 

compliance with § 193.2059 unless the deficiencies identified in the Fire Protection 

Research Foundation’s reports “Evaluating Vapor Dispersion Models for Safety Analysis 

of LNG Facilities Research Project (April 2007)” and “LNG Source Term Models for 

Hazard Analysis: A Review of the State-of-the-Art and an Approach to Model 

Assessment (March 2009)” had been addressed;

• source term models must have a credible scientific basis and must not ignore phenomena 

which can influence the discharge, vaporization, and conveyance of LNG; and 

• an alternative source term model proposed by Downeast was suitable for siting 

impoundments, but the effects of flashing and jetting (and any other phenomena having a 

similar influence on the discharge, vaporization, or conveyance of LNG) must be 

considered in order to comply with §193.2059.

As a result of these interpretations, alternative dispersion models became necessary in order to 

examine the effects of jetting, flashing and conveyance of LNG for exclusion zone calculations. 

In August 2010, the DOT issued Advisory Bulletin ADB-10-07 to provide guidance on obtaining 

approval of alternative vapor-gas dispersion models under Subpart B of 49 CFR 193. In October 

2011, two dispersion models were approved by DOT for use in vapor dispersion exclusion zone 

 37 PHMSA Interpretation “Re: Request for Written Interpretation on the Applicability of 49 CFR 193 to Proposed 

Waterfront Liquefied Natural Gas Plant in the City of Fall River, Massachusetts” (July 7, 2010) and PHMSA 

Interpretation “Re: Request for Written Interpretation on the Applicability of 49 CFR 193 to Proposed LNG Import 

Terminal in Robbinston, Maine” (July 16, 2010).
4-327 4.12 – Reliability and Safety

calculations: PHAST-UDM Version 6.6 and Version 6.7 (submitted by Det Norske Veritas) and 

FLACS Version 9.1 Release 2 (submitted by GexCon).

On May 23, 2012, and October 12, 2012, as supplemented on October 26 and November 13, 

2012, Downeast submitted analyses to address the vapor dispersion analysis requirements of Part 

193. PHAST 6.7 and FLACS 9.1, with their built-in source term models, were used to calculate 

dispersion distances. As the 2011 DOT approvals of the alternative dispersion models did not 

address source term models, we consulted with the DOT on Downeast’s submitted PHAST and 

FLACS source term modeling. Based on our consultation with DOT staff, we conclude that the 

use of the PHAST flashing and jetting source term models and the use of the FLACS flashing /

jetting / pool spread and vaporization source term models are suitable and comply with the siting 

requirements of Part 193 for this project. As this determination must be made on a project 

specific basis, this conclusion would need to be revisited for future applications of these source 

models.

As discussed under “Design Spills” in section 4.12.5, failure scenarios must be selected as the 

basis for the Part 193 dispersion analyses. Process conditions at the failure location would affect 

the resulting vapor dispersion distances. In determining the spill conditions for these leakage 

sources, process flow diagrams for the proposed design, used in conjunction with the heat and 

material balance information (i.e., flow, temperature, and pressure), can be used to estimate the 

flow rates and process conditions at the location of the spill. In general, higher flow rates would 

result in larger spills and longer dispersion distances; higher temperatures would result in higher 

rates of flashing; and higher pressures would result in higher rates of jetting and aerosol 

formation. Therefore, two scenarios may be considered for each design spill:

• The pressure in the line is assumed to be maintained by pumps and/or hydrostatic head to 

produce the highest rate of flashing and jetting (i.e. flashing and jetting scenario); and

• The pressure in the line is assumed to be depressurized by the breach and/or emergency 

shutdowns to produce the highest rate of liquid flow within a curbed, trenched, or 

impounded area (i.e. liquid scenario).

Alternatively, a single scenario for each design spill could be selected if adequately supported 

with an assessment of the depressurization calculations and/or an analysis of process 

instrumentation and shutdown logic acceptable to DOT.

In addition, the location and orientation of the leakage source must be considered. The closer a 

leakage source is to the property line, the higher the likelihood that the vapor cloud would extend 

off-site. As most flashing and jetting scenarios would not have appreciable liquid rainout and 

accumulation, the siting of impoundment systems would be driven by liquid scenarios, while 

siting of remaining portions of the plant would be driven by flashing and jetting scenarios.

Downeast reviewed 266 single accidental leakage sources for the liquid scenarios and for the 

flashing and jetting scenarios. Downeast used the following conditions, corresponding to 49 

CFR 193.2059, for the vapor dispersion calculations: ambient temperature of 69°F, relative 

humidity of 50 percent, wind speed of 4.5 mph in various directions, atmospheric stability class 

of F and a ground surface roughness of 0.03 meters. In addition, a sensitivity analysis to the 
4.12 – Reliability and Safety 4-328

wind speed and direction was provided to demonstrate the longest predicted downwind 

dispersion distance in accordance with the PHAST and FLACS Final Decisions. A sensitivity 

analysis to a ground surface roughness of 0.01 meters was also provided for spills over water.

Downeast accounted for the facility geometry, including the impoundment and trench geometry 

details as established by available plant layout drawings. Including the plant geometry accounts

for any on-site wind channeling that could occur and allows for inclusion of mitigation measures, 

such as vapor fences. The releases were initiated after sufficient time had passed in the model 

simulations to allow the wind profile to stabilize from effects due to the presence of buildings 

and other on-site obstructions.

In order to address the highest rate of LNG liquid flow (i.e. liquid scenario) into the Process Area 

Impoundment Basin, and in accordance with table 2.2.3.5 of NFPA 59A (2001) for storage tanks 

with over-the-top fill and no penetrations below the liquid level, Downeast specified the design 

spill as a complete rupture of the 20-inch-diameter discharge header with both in-tank pumps 

running at full rated capacity [(4,600 gpm rated flow) x (2 in-tank pumps) = 9,200 gpm]. In 

order to address the highest rate of LNG flashing and jetting from piping in the Process Area, 

Downeast submitted a release through a 2-inch-diameter hole in this piping, calculated to be 785 

gpm. However, in performing the vapor dispersion modeling for flashing and jetting scenarios, 

Downeast actually used a larger spill from a 6-inch-diameter release of approximately 7,775 gpm 

from LNG piping in the tank.

In order to address the highest rate of LNG liquid flow (i.e. liquid scenario) into the Vaporizer 

Area Impoundment Basin, Downeast specified the design spill as a complete rupture of the 6-

inch-diameter vaporizer-inlet line, resulting in a 3,448 gpm spill rate. In order to address the 

highest rate of LNG flashing and jetting from piping in the Process Area, Downeast submitted a 

release through a 1-inch-diameter hole in the high pressure pump area, calculated to be 1,127 

gpm. However, in performing the vapor dispersion modeling for flashing and jetting scenarios, 

Downeast actually used a larger 3-inch-diameter release of approximately 1,380 gpm from LNG 

piping in the high pressure pump area.

In order to address the highest rate of LNG liquid flow (i.e. liquid scenario) into the Transfer 

Area Impoundment Basin, Downeast specified the design spill as a hole equivalent to 1/3 

diameter of the 36-inch-diameter transfer line, resulting in a 32,330 gpm spill rate. In order to 

minimize jetting effects, Downeast proposes to install a 6-foot high vapor fence that runs along 

each side of the transfer line. With the vapor fences, a hole sensitivity analysis showed the 

highest amount of vapor would be produced by the 12-inch hole along the transfer line. In 

addition, Downeast considered a 4-inch-diameter release from LNG piping in the dock area

where there would not be any vapor fences resulting in an orifice flow rate of approximately 

3,450 gpm. Table 4.12.5-3 summarizes the design spills specified by Downeast.
4-329 4.12 – Reliability and Safety

TABLE 4.12.5-3

LNG Design Spills

Scenario Release location Equivalent Hole Size Total Flow Rate 

(gpm)

Liquid Fraction

(%)

1 Process Area 20-inch 9,200 100

2 Process Area 6-inch 7,775 0

3 Vaporizer Area 6-inch 3,448 100

4 Vaporizer Area 3-inch 1,380 0

5 Transfer Line 12-inch 32,330 100

6 Transfer Line 12-inch 32,330 95

7 Dock Area 4-inch 3,450 0

Downeast’s simulations indicated the need for a series of 20-30 foot high vapor fences 

throughout the onshore plant and a 6 foot high vapor fence along each side of the transfer line. 

Downeast proposes a fence made of impermeable Galvalume panels fastened to galvanized 

beams and posts to act as a vapor barrier to prevent the LNG vapor from extending beyond the 

western, northern, and southern property lines. There would be no vapor fence along the eastern 

property line adjacent to the waterway. The vapor fences are shown in Figure 4.12.5-1.

Figure 4.12.5-1 Vapor Fences Proposed at Downeast Onshore Facilities

Fence A would be 20 feet high, Fence B would be 25 feet high, and Fence C would be 30 

feet high.
4.12 – Reliability and Safety 4-330

In its filings, Downeast presented that the 1⁄2 LFL vapor cloud for flashing and jetting cases 

would remain within the Downeast LNG property or would not extend beyond the property line 

to the west, north or south considering installation of the vapor barriers. Downeast stated that the 

vapor barriers would be routinely inspected by personnel and repaired as necessary. In addition, 

security patrols would observe the vapor barriers during their regular rounds and report any 

observed damage. In order to ensure that the vapor barriers are maintained throughout the life of 

the facility, we recommend that:

• Prior to construction of the final design, Downeast should file with the Secretary for 

review and written approval by the Director of OEP, procedures to maintain and 

inspect the vapor barriers provided to meet the siting provisions of 49 CFR 

193.2059. This information should be filed a minimum of 30 days before approval 

to proceed is requested. 

The flammable vapor dispersion results are consolidated into figure 4.12.5-2. The FLACS 

simulations showed that, due to the proposed vapor fences within the plant, none of the design 

spills would result in the 1⁄2 LFL vapor dispersion extending over a property line that could be 

built upon. As a result, we conclude that the siting of the proposed facility would not have a 

significant impact on public safety. If the facility is constructed and operated, compliance with 

the requirements of 49 CFR 193 would be addressed as part of DOT’s inspection and 

enforcement program.

 Downeast dispersion results

Figure 4.12.5-2 Vapor Dispersion Exclusion Zones
4-331 4.12 – Reliability and Safety

We received comments on Downeast’s vapor dispersion exclusion zones extending beyond the 

shoreline along the eastern property line and over public access routes to intertidal recreation and 

study areas. The commentor stated that, as Downeast would have no ability to control public 

access in these areas, the exclusion zones would be in violation of Part 193. DOT has indicated 

an exclusion zone that extends past a property line into a navigable body of water or onto a 

public road is typically acceptable unless the body of water contains a dock or pier that is not 

controlled by the LNG plant or if another entity could build a building or members of the public 

could assemble. During the development of the supplemental draft EIS, we raised the issue with 

the vapor dispersion exclusion zones extending past the property line onto the waterway and 

intertidal zone with DOT. DOT staff informed FERC staff that the vapor dispersion exclusion 

zones onto the waterway and intertidal zone would not violate the Part 193 exclusion zone 

requirements.

Overpressure Considerations

As discussed in section 4.12.2, the propensity of a vapor cloud to detonate or produce damaging 

overpressures is influenced by the ignition source, reactivity of the material, the level of 

confinement and congestion surrounding and within the vapor cloud, and the flame travel 

distance. It is possible that the prevailing wind direction may cause the vapor cloud to travel into 

a partially confined or congested area. 

As adopted by Part 193, Section 2.1.1 of NFPA 59A (2001) requires an evaluation of potential 

incidents and safety measures incorporated in the design or operation of the facility be 

considered. As discussed under “Overpressures” in section 4.12.2, unconfined LNG vapor 

clouds would not be expected to produce damaging overpressures. The presence of heavier 

hydrocarbons influences the propensity for a detonation or deflagration with damaging 

overpressures. Product with greater amounts of heavier hydrocarbons is more sensitive to 

detonation. LNG facilities have typically imported LNG with methane concentrations ranging 

from 89 percent to 96 percent with occasional imports as low as 86 percent. The Downeast LNG

import facility would be designed to receive LNG with methane concentrations as low as 87 

percent. These compositions are not in the range shown to exhibit overpressures and flame 

speeds associated with high-order explosions and detonations.

The Coast Guard studies referenced under “Overpressures” in section 4.12.2 indicated 

overpressures of 4 bar and flame speeds of 35 m/s (meters per second) were produced from 

vapor clouds of 86 percent to 96 percent methane in near stoichiometric proportions using 

exploding charges as the ignition source. The 4 bar overpressure was the same overpressure 

produced during the calibration test involving exploding the charge ignition source alone, so it 

remains unclear that the overpressure was attributable to the vapor deflagration. However, 

unconfined methane vapor clouds ignited with low energy ignition sources have been shown to 

produce flame speeds ranging from 5.2 to 7.3 m/s, which is much less than the flame speeds 

associated with explosions or detonations. 

Additional tests were conducted to study the influence of confinement and congestion on the 

propensity of a vapor cloud to detonate or produce damaging overpressures. The tests used 

obstacles to create a partially confined and turbulent scenario, but found that flame speeds 

developed for methane were not significantly higher than the unconfined case and were not in 

the range associated with detonations.
4.12 – Reliability and Safety 4-332

For unconfined and congested vapor clouds, we still evaluated the proposed plant design and 

found that most areas of confinement and congestion would be within the process areas of the 

plant. These areas would be less likely to ignite a vapor cloud due to required safety measures, 

such as the electrical area classification for Class 1, Division 1 or 2. However these areas are not 

without risk, therefore, despite these safety measures, we used the BST methodology, recently 

updated based on the work of Pierorazio, Thomas, Baker, and Ketchum in 2005, in order to 

investigate the effects of such a vapor cloud migrating into a congested area.

Based on our analysis of the proposed layout and pipe rack cross-sections, the process areas 

would have volume and area blockage ratios consistent with a low congestion area and would 

allow for expansion consistent with 2.5D confinement (i.e. pipe rack where pipes are almost 

touching). The primary flammable substances in the process area would be methane. Using the 

revised BST methodology, the vapor cloud explosion overpressures would not reach 1 psi, a 

value used in consequence analyses by FERC staff and required under other federal agency 

regulations, such as Title 40 CFR Part 68.22, reflective of damage to light wooden framed 

structures and shattering of glass.

After the 2009 draft EIS was issued, we received comments on whether the vapor fences would 

cause a confinement and potentially result in damaging overpressures from an ignited vapor 

cloud. The 6-foot vapor fences along the dock are separated by nearly 18 feet and the 30-foot 

and 25-foot tall vapor fences are nearly 80 feet apart where the two run parallel and closest to 

each other at the western property line. These separation distances are more than adequate 

enough to prevent any pressure build-up if there is a lack of congestion between the vapor 

fences. However, Downeast has indicated that approximately 33 acres of forested area, 

including a 250 treeline buffer, would be maintained along the shoreline and within the plant 

boundaries and vapor fences. These trees were not accounted for in the vapor dispersion hazard 

analyses and were not considered in any vapor cloud explosion hazard analyses. Although the 

presence of the trees should reduce the vapor dispersion distances, the congestion from the trees 

could cause a vapor cloud explosion hazard depending on the level of congestion. Therefore, we 

recommend that:

• Prior to initial site preparation, Downeast should file with the Secretary for review 

and written approval by the Director of OEP, certification that all trees would be 

removed from the area between the vapor fences and the shoreline. Alternatively, 

Downeast may demonstrate that the spacing of the trees, and any vegetation 

management plan, would prevent congested areas that could produce offsite 

overpressures above 1 psi. 

Given the LNG compositions which would be handled onsite, potential ignition sources, and the 

expected vapor dispersion characteristics, damaging overpressures would not be expected to 

occur from ignition of an unconfined vapor cloud. 

Ignition of a confined vapor cloud could also result in higher overpressures. In order to prevent 

such an occurrence, buildings are typically located away from process areas containing 

flammable materials. Furthermore, as required by our recommendation in section 4.12.3, 

Downeast would need to demonstrate that all areas are adequately covered by hazard detection 

devices. A preliminary evaluation of the Downeast facility indicates the only enclosed buildings

within the facility would be the administrative building, control room building, and electrical 
4-333 4.12 – Reliability and Safety

switchgear building. In order to reduce the likelihood of flammable vapors dispersing into these 

buildings, Downeast proposes to pressurize these buildings, elevate the heating, ventilation, and 

air conditioning (HVAC) intakes above the maximum height of any modeled flammable vapor 

cloud, and install a flammable gas detector at the HVAC intake to initiate an alarm and shutdown 

of the HVAC blower upon detection of 20 percent LFL gas concentrations. We believe these 

measures provide sufficient protection and that the potential for overpressures from confined 

vapor clouds would be negligible.

Thermal Radiation Analysis

As discussed in section 4.12.2, if flammable vapors are ignited, the resulting pool fire would 

cause high levels of thermal radiation (i.e., heat from a fire). In order to address heat from pool 

fires, 49 CFR § 193.2057 specifies hazard endpoints in terms of flux levels for spills into LNG 

storage tank containment and spills into impoundments for process or transfer areas. For any 

distance from a pool fire, a flux level which expresses how much thermal radiation would be 

received at that point can be calculated. Each LNG container and LNG transfer system is 

required to have a thermal exclusion zone in accordance with Section 2.2.3.2 of NFPA 59A 

(2001). Together, Part 193 and NFPA 59A (2001) specify different hazard endpoints for spills 

into LNG storage tank containment and spills into impoundments for process or transfer areas. 

For LNG storage tank spills, there are three radiant heat flux levels which must be considered:

• 1,600 British thermal units per square foot per hour (Btu/ft2-hr) - This level can extend 

beyond the facility’s property line that can be built upon but cannot include areas that, at 

the time of facility siting, are used for outdoor assembly by groups of 50 or more persons;

• 3,000 Btu/ft2-hr - This level can extend beyond the facility’s property line that can be 

built upon but cannot include areas that, at the time of facility siting, contain assembly, 

educational, health care, detention or residential buildings or structures; and

• 10,000 Btu/ft2-hr - This level cannot extend beyond the facility’s property line that can be 

built upon.

The requirements for smaller spills from process or transfer areas are more stringent. For these 

impoundments, the 1,600 Btu/ft2-hr flux level cannot extend beyond the facility’s property line 

that can be built upon. 

Part 193 requires the use of the LNGFIRE3 computer program model developed by the Gas 

Research Institute to determine the extent of the thermal radiation distances. Part 193 stipulates 

that the wind speed, ambient temperature, and relative humidity that produce the maximum 

exclusion distances must be used, except for conditions that occur less than 5 percent of the time 

based on recorded data for the area.

For its analysis, Downeast calculated thermal radiation distances for the 1,600-, 3,000-, and

10,000-Btu/ft2

-hr incident radiant heat levels for the LNG storage tank using the outer tank’s 

concrete wall diameter (254 feet) as the pool diameter. The flame height was set equal to the top 

of the concrete wall (142.75 feet). In addition, Downeast calculated thermal radiation distances 

using LNGFIRE3 for the 1,600-Btu/ft2-hr incident radiant heat levels centered on the Process 

Area Impoundment Basin, the Vaporizer Area Impoundment Basin, and the Transfer Area 

Impoundment Basin. Downeast selected the following ambient conditions to produce the 
4.12 – Reliability and Safety 4-334

maximum exclusion distances: wind speeds of 8-16 mph, ambient temperature of 15°F, and 47

percent relative humidity. 

For the storage tanks, target heights were set at 0 feet and 52 feet to reflect the minimum and 

maximum ground level elevation changes from to an offsite area affected by the radiant heat. 

The elevated target height for the storage tank provides higher thermal radiation intensities as the 

target would be closer to the elevated fire. For the impoundments, target heights were set at 

0 feet as the ground level elevation changes were minimal from the impoundments to offsite 

areas affected by the radiant heat. The resulting maximum thermal radiation distances are shown 

in table 4.12.5-4, figure 4.12.5-3 and figure 4.12.5-4.

TABLE 4.12.5-4

Thermal Radiation Exclusion Zones for Impoundment Basins

Flux Level

(Btu/ft2

-hr )

Full Containment 

Tank Outer 

Containment (ft)*

Process Area 

Impoundment Basin 

(ft)*

Vaporizer Area 

Impoundment Basin 

(ft)*

Transfer Area 

Impoundment Basin 

(ft)*

10,000 429 58 38 194

3,000 741 113 96 268

1,600 950 137 115 322

*from center of impoundment

As shown in figure 4.12.5-3, both the 10,000-, and 3,000-Btu/ft2-hr heat flux for the LNG 

storage tanks would remain within the facility property lines. The 1,600 Btu/ft2-hr flux level 

would extend beyond the facility property line onto US Route 1. DOT has indicated that an 

exclusion zone that extends past a property line into a navigable body of water or onto a public 

road is typically acceptable. As a result, we conclude that the siting of the proposed LNG 

storage tanks would not have a significant impact on public safety. If the facility is constructed 

and operated, compliance with the requirements of 49 CFR 193 would be addressed as part of 

DOT’s inspection and enforcement program.

As shown in figure 4.12.5-4, the 1,600 Btu/ft2-hr heat flux for the Process Area Impoundment 

Basin and the Vaporizer Area Impoundment Basin would remain within the facility property 

lines. The 1,600 Btu/ft2

-hr heat flux for the Transfer Area Impoundment Basin would extend 

beyond the facility property line over portions of the shoreline and waterway. As indicated by 

DOT staff, an exclusion zone that extends past a property line into a navigable body of water or 

onto a public road is typically acceptable unless the body of water contains a dock or pier that is 

not controlled by the LNG plant or if another entity could build a building or members of the 

public could assemble. Accordingly, we consulted DOT on the thermal radiation exclusion 

zones extending past the property line onto the waterway and intertidal zone where comments

indicated possible areas of public access routes to recreation and study areas. During the 

development of the supplemental draft EIS, DOT staff informed FERC staff that the thermal 

radiation exclusion zones onto the waterway and intertidal zone would not violate their exclusion 

zone requirements. As a result, we conclude that the siting of these impoundments would not 

have a significant impact on public safety.
4-335 4.12 – Reliability and Safety

Figure 4.12.5-3 Thermal Radiation Exclusion Zones for Storage Tanks

Figure 4.12.5-4 Thermal Radiation Exclusion Zones for Impoundment Basins
4.12 – Reliability and Safety 4-336

The proposed layout of the facility would also meet the NFPA 59A (2001) separation 

requirements of a distance equal to 0.7 times the tank diameter between the storage tank and the 

property line (178 feet for the tank design under consideration). However, the 10,000 Btu/ft2

-hr 

incident heat flux for the LNG storage tanks would extend over occupied buildings, such as the 

main control building, administrative building, and maintenance building, and over equipment 

that is critical to the safe shutdown and operation of emergency equipment, such as the power 

distribution building transformers and emergency generator. In addition, the 3,000 Btu/ft2

-hr 

incident heat flux for the Vaporizer Area Impoundment Basin would extend over the vaporizers, 

high pressure pumps, and associated equipment. Although there are no provisions within Part 

193 or NFPA 59A (2001) which would prohibit this layout, we do not consider this to be 

appropriate design practice. As a result, we recommend:

• Prior to construction of the final design, Downeast should file the following 

information: 

a. an evaluation that justifies the location of occupied buildings, including the main 

control building, administration building, and maintenance building, or a final 

design that relocates the occupied buildings or storage tank, so that the radiation 

from a storage tank roof top fire would be less than 10,000 Btu/ft2

-hr at occupied 

buildings.

b. an evaluation that justifies the location of equipment that is critical to the safe 

shutdown and operation of emergency equipment, including the power 

distribution building transformers and emergency generator, or a final design 

that relocates the equipment or storage tank, so that the radiation from a storage 

tank roof top fire would be less than 10,000 Btu/ft2-hr at the these locations.

c. an evaluation that justifies the location of the vaporizers, high pressure pumps, 

and associated equipment, or a final design that relocates the equipment or 

impoundment, so that the radiation from a fire in the vaporizer spill 

impoundment would be less than 3,000 Btu/ft2-hr at the vaporizer and high 

pressure pump equipment.

After the 2009 draft EIS was issued, we received comments on the suitability of LNGFIRE3 in 

light of research conducted by Sandia National Laboratories (Sandia). In 2007, the DOE 

contracted Sandia to develop information for assessing the potential impacts associated with 

large LNG spills on water. The results of this study were released by DOE in the report 

“Liquefied Natural Gas Safety Research Report to Congress,” dated May 2012. Using data 

gathered from these tests and earlier methane gas burner tests, Sandia developed 

recommendations on parameters, including mass burning rate, pool fire flame height, surface 

emissive power, and atmospheric transmissivity, appropriate for use in solid flame models for 

pool fires over water. We examined the effect of altering the LNGFIRE3 model to incorporate 

Sandia’s recommendations regarding LNG pool fire modeling over water and on data provided 

by the largest LNG pool fire tests on land (Gaz de France Montoir tests) or water (Phoenix 

tests).38 Our conclusions were that LNGFIRE3, as currently prescribed by 49 CFR 193, is 

 38 “Recommended Parameters for Solid Flame Models for Land Based Liquefied Natural Gas Spills,” Issued 

January 23, 2013 in Docket AD13-4-000 (eLibrary Accession Number: 20130123-4002).
4-337 4.12 – Reliability and Safety

appropriate for modeling thermal radiation from LNG pool fires on land and is suitable for use in 

siting on-shore LNG facilities. 

We also received comments that LNGFIRE3 has not been verified or validated for use for tank 

top fires and therefore is not fit for purpose to use for siting Downeast. LNGFIRE3 has been 

verified and validated for relevant LNG pool fires, including the largest pool fires on land 

conducted to date. LNGFIRE3 is a semi-empirical model that is based on an assumed cylindrical 

fire shape and constant surface emissive power that utilizes a correlation for flame height based 

on flame diameter and burning characteristics. This is a common and well proven methodology. 

LNGFIRE3 also takes into account flame tilt and drag from wind effects. The correlations are 

based on LNG pool fire data up to 35 meters in diameter, which is typically in the range of plant 

impoundments, and is the largest published LNG pool fire test conducted on land. The largest 

published pool fire that would be within the range of a tank top fire is an 80-meter-diameter jet 

fuel fire conducted by Japan. However, this data is not pertinent or appropriate to use as jet fuel 

has very different burning characteristics, such as smoke generation. The recent Sandia large 

LNG pool fire tests are in the same range size and, while the results are not directly comparable 

for evaluating LNG pool fire models on land, the results show important trends in LNG pool 

fires. Although there have not been any LNG tank top fire tests to validate any LNG pool fire 

model, there has been an abundance of LNG and other test data that generally indicate that the 

semi-empirical relationships are conservative and provide confidence in the LNGFIRE3 results. 

Commentors also suggested that more advanced CFD models may be more appropriate to 

evaluate tank top fires and knock on effects. While CFD models would be able to account for 

additional physical phenomenom, including obstructions that can absorb the radiant heat emitted 

by the fire, these models also contain assumptions that can limit their applicability and would 

require an evaluation before they could be claimed to be more accurate or appropriate to use than 

LNGFIRE3. In addition, the use of more advanced models may not necessarily be more 

conservative, especially as distances from the fire are increased.

Such models are also generally more dependent on user input and may be manipulated to provide 

a desired outcome. As discussed in a recent paper, the publically available Fire Dynamic 

Simulator (FDS), developed by that National Institute of Standards and Technology (NIST) is 

limited in its ability to model smoke generation and relies on semi-empirical relationships and 

user-specified input to its sub-model to determine the amount of smoke generated. This allows 

for the user to manipulate the soot production in the results, which can greatly affect the radiant 

heat levels predicted. Moreover, FDS, including the soot production levels and other variables, 

has not yet been subjected to an evaluation, including scientific assessment, verification or 

validation, for any LNG pool fire scenarios. As a result, we would have less confidence in it 

than in the LNGFIRE3 results at this point. 

Commentors also questioned the effect of higher wind speeds on flame tilt and flame drag at 

higher elevations. As part of our evaluation of LNGFIRE3, we examined the effect of higher 

wind speeds for fires at higher elevations (e.g. storage tank roof top fires). Accounting for these 

effects would result in a less than 3 percent increase to the 1,600 Btu/ft2-hr zone, which is well 

within the uncertainty of the model predictions and is not significant enough to invalidate the 

thermal radiation modeling results.
4.12 – Reliability and Safety 4-338

Commentors raised further concerns on the structural integrity of storage tanks during a storage 

tank fire. Assuming the storage tank outer containment progressively failed as the fire burned 

(similar to fires in metal storage tanks), there would be a less than 2 percent increase to the 

1,600 Btu/ft2-hr zone, which is well within the uncertainty of the model predictions and is not 

significant enough to invalidate the thermal radiation modeling results.

We also received comments that there does not exist a definite and absolute value of safe 

exposure. Although there are differences many regulatory and standards bodies, the majority of 

regulations and codes, including those by DOT, EPA, and Canadian Standards Association 

(CSA), specify 1,600 Btu/ft2-hr (5 kW/m2) as a safe limit. Other international regulations also 

use values at or near 5 kW/m2 as a safe limit. The use of 1,600 Btu/ft2-hr (5 kW/m2) was reaffirmed for use at U.S. regulated facilities by the DOT in 2010. 39

4.12.6 Facility Security

Title 49, CFR, Part 193, Subpart J – Security, specifies security requirements for the onshore 

component of LNG facilities. This subpart includes requirements for conducting security 

inspections and patrols, liaison with local law enforcement officials, design and construction of 

protective enclosures, lighting, monitoring, alternative power sources, and warning signs. 

Security at the facility would be provided by both active and passive systems. The entire site 

would be surrounded by a protective enclosure (i.e., a fence) with sufficient strength to deter 

unauthorized access. The enclosure would be illuminated with not less than 2.2 lux between 

sunset and sunrise. Intrusion detection systems and day/night camera coverage would identify 

unauthorized access. A separate security staff would conduct periodic patrols of the plant, and 

screen visitors and contractors. The security staff may also assist in maintaining security of the 

marine terminal during cargo unloading.

In addition to the requirements of Part 193, there are also requirements for maintaining security 

of a marine terminal contained in Coast Guard regulations. Title 33, CFR, Part 105, as 

authorized by the Maritime Transportation Security Act (MTSA) of 2002, requires all terminal 

owners and operators to submit a Facility Security Assessment and a Facility Security Plan to the 

Coast Guard for review and approval. Some of the responsibilities of the applicant include, but 

are not limited to:

• designating a Facility Security Officer with a general knowledge of current security 

threats and patterns, risk assessment methodology, and the responsibility for 

implementing the Facility Security Assessment and Facility Security Plan and performing 

an annual audit for the life of the project;

• conducting a Facility Security Assessment to identify site vulnerabilities, possible 

security threats and consequences of an attack, and facility protective measures;

• developing a Facility Security Plan based on the Facility Security Assessment, with 

procedures for: responding to transportation security incidents; notification and 

coordination with local, state, and federal authorities; prevention of unauthorized access; 

 39 PHMSA Interpretation “Re: Request for Written Interpretation on the Applicability of 49 CFR 193 to Proposed 

Waterfront Liquefied Natural Gas Plant in the City of Fall River, Massachusetts” (July 7, 2010).
4-339 4.12 – Reliability and Safety

measures and equipment to prevent or deter dangerous substances and devices; training; 

and evacuation;

• implementing scalable security measures to provide increasing levels of security at 

increasing maritime security levels for facility access control, restricted areas, cargo 

handling, vessel stores and bunkers, and monitoring;

• ensuring the Transportation Worker Identification Credential program is properly 

implemented; and

• reporting all breaches of security and security incidents to the National Response Center.

If this project is constructed, 33 CFR 105 would require Downeast to submit a Facility Security 

Plan to the Coast Guard for review and approval before commencement of operations.

The LNG carriers which would deliver LNG to the proposed facility would also need to comply 

with various U.S. and international security requirements. The International Maritime 

Organization (IMO) adopted the International Ship and Port Facility Security Code (ISPS Code)

in 2003. The ISPS Code requires both ships and ports to conduct vulnerability assessments and 

to develop security plans. The purpose of the code is to prevent and suppress terrorism against 

ships; improve security aboard ships and ashore; and reduce the risk to passengers, crew, and 

port personnel on board ships and in port areas. All LNG vessels, as well as other cargo vessels 

500 gross tons and larger, and ports servicing those regulated vessels, must adhere to the IMO 

standards. Some of the IMO requirements for ships are as follows:

• ships must develop security plans and have a Vessel Security Officer;

• ships must have a ship security alert system. These alarms transmit ship-to-shore security 

alerts identifying the ship, its location, and indication that the security of the ship is under 

threat or has been compromised;

• ships must have a comprehensive security plan for international port facilities, focusing 

on areas having direct contact with ships; and

• ships may have equipment onboard to help maintain or enhance the physical security of 

the ship.

In 2002, the MTSA was enacted by the U.S. Congress and aligned domestic regulations with the 

maritime security standards of the ISPS Code and the International Convention for the Safety of 

Life at Sea (SOLAS). The resulting Coast Guard regulations, contained in 33 CFR 104, require 

vessels to conduct vulnerability assessments and develop corresponding security plans. All LNG 

carriers servicing the facility would have to comply with the MTSA requirements and associated 

regulations while in U.S. waters.

4.12.7 LNG Carriers

Since 1959, ships have transported LNG without a major release of cargo or a major accident 

involving an LNG vessel. There are more than 370 LNG carriers in operation routinely 

transporting LNG between more than 100 import/export terminals currently in operation 

worldwide. Since U.S. LNG terminals first began operating under FERC jurisdiction in the 

1970s, there have been more than 2,600 individual LNG ship arrivals at terminals in the U.S. 
4.12 – Reliability and Safety 4-340

For the past 40 years, LNG shipping operations have been safely conducted in U.S. ports and 

waterways.

4.12.7.1 Design and Operating Requirements

The LNG carriers used to import and export LNG to and from the United States would be 

constructed and operated in accordance with the IMO’s Code for the Construction and 

Equipment of Ships Carrying Liquefied Gases in Bulk, the SOLAS, and 46 CFR 154, which 

contains the United States safety standards for vessels carrying liquefied natural gas in bulk. 

As required by the IMO’s conventions and design standards, hold spaces and insulation areas on 

an LNG carrier must be equipped with gas detection and low temperature alarms. These devices 

monitor for leaks of LNG into the insulation between primary and secondary LNG cargo tank 

barriers. In addition, hazard detection systems must also be provided to monitor the hull 

structure adjacent to the cargo tank, compressor rooms, motor rooms, cargo control rooms, 

enclosed spaces in the cargo area, specific ventilation hoods and gas ducts, and air locks.

In 1993, amendments to the IMO’s Code for the Construction and Equipment of Ships Carrying 

Dangerous Chemicals in Bulk required all vessels to have monitoring equipment with an alarm 

facility which is activated by detection of over-pressure or under-pressure conditions within a 

cargo tank. In addition, cargo tanks must be heavily instrumented, with gas detection equipment 

in the hold and inter-barrier spaces, temperature sensors, and pressure gauges. LNG carriers are

to be equipped with a firewater system with the ability to supply at least two jets of water to any 

part of the deck in the cargo area and parts of the cargo containment and tank covers above-deck. 

A water spray system is also available for cooling, fire prevention, and crew protection in 

specific areas. In addition, certain areas of LNG carriers are fitted with dry chemical powdertype extinguishing systems and carbon dioxide smothering systems for fighting fires. Fire 

protection must include the following systems:

• a water spray (deluge) system that covers the accommodation house control room and all 

main cargo valves;

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

stations found throughout the vessel;

• a dry chemical fire extinguishing system for hydrocarbon fires; and

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

emergency generators, and compressors.

All LNG vessels entering U.S. waters are required to possess a valid IMO Certificate of Fitness 

and either a Coast Guard Certificate of Inspection (for U.S. flag vessels) or a Coast Guard 

Certificate of Compliance (for foreign flag vessels). These documents certify that the vessel is 

designed and operating in accordance with both international standards and the U.S. regulations 

for bulk LNG carriers under Title 46, CFR, Part 154. Vessels navigating Canadian waters would 

have to comply with the requirements set out by the Transport Canada with respect to 

certification, safety inspections and other regulations (SENES, 2007).
4-341 4.12 – Reliability and Safety

4.12.7.2 Hazards Resulting from Accidents

A review of the history of LNG maritime transportation indicates that there has not been a 

serious accident at sea or in a port which resulted in a spill due to rupturing of the cargo tanks. 

However, insurance records, industry sources, and public websites identify a number of incidents 

involving LNG vessels, including minor collisions with other vessels of all sizes, groundings, 

minor LNG releases during cargo unloading operations, and mechanical/equipment failures 

typical of large vessels. Some of the more significant occurrences, representing the range of 

incidents experienced by the worldwide LNG vessel fleet, are described below:

• El Paso Paul Kayser grounded on a rock in June 1979 in the Straits of Gibraltar during a 

loaded voyage from Algeria to the United States. Extensive bottom damage to the ballast 

tanks resulted; however, no cargo was released because no damage was done to the cargo 

tanks. The entire cargo of LNG was subsequently transferred to another LNG vessel and 

delivered to its U.S. destination.

• Tellier was blown by severe winds from its docking berth at Skikda, Algeria in 

February 1989 causing damage to the loading arms and the vessel and shore piping. The 

cargo loading had been secured just before the wind struck, but the loading arms had not 

been drained. Consequently, the LNG remaining in the loading arms spilled onto the 

deck, causing fracture of some plating.

• Mostefa Ben Boulaid had an electrical fire in the engine control room during unloading 

at Everett, Massachusetts. The ship crew extinguished the fire and the ship completed 

unloading. 

• Khannur had a cargo tank overfill into the vessel’s vapor handling system on 

September 10, 2001, during unloading at Everett, Massachusetts. Approximately 

100 gallons of LNG were vented and sprayed onto the protective decking over the cargo 

tank dome, resulting in several cracks. After inspection by the Coast Guard, the Khannur 

was allowed to discharge its LNG cargo.

• Mostefa Ben Boulaid had LNG spill onto its deck during loading operations in Algeria 

in 2002. The spill, which is believed to have been caused by overflow rather than a 

mechanical failure, caused significant brittle fracturing of the steelwork. The vessel was 

required to discharge its cargo, after which it proceeded to dock for repair.

• Norman Lady was struck by the USS Oklahoma City nuclear submarine while the 

submarine was rising to periscope depth near the Strait of Gibraltar in November 2002. 

The 87,000 cubic meter (m3

) LNG vessel, which had just unloaded its cargo at Barcelona, 

Spain, sustained only minor damage to the outer layer of its double hull but no damage to 

its cargo tanks.

• Tenaga Lima grounded on rocks while proceeding to open sea east of Mopko, South 

Korea due to strong current in November 2004. The shell plating was torn open and 

fractured over an approximate area of 20 by 80 feet, and internal breaches allowed water 

to enter the insulation space between the primary and secondary membranes. The vessel

was refloated, repaired, and returned to service.

• Golar Freeze moved away from its docking berth during unloading on March 14, 2006,

in Savannah, Georgia. The powered emergency release couplings on the unloading arms 

activated as designed, and transfer operations were shut down.
4.12 – Reliability and Safety 4-342

• Catalunya Spirit lost propulsion and became adrift 35 miles east of Chatham, 

Massachusetts on February 11, 2008. Four tugs towed the vessel to a safe anchorage for 

repairs. The Catalunya Spirit was repaired and taken to port to discharge its cargo.

• Al Gharrafa collided with a container ship, Hanjin Italy, in the Malacca Strait off 

Singapore on December 19, 2013. The bow of the Al Gharrafa and the middle of the 

starboard side of the Hanjin were damaged. Both ships were safely anchored after the 

incident. No loss of LNG, fatalities, or injuries were reported.

Although the history of LNG shipping has been free of major incidents, and no incidents have 

resulted in significant quantities of cargo being released, the possibility of an LNG spill from a 

vessel over the duration of the proposed project must be considered. If an LNG spill were to 

occur, the primary hazard to the public would be from radiant heat from a pool fire. If an LNG 

release were to occur without ignition, an ignitable gas cloud could form and also present a 

hazard. Historically, the events most likely to cause a significant release of LNG were a vessel 

casualty such as: 

• a grounding sufficiently severe to puncture an LNG cargo tank;

• a vessel colliding with an LNG vessel in transit;

• an LNG vessel alliding40 with the terminal or a structure in the waterway; or

• a vessel alliding with an LNG vessel while moored at the terminal.

To result in a spill of LNG, any of the above events would need to occur with sufficient impact 

to breach an LNG vessel’s double hull and cargo tanks. All LNG vessels used to deliver LNG to 

the proposed project would have double-hull construction, with the inner and outer hulls 

separated by about 10 feet. Furthermore, the cargo tanks are normally separated from the inner 

hull by a layer of insulation approximately 1-foot thick.

As a result, many grounding incidents severe enough to cause a cargo spill on a single-bottom oil 

tanker would be unable to penetrate both inner and outer hulls of an LNG vessel. An earlier 

Federal Power Commission (predecessor to the FERC) study estimated that the double bottom of 

an LNG vessel would be sufficient to prevent cargo tank penetration in about 85 percent of the 

cases that penetrated a single-bottom oil tanker. Previous incidents with LNG vessels have 

primarily involved grounding, and none of these have resulted in the breach of the double hull 

and subsequent release of LNG cargo. The likelihood of an LNG vessel sustaining cargo tank 

damage in a collision would depend on several factors: 

• the displacement and construction of both the struck and striking vessels;

• the velocity of the striking vessel and its angle of impact with the struck vessel; and 

• the location of the point of impact.

The Federal Power Commission study estimated that the additional protection afforded by the 

double hull would be effective in low-energy collisions; overall, it would prevent cargo tank 

penetration in about 25 percent of the cases that penetrated a single-hull oil tanker.

 40 “Allision” is the action of dashing against or striking upon a stationary object (for example, the running of one 

ship upon another ship that is docked) – distinguished from “collision,” which is used to refer to two moving ships 

striking one another.
4-343 4.12 – Reliability and Safety

In 1995, to assist the Coast Guard in San Juan, Puerto Rico, EcoEléctrica L.P. prepared an 

analysis of the damage that could result from an oil tanker striking an LNG vessel at berth 

(FERC, 1996). The analysis assumed a 125,000 m3 LNG vessel and an 82,000-dead-weight-ton 

tanker carrying number 6 fuel oil without tug assistance. The analysis determined the minimum 

striking speed to penetrate the cargo tanks of an LNG vessel for a range of potential collision 

angles. Table 4.12.7.2-1 presents the resulting minimum striking speeds for the two principal 

cargo systems.

TABLE 4.12.7.2-1

Minimum Striking Speed to Penetrate LNG Cargo Tanks

Angle of Impact

Minimum Striking Speed (knots)

Spherical Tanks Membrane Tanks

Greater than 60 degrees 4.5 3.0

45 degrees 6.3 4.0

30 degrees 9.0 6.0

15 degrees 18.0 12.0

For membrane tanks, the critical beam-on striking speed was 3.0 knots; for spherical tanks, the 

critical on-beam speed was 4.5 knots. For both containment types, lower angles of impact result 

in much greater minimum striking speeds to penetrate LNG cargo tanks. In the July/August 

2002 issue of LNG Journal, the General Manager of the Society of International Gas Tanker and 

Terminal Operators provided a table that indicated the critical speed necessary for a 20,000-ton 

vessel to puncture the outer hull of an LNG vessel was 7.3 knots. For a 93,000-ton vessel, the 

impact speed was 3.2 knots. In neither case does such an impact result in damage to the LNG 

cargo containment system, nor does it result in a release of LNG.

A more recent significant work in analyzing the potential for an LNG vessel breach was released 

by the DOE in December 2004. Sandia conducted the research and wrote the report entitled, 

Guidance on Risk Analysis and Safety Implications of a Large Liquefied Natural Gas (LNG) 

Spill Over Water (2004 Sandia Report). The 2004 Sandia Report included an LNG cargo tank 

breach analysis using modern finite element modeling and explosive shock physics modeling to 

estimate a range of breach sizes for both credible accidental and intentional LNG spill events. 

Accidental breaching evaluations were based on finite element modeling of collisions of doublehulled oil tankers similar in size and design to LNG ships. The analysis of accidental events 

found that groundings, collisions with small vessels, and low-speed (less than 7 knots) collisions 

with large vessels striking at 90 degrees could cause minor vessel damage but would not result in 

a cargo spill. This is due to the protection provided by the double-hull structure, the insulation 

layer, and the primary cargo tank of an LNG vessel. High-speed (12 knots) collisions with large 

vessels striking at 90 degrees were found to potentially cause cargo tank breach areas of from 0.5 

to 1.5 meters squared (m2

).

The possibility of a LNG release due to an accident, such as a collision or grounding, is 

considered minimal. In addition, current operational procedures in use by the Coast Guard, such 

as managing ship traffic, coordinating ship speeds, and active ship control in inner and outer 

harbors, would also further reduce the potential of LNG spill from accidental causes.
4.12 – Reliability and Safety 4-344

4.12.7.3 Hazards Resulting from Intentional Acts

The 2004 Sandia Report also analyzed credible intentional breaches on LNG carriers up to 

145,000 m3 in capacity using modern finite element modeling and explosive shock physics 

modeling. The events considered for credible intentional acts were based on intelligence and 

historical data, and ranged from sabotage and hijacking to other types of physical attacks. 

Physical attacks included those documented to have occurred to several types of international 

shipping vessels, including attacks with small missiles and rockets, and attacks with bulk 

explosives.

For intentional scenarios, the size of the cargo tank hole depends on the location of the ship and 

source of threat. Intentional breach areas were estimated to range from 2 to 12 m2. In most 

cases, an intentional breaching scenario would not result in a nominal hole area of more than 5 to 

7 m2, which is a more appropriate range to use in calculating potential hazards from spills. These 

hole sizes are equivalent to circular hole diameters of 2.5 and 3 meters.

The 2004 Sandia Report also evaluated cascading damage due to brittle fracture from exposure 

to cryogenic liquid or fire-induced damage to foam insulation. While possible under certain 

conditions, the cascading damage was found to not likely involve more than two or three cargo 

tanks. Cascading events were expected to increase the fire duration but not to significantly 

increase the overall fire hazard.

The 2004 Sandia Report also included guidance on risk management for intentional spills, based 

on the findings that the most significant impacts to public safety and property exist within 

approximately 500 meters (1,640 feet) of a spill due to thermal hazards from a fire, with lower 

public health and safety impacts beyond 1,600 meters (approximately 1 mile). Large un-ignited 

LNG vapor releases were found to be unlikely, but could extend from nominally 2,500 meters 

(8,200 feet) to a conservative maximum distance of 3,500 meters (2.2 miles) for an intentional 

spill.

In 2008, the DOE released another study prepared by Sandia, entitled Breach and Safety Analysis 

of Spills Over Water from Large Liquefied Natural Gas Carriers, May 2008 (2008 Sandia 

Report). The 2008 Sandia Report assessed the scale of possible hazards for newer LNG vessels

with capacities up to 265,000 m3. Using the same methodology as the 2004 Sandia Report, the 

2008 Sandia Report concluded thermal hazard distances would be 7 - 8 percent greater than 

those from vessels carrying 145,000 m3 of LNG, due primarily to the slightly greater height of 

LNG above the waterline. The 2008 Sandia Report also noted the general design of the larger 

vessels was similar to the previously analyzed ship designs and, for near-shore facilities, the 

calculated breach size for intentional scenarios would remain the same. Overall, the 2008 Sandia 

Report maintained the same impact zones as with the smaller vessels that were analyzed in the 

2004 Sandia Report.

In February 2007, the U.S. Government Accountability Office (GAO) published a report 

assessing several studies, including the 2004 Sandia Report, that had been conducted on the 

consequences of an LNG spill resulting from a terrorist attack on an LNG vessel (GAO, 2007). 

The GAO’s panel of experts agreed that the most likely public safety impact of an LNG spill 

would be the radiant heat from a pool fire and suggested that further study was needed to 

eliminate uncertainties in the assumptions used in modeling large LNG spills on water. After the 
4-345 4.12 – Reliability and Safety

GAO report, Congress requested the DOE to further address these research needs. DOE 

contracted Sandia to conduct a series of large-scale LNG fire and cryogenic damage tests to 

investigate the larger classes of LNG carriers with capacities up to 260,000 m3

, representative of 

the largest LNG vessels in operation. Sandia conducted the largest LNG pool fire tests done to 

date and performed advanced computational modeling and ship simulations between 2008 

and 2011.

As in the earlier studies, Sandia worked with marine safety, law enforcement, and intelligence 

agencies to assess threats and credible intentional acts. Scenarios included attacks with shoulderfired weapons, explosives, and attacks by aircraft and other boats. Sandia identified several 

ranges of possible hull breaches ranging from 0.005 m2 (Very Small) to 15 m2 (Very Large). 

Based on the collected pool fire test data and the ship simulations, Sandia concluded that thermal 

hazard distances to the public from a large LNG pool fire was smaller, by at least 2 to 7 percent, 

than the results listed in the 2004 and 2008 Sandia Reports.

In order to more robustly analyze the potential for cascading failure of LNG carrier cargo tanks, 

Sandia use detailed vessel structural and thermal damage models to simulate the effects to a 

LNG carrier from a spill. For the large breaches considered, Sandia predicts that as much as 40 

percent of the LNG released from the cargo tank would remain within the ship’s structure. Due 

to both the cold temperature of the LNG and the heat from a pool fire, the LNG carrier’s 

structural steel would be degraded. The effects could be significant enough to cause the ship to 

be disabled, severely damaged, and at risk of sinking.

Although LNG ship design and construction practices render simultaneous, multiple tank failures 

as extremely unlikely, Sandia concluded that sequential multi-tank spills may be possible. If 

sequential failures were to occur, they would not increase the size of the area impacted by the 

pool fire but could increase the duration of the fire hazards. Based on this research, Sandia 

concluded that use of a nominal one-tank spill, with a maximum of a three-tank spill, as was 

recommended in the 2004 Sandia report, is still appropriate for estimating hazard distances.

4.12.7.4 Regulatory Requirements for LNG Carrier Operations

The Coast Guard exercises regulatory authority over LNG facilities that affect the safety and 

security of port areas and navigable waterways under Executive Order 10173; the Magnuson Act 

(50 United States Code [USC] Section 191); the Ports and Waterways Safety Act of 1972, as 

amended (33 USC Section 1221, et seq.); and the MTSA of 2002 (46 USC Section 701). The 

Coast Guard is responsible for matters related to navigation safety, carrier engineering and safety 

standards, and all matters pertaining to the safety of facilities or equipment located in or adjacent 

to navigable waters up to the last valve immediately before the receiving tanks. The Coast 

Guard also has authority for LNG facility security plan review, approval, and compliance 

verification as provided in Title 33, CFR, Part 105.

The Coast Guard regulations in 33 CFR 127 apply to the marine transfer area of waterfront 

facilities between the LNG vessel and the first manifold or valve located inside the containment. 

Title 33 CFR 127 regulates the design, construction, equipment, operations, inspections, 

maintenance, testing, personnel training, firefighting, and security of LNG waterfront facilities. 

The safety systems, including communications, emergency shutdown, gas detection, and fire 

protection, must comply with the regulations in 33 CFR 127. Under § 127.019, Downeast would 
4.12 – Reliability and Safety 4-346

be required to submit two copies of its Operations and Emergency Manuals to the Coast Guard 

Sector Northern New England at least 30 days prior to the first LNG transfer.

Both the Coast Guard regulations under 33 CFR 127 and FERC regulations under 18 CFR 

157.21, require an applicant who intends to build an LNG import facility to submit a Letter of 

Intent (LOI) to the Coast Guard at the same time the pre-filing process is initiated with the 

Commission. Consequently, Downeast initially notified the Coast Guard that it proposed to 

construct an LNG import terminal in Washington County, Maine and submitted an LOI to the 

Captain of the Port (COTP), Sector Northern New England, on December 20, 2005, with LOI 

amendments submitted on January 6 and February 8, 2006.41

As required by its regulations (33 CFR 127.009), the Coast Guard is responsible for issuing a 

LOR to the FERC regarding the suitability of the waterway for LNG marine traffic with respect 

to the following items:

• physical location and description of the facility;

• the LNG vessel’s characteristics and the frequency of LNG shipments to or from the 

facility;

• waterway channels and commercial, industrial, environmentally sensitive, and residential 

areas in and adjacent to the waterway used by LNG vessels en route to the facility, within 

25 kilometers (15.5 miles) of the facility;

• density and character of marine traffic in the waterway;

• locks, bridges, or other manmade obstructions in the waterway;

• depth of water;

• tidal range;

• protection from high seas;

• natural hazards, including reefs, rocks, and sandbars;

• underwater pipes and cables; and

• distance of berthed vessels from the channel and the width of the channel.

In addition to the LOI, 33 CFR 127 and FERC regulations require each LNG project applicant to 

submit a Waterway Suitability Assessment (WSA) to the cognizant COTP no later than the start 

of the FERC pre-filing process. Until a facility begins operation, applicants must annually 

review their WSAs and submit a report to the COTP as to whether changes are required. As 

indicated in 33 CFR Part 127.007(h), the deadline for these reports should coincide with the 

LOR anniversary date. Downeast must ensure that all submissions of the annual review coincide

with the actual date of the initial LOR, which was issued on January 6, 2009. Therefore, the due 

date of the next annual review will be January 6, 2015. The WSA must include the following 

information: 

• port characterization;

• risk assessment for maritime safety and security; 

 41 FERC regulations requiring the LOI during the pre-filing process were issued in 2005 (70 FR 60440, Oct. 18, 

2005) before Downeast initiated the pre-filing process. In 2010, the Coast Guard revised 33 CFR 127 to require 

submittal of the LOI during the FERC pre-filing period (75 FR 29426, May 26, 2010).
4-347 4.12 – Reliability and Safety

• risk management strategies; and 

• resource needs for maritime safety, security, and response. 

On June 14, 2005, the Coast Guard published a Navigation and Vessel Inspection Circular –

Guidance on Assessing the Suitability of a Waterway for Liquefied Natural Gas (LNG) Marine 

Traffic (NVIC 05-05). The purpose of NVIC 05-05 was to provide the Coast Guard 

COTPs/Federal Maritime Security Coordinators, members of the LNG industry, and port 

stakeholders with guidance on assessing the suitability of a waterway for LNG marine traffic. 

Since 2005, the Coast Guard updated this guidance twice, publishing NVIC 05-08 and NVIC 01-

11. The current guidance from the Coast Guard is contained in NVIC 01-11.

As described in 33 CFR 127 and in NVIC 01-11, the applicant develops the WSA in two phases. 

The first phase is the submittal of the Preliminary WSA, which begins the Coast Guard’s review 

process to determine the suitability of the waterway for LNG marine traffic. The second phase is 

the submittal of the Follow-On WSA. This document is reviewed and validated by the Coast 

Guard and forms the basis for the agency’s LOR to the FERC.

The Preliminary WSA provides an outline which characterizes the port community and the 

proposed facility and transit routes. It provides an overview of the expected major impacts LNG 

operations may have on the port, but does not contain detailed studies or conclusions. This 

document is used to start the Coast Guard’s scoping process for evaluating the suitability of the 

waterway for LNG marine traffic. 

The Follow-On WSA must provide a detailed and accurate characterization of the LNG facility, 

the LNG tanker route, and the port area. The assessment should identify appropriate risk 

mitigation measures for credible security threats and safety hazards. The Follow-on WSA 

provides a complete analysis of the topics outlined in the Preliminary WSA. It should identify 

credible security threats and navigational safety hazards for the LNG marine traffic, along with 

appropriate risk management measures and the resources (federal, state, local, and private sector) 

needed to carry out those measures.

All three NVICs direct the use of the 2004 Sandia Report as the best available information on 

LNG spills. NVIC 05-08 and NVIC 01-11 also include use of the 2008 Sandia Report. Three 

concentric Zones of Concern, based on LNG carriers with a cargo carrying capacity up to 

265,000 m3, are used to assess the maritime safety and security risks of LNG marine traffic. The 

Zones of Concern are:

• Zone 1 – impacts on structures and organisms are expected to be significant within 

500 meters (1,640 feet). The outer perimeter of Zone 1 is approximately the distance to 

thermal hazards of 37.5 kiloWatts per square meter (kW/m2) (12,000 Btu/ft2-hr) from a 

pool fire.

• Zone 2 – impacts would be significant but reduced, and damage from radiant heat levels 

are expected to transition from severe to minimal between 500 and 1,600 meters 

(1,640 and 5,250 feet). The outer perimeter of Zone 2 is approximately the distance to 

thermal hazards of 5 kW/m2 (1,600 Btu/ft2

-hr) from a pool fire.

• Zone 3 – impacts on people and property from a pool fire or an un-ignited LNG spill are 

expected to be minimal between 1,600 meters (5,250 feet) and a conservative maximum 
4.12 – Reliability and Safety 4-348

distance of 3,500 meters (11,500 feet, or 2.2 miles). The outer perimeter of Zone 3 

should be considered the vapor cloud dispersion distance to the LFL from a worst case 

un-ignited release. Impacts to people and property could be significant if the vapor cloud 

reaches an ignition source and burns back to the source.

Once the applicant submits a complete Follow-On WSA, the Coast Guard reviews the document 

to determine if it presents a realistic and credible analysis of the public safety and security 

implications from LNG marine traffic in the port. Finally, the Coast Guard issues a LOR. The 

Coast Guard may also prepare an LOR Analysis (LOR Analysis), which serves as a record of 

review of the LOR and contains detailed information along with the rationale used in assessing 

the suitability of the waterway for LNG marine traffic.42

4.12.7.5 Downeast’s Waterway Suitability Assessment

Downeast submitted a Preliminary WSA for the proposed project to the Coast Guard in 

December of 2005. In the development of the Follow-On WSA, consultations occurred with the 

Coast Guard, the Area Maritime Security Committee, and other port stakeholders. As part of its 

assessment of the safety and security aspects of this project, the COTP Sector Northern New 

England convened safety and security working groups under the umbrella of the Passamaquoddy 

Bay/Down East Sub-Committee of the Area Maritime Security Committee (LNG Working 

Group) and Maine and New Hampshire Port Safety Forum, and participated in ad hoc meetings 

with the regional U.S. and Canadian response and law enforcement communities. The LNG 

Working Group, as a whole, convened initially in Ellsworth, Maine, in March of 2006, and 

subsequent meetings were held in Ellsworth and Eastport, Maine, in April and December 2006, 

respectively. The consultation process included subsequent collaboration with members 

throughout the WSA review and validation process.

In addition, a Ports and Waterways Safety Assessment (PAWSA) was conducted in October 

2006 to provide a baseline for analyses of navigational safety concerns for the Passamaquoddy

Bay port area. The PAWSA is a systematic assessment process designed to identify major 

waterway safety hazards, estimate risk levels, and evaluate potential measures to reduce risk. 

Participation in the PAWSA was through invitation and was designed to include a broad crosssection of waterway users, port stakeholders, and maritime professionals. Participants included 

representatives of the marine industry, pilots, tug operators, passenger/ferry operators, 

commercial fishing and aquaculture industry, environmental groups, state and local officials, 

local and regional law enforcement, and federal and provincial governments. Canadian 

government officials, members of the LNG industry, and concerned citizens’ groups were on 

hand to observe the process. 

Downeast submitted the Follow-On WSA to the Coast Guard on December 19, 2006. The 

Follow-On WSA used three concentric Zones of Concern based on LNG carriers with a cargo 

 42 At the time the Coast Guard conducted the waterway review, the guidance in NVIC 05-05 used the term WSR as 

the title for the LOR Analysis. In order to avoid confusion, the Coast Guard decided to continue referring to its final 

assessment for the Downeast LNG proposal as the WSR, although the WSR term was eliminated in NVIC 05-08 and 

NVIC 01-11.
4-349 4.12 – Reliability and Safety

carrying capacity up to 265,000 m3 to assess the maritime safety and security risks of LNG 

marine traffic in Passamaquoddy Bay.

43

Carrier Routes

Imported LNG could be obtained from exporting terminals throughout the world and delivered 

by LNG vessels to the proposed terminal. There are 19 countries which provide LNG for export: 

Algeria; Angola; Australia; Brunei; Egypt; Equatorial Guinea; Indonesia; Libya; Malaysia; 

Nigeria; Norway; Oman; Peru; Qatar; Russia; Trinidad & Tobago; United Arab Emirates, United 

States, and Yemen with another 5 countries planned or under construction: Canada, Columbia, 

Iran, Papua New Guinea, and Venezuela. Downeast has not identified specific source(s) for 

LNG supplies for the proposed project.

An LNG carrier’s transit from sea to the Downeast LNG terminal would follow a circuitous 

route through Canadian waters.

44 This is virtually the same route as currently used by all deepdraft vessels servicing the Passamaquoddy Bay port area. Deep-draft vessels bound for the ports 

of Bayside, New Brunswick, or Eastport, Maine, either enter the area via the Gulf of Maine and 

into Grand Manan Channel, or by transiting Grand Manan Basin into the Bay of Fundy. Both 

routes converge offshore in the general vicinity of the entrance to Head Harbour Passage, north 

of Campobello Island. 

The LNG carrier would continue on its northeasterly course into Canadian waters, roughly 

paralleling the east and northeast coasts of Campobello Island, New Brunswick, to the entrance 

of Head Harbour Passage. At this point, the LNG carrier would enter Head Harbour Passage. 

Here it would pass Campobello Island along the island’s north shore, then Friar Roads south of 

Indian Island and Cherry Isle. The carrier would enter U.S. waters as it neared Eastport, Maine. 

It would pass along Eastport’s eastern shore, through Western Passage, pass Quoddy Village in 

Eastport, Maine, to the west, and pass Deer Island, New Brunswick to the east. The ship’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 intended 

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

carrier 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.

All deep-draft vessel traffic entering the Passamaquoddy Bay port area initially navigate 

Canadian waters, and then straddle the international boundary throughout their respective 

transits. The existing scheme for ensuring traffic control involves the full cooperation of the 

United States and Canada. Previously, deep-draft vessel movements were reported to and 

controlled by “Fundy Traffic,” a Canadian marine traffic and communications service center in 

St. John, New Brunswick. However, Fundy Traffic is no longer in operation and all vessel 

 43 Downeast LNG’s LOI and WSA were provided to the Coast Guard in 2005 prior to the issuance of the 2008 

Sandia Report. The Coast Guard’s Waterway Suitability Report 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 cargo capacity.”

44 The carrier transit described in this section is from the Coast Guard’s January 6, 2009 Waterway Suitability 

Report for the proposed Downeast LNG facility. The Waterway Suitability Report can be found in Appendix B of 

the 2009 draft EIS.
4.12 – Reliability and Safety 4-350

movement and communications are controlled remotely. Therefore, the Coast Guard 

recommends Downeast consult with Transport Canada to determine if this change will 

compromise the safety of deep draft vessel traffic entering the Passamaquoddy Bay port area and 

that these results be provided to Coast Guard Sector Northern New Englad for evaluation. The 

National Vessel Movement Center in the U.S. requires a 96-hour advance notice of arrival for 

those deep draft vessels calling on U.S. ports.

Both Transport Canada and the U.S. Coast Guard administer Port State Control procedures. If a 

U.S. Port State Control boarding is required prior to a vessel entering a U.S. port, the boarding 

would need to take place in U.S. waters, most likely at a point south of West Quoddy Head. 

Pilotage is compulsory for foreign vessels and U.S. vessels under registry in foreign trade when 

in U.S. waters. All deep draft ships currently entering the shared waterway via Head Harbour 

Passage and transiting Maine waters to Eastport must employ a U.S. pilot.

As noted earlier, a typical transit would take approximately two and one half to three and one 

half hours to traverse the over 16.6 nautical miles from Head Harbour Passage to the proposed 

terminal. Transit speeds for all LNG marine traffic would be approximately 5 to 10 knots 

depending on the weather, sea state, and vessel traffic in the area.

LNG carriers leaving the terminal would utilize the same transit routes as described above. A 

small amount of LNG following cargo unloading at the facility would be retained by the LNG 

carriers. This volume serves as the “heel” and is the minimum amount of LNG used to insulate 

the vessel’s LNG storage tanks and also serves as fuel for the vessel.

Hazard Zones Associated with the Proposed Route

As discussed in section 4.12.7.2 and 4.12.7.3, Sandia National Labs identified three different 

hazard zones based on accidental and intentional events. The Coast Guard NVIC 01-11 

references the three larger intentional “Zones of Concern” for assisting in a risk assessment of 

the waterway. As LNG carriers proceed along the intended track line, Zone 1, the potential area 

with the most severe impact, would not affect any high population area or public or government 

centers such as schools, hospitals or transportation infrastructure.

45 However, Zone 1 may 

overlap any commercial vessel intended for the Port of Bayside as the vessel passes the berthed 

LNG carriers. Similarly, recreational and fishing vessels may fall within Zone 1, depending on 

their course. The seasonal ferry crossings connecting Deer Island, New Brunswick and Eastport, 

Maine and Campobello Island, New Brunswick could fall within Zone 1 as an LNG carrier 

passes these ferry crossings. Transit of such vessels through a Zone 1 area of concern can be 

avoided by timing and course changes, if conditions permit.

During the LNG carrier’s transit, Zone 1 would encompass portions of Moose Island on the 

Maine side and Deer Island on the New Brunswick side. This area presents the narrowest point 

in the entire transit route and the pilots tend to hug the U.S. side of the dogleg, rather than stay in 

the middle of the channel, in order to avoid the divergent currents common to this portion of the 

waterway. Although no major military post or camp is situated along the waterway, Coast Guard 

 45 As discussed in section 4.12.7.2, the Coast Guard used criteria developed by Sandia to define the outer 

limits of the hazard zones for assessing potential risks associated with the proposal. The Coast Guard’s January 6, 

2009 Waterway Suitability Report (WSR) defines the areas along the transit route that fall within each zone.
4-351 4.12 – Reliability and Safety

Station Eastport, a Search and Rescue and Law Enforcement installation, is located on the shore 

of Eastport and would fall within Zone 1 and/or 2, depending on the actual course taken by the 

pilots when navigating the bend off Dog Island. When the carriers transit Head Harbour 

Passage, the northern most edge of Head Harbour and shore side neighboring areas on 

Campobello Island would fall within Zone 1, including portions of Wilson’s Beach. When the 

carriers transit Friar Roads and Western Passage, the western edge of Deer Island Point, New 

Brunswick, including Deer Island Campgrounds, would also fall into this zone.

Zone 2 areas, defined as those where the impact is significant but reduced, include most of 

Eastport, Kendall Head, and Pleasant Point, Maine, including residential, commercial (e.g. East 

Coast Ferries, Quoddy Tides Newspaper, restaurants, etc.), and institutional (e.g., Eastport 

Elementary School, Shead High School, Beatrice Rafferty School, Eastport Police Department, 

Peavey Memorial Library, U.S. Post Office) land uses. A portion of Route 190, the only vehicle 

access to and from the City of Eastport, is within Zone 2.

During LNG vessel transits of Head Harbour Passage, all Canadian areas and communities along 

the northern and westerly edges of Campobello Island such as Brown Head, Wilson’s Beach, 

Windmill Point, and Bald Head would fall within Zone 2. Also within this zone would be the 

islands off the coast of New Brunswick to include Spruce Island, Sandy Island, Casco Bay 

Island, Green Island, Pope Island and Indian Island. Zone 2 would also impact land masses 

along Friar Roads and Western Passage such as West Deer Island, New Brunswick communities 

west of Highway 772, Doctors Cove, Cummings Cove, and Mink Point. 

Zone 3 would include areas such as Leonardville, Bar Island, and a portion of Southern Deer 

Island. Welshpool and all of Northern Campobello Island would fall into Zone 3, as would the 

communities on the alternate side of Head Harbour Passage. When LNG vessels navigate Friar 

Roads and Western Passage, a major portion of western Deer Island would fall within this zone 

as well. Zone 3 would also include Eastport and Moose Island, Pleasant Point, Perry, 

Robbinston, and Saint Andrews, including residential (e.g., Passamaquoddy Pleasant Point 

Reservation), commercial (e.g., Eastport Municipal Airport, Federal Marine Terminals), 

institutional (e.g., Passamaquoddy Tribal Government, Eastport Chamber of Commerce, 

Robbinston Volunteer Fire Department, Border Historical Museum, Campobello Island 

Consolidated School, Christ Episcopal Church), and recreational (e.g., Shackford Head State 

Park, Clark Gregory Nature Preserve, Monument Square, Centennial Park, Algonquinn Golf

Course, Saint Andrew’s Blockhouse) land uses.

The areas impacted by the three different hazard zones are illustrated for both accidental and 

intentional events in figure 4.12.7-1. More detailed figures may be found in Appendix F.

4.12.7.6 Coast Guard Waterway Suitability Report

On January 6, 2009, the COTP, Sector Northern New England, issued an LOR and a Waterway 

Suitability Report (WSR) that summarized the Coast Guard’s recommended risk mitigation 

measures, as well as the port community’s capabilities.46 

 46 At the time the Coast Guard conducted the waterway review, the guidance in NVIC 05-05 used the term WSR as 

the title for the LOR Analysis. In order to avoid confusion, the Coast Guard decided to continue referring to its final 
4.12 – Reliability and Safety 4-352

Accidental Intentional

 Sandia Hazard Zone 1 (0-500m)

 Sandia Hazard Zone 2 (500-1,600m)

 Sandia Hazard Zone 3 (1,600-3,500m)

Figure 4.12.7-1 Hazard Zones Along LNG Carrier Route

Based on the results of the assessment of potential risks to navigation safety and maritime

security associated with the Downeast proposal47, the Coast Guard determined the waterway 

along the proposed carrier transit route would be suitable for the type and frequency of LNG 

marine traffic associated with this proposed project, provided that the risk mitigation measures

defined in the WSR are implemented. The hydrographic characteristics of the waterway are 

suitable to sustain deep draft vessel movement and the simulation tests and traffic studies 

confirm the transit and maneuvers are feasible for the design range of LNG carriers anticipated. 

These measures are further detailed in the WSR and include, among others, the following 

requirements:

• The development, by Downeast, of standard operating parameters approved by the Coast 

Guard and coordinated with the Government of Canada to enable the safe and secure 

movement of LNG tankers through Canadian and U.S. waters, taking into account the 

need for:

1) Number and performance capabilities of assist tugs and escort vessels as well as 

determining appropriate staging areas. The minimum specified number of 

escort/assist tugs must be employed at all times to escort LNG carriers throughout 

their transit and during berthing and unberthing. It should be noted that additional 

 

assessment for the Downeast LNG proposal as the WSR, although the WSR term was eliminated in NVIC 05-08 and 

NVIC 01-11. 47 We received comments from the House of Commons and Embassy of Canada opposed to the passage of LNG 

tankers through Head Harbour Passage, which is located within Canadian internal waters.
4-353 4.12 – Reliability and Safety

requirements for escort tugs may be identified during the emergency response 

planning process.

2) Identification and implementation of navigation safety upgrades and enhancements, 

as identified in Downeast’s WSA, to include but not limited to: radar, 

communications interoperability, data buoys, and critical Aids to Navigation.

3) Safe operating parameters and environmental constraints, to include but not limited 

to: visibility, wind, sea state, currents, and tides.

4) These parameters must include the following:

o Daylight Transits – Loaded or partially loaded LNG carriers may only transit the 

waterway during daylight hours. “Daylight” is interpreted as “civil twilight” in 

which the sun may be below the horizon, but the “horizon is clear and larger stars 

visible (Dutton’s Navigation and Plotting). In practical terms, the horizon, 

shoreline and receiving berths must be clearly seen under conditions of natural 

light;

o Visibility – A minimum of two miles of visibility is required for the movement of 

LNG vessels in U.S. waters. Since in marginal weather conditions visibility can 

vary significantly along the route, the decision as to whether sufficient visibility 

exists, and is likely to continue to exist for the transit, is a judgment call that will 

be made jointly between the attending pilot(s) and Transport Canada, in 

consultation with and the concurrence of the COTP. The minimum visibility 

limits must be commensurate with the combined safety and security parameters;

o Wind – 25 knots is the maximum sustained wind speed (determined during 

simulation tests), as measured on the vessel, in which an inbound or outbound 

transit will be allowed to commence. As with visibility, significant variation in 

wind conditions can exist along the route, and the decision as to whether wind 

conditions permit a safe transit will be made by the attending pilot(s) in 

consultation with, and concurrence by, the COTP;

o Traffic Control – One-way traffic patterns for deep-draft transits will be required 

and strictly enforced whenever LNG carriers are moving to avoid meeting or 

passing situations. At the discretion of the attending pilots and in consultation 

with vessel masters and Transport Canada, all vessel transits will be on a firstcome, first-served basis, with inbound vessels having priority over outbound;

o Anchoring – There are presently no designated (i.e., anchorages specified in 

regulation) for the area. However, three locations are routinely used: one located 

in the Bay of Fundy just outside of the transit corridor and to the north of Head 

Harbour Passage; one in the vicinity of Friars Roads southeast of Eastport; and 

one inside of Passamaquoddy Bay. LNG vessels will not be allowed to anchor, or 

hold, in Friar Roads while waiting for a berth – anchoring or holding under this 

circumstance must occur offshore;

o Loaded, inbound LNG carriers transiting Head Harbour Passage and Western 

Passage must maintain ample separation distance and uphold, at a minimum, the 

safety and security zone parameters. The intent of this limitation is to preclude 

the possibility of incurring overtaking situations and/or the need for holding at, or 
4.12 – Reliability and Safety 4-354

anchoring in Friar Roads. Non-LNG vessels may anchor in, or hold at Friar 

Roads while waiting for a vessel proceeding in the opposite direction to transit 

Head Harbour Passage or Western Passage; and

o With the exception of temporary boarding areas established by and for Coast 

Guard authorized assets, the anchoring or holding of LNG vessels within Friar 

Roads is limited to confirmed emergency situations only, such as major 

mechanical malfunctions and reduced visibility situations following nonforecasted, abrupt weather changes (fog, squalls, etc.) and/or as directed by, and 

in consultation with, the COTP.

• The development by Downeast, of an ERP required by Section 311 of EPAct 2005, 

15 U.S.C § 717b-1(e), approved by the FERC and accepted by the Coast Guard to enable 

a comprehensive and coordinated response to an LNG emergency, taking into account the 

need for: 

1) In-transit and dockside emergency procedures in the event of fire, mechanical 

malfunction, allision, grounding, and/or need of safe anchorage or refuge;

2) The potential environmental impact of an LNG release and the identification and 

acquisition of joint resource needs to respond to the potential release;

3) A contingency response plan specific to LNG and focusing on a layered response 

approach;

4) Coordinated marine firefighting training and emergency response, with an emphasis 

on containing and extinguishing LNG fires; and

5) An incident management training and collaborative exercise program.

• Collaboration with all appropriate jurisdictions on a joint, complementary rulemaking to 

formalize vessel traffic management practices and the establishment and enforcement of 

comprehensive safety and security zones for the protection of the LNG carrier, alternate 

waterway users, and area residents, taking into account the need for: 

1) A one-way vessel traffic scheme during transit operations;

2) Deep-draft vessel tug escorts and assistance services;

3) Mandatory pilotage throughout the transit route and during docking and undocking 

evolutions at all ports along the waterway;

4) Implementation of an Automatic Identification System for all vessels involved in the 

transport of LNG on this waterway;

5) Implementation of appropriate vessel speed restrictions; and

6) Implementation of appropriate environmental operating parameters (e.g. currents, 

tides, visibility, wind velocity, etc.).

All the safety and security zones associated with the transiting LNG marine traffic would move 

with the LNG vessel. As stated in the WSR, the average time for the zone to pass any given 

point would be approximately 18 minutes. Proper voyage planning and paying attention to 

advanced Broadcasts to Mariners should be used to alleviate potential conflicts with the moving 

safety and security zones associated with LNG marine traffic. 
4-355 4.12 – Reliability and Safety

• Downeast must develop and successfully conduct full mission bridge simulator training

for all pilots providing services to LNG carriers. The training must take into account the 

full spectrum of vessel design and length, cargo carrying capacity, method of propulsion, 

steering and rudder configuration, thruster arrangements, and maneuvering characteristics 

for those carriers being considered for charter. In addition, expanded simulator training 

incorporating the number and design of tug boats having the minimum performance and 

operating criteria previously outlined, would be required.

• Downeast must develop a Transit Management Plan (TMP) or other document, in 

consultation with the Coast Guard and other cognizant agencies, that clearly outlines the 

roles, responsibilities, and specific procedures for the LNG carrier, the LNG terminal, 

and all federal, state/provincial, and local stakeholders with responsibilities related to the 

proposed project and/or whose jurisdiction may reasonably be expected to be impacted 

by a potential navigation safety accident or terrorist attack.

• The applicant must prepare and submit an Operations Manual, as required by 33 C.F.R. § 

127.305, an Emergency Manual, as required by 33 C.F.R. § 127.307, and a Facility 

Security Plan as required by 33 C.F.R. § 105.120 to the COTP Sector Northern New 

England for review and approval at least 6 months but no more than 12 months before the 

facility would begin operations. In its comments as a coopering agency, the Coast Guard 

Sector Northern New England revised this timeline and stated that under 33 CFR Part 

127.019, Downeast would be required to submit two copies of its Operations and 

Emergency manual to Coast Guard Sector Northern New Englad at least 30 days prior to 

its first transfer of LNG. Additionally, at least 60 days prior to commencing operations, 

Downeast would need to submit a Facility Security Plan in accordance with 33 CFR Part 

105.410 to the Coast Guard Sector Northern New England.

• The applicant must provide written verification to the Coast Guard of collaboration with 

and acceptance from the Passamaquoddy Nation, ensuring its jurisdictional interests and 

public safety and security needs associated with this project are adequately met.

The risk mitigation measures in the WSR also provide that Downeast must determine and 

comply with all Canadian laws and regulations applicable to safe and secure navigation and the 

regulation of maritime traffic that comply with customary international law. The Coast Guard 

indicated that such laws and regulations should not discriminate among foreign ships or in their 

application have the practical effect of denying, hampering, or impairing the right of nonsuspendable innocent passage through an international strait. Moreover, consistent with 

international law, the Coast Guard will not require compliance with such laws and regulations 

that apply to the design, construction, manning, or equipment of foreign ships unless they are 

giving effect to generally accepted international rules or standards.

Based on its review of the WSA, the Coast Guard determined that the Passamaquoddy Bay 

navigation channel would be suitable for the type and frequency of LNG marine traffic 

associated with the proposed project. This determination is contingent upon implementation of 

the recommended measures outlined in the WSR to responsibly manage the maritime safety and 

security risks. These safety and security measures would be incorporated into a TMP, developed 

in consultation with the Coast Guard, area stakeholders, and other cognizant agencies. This plan 

would clearly spell out roles, responsibilities, and specific procedures for LNG marine traffic 
4.12 – Reliability and Safety 4-356

transiting Passamaquoddy Bay up to the terminal, as well as for all agencies involved in 

implementing security and safety during the operation.

The Coast Guard’s LOR is a recommendation on the current status of the waterway to the FERC, 

the lead agency responsible for siting the on-shore LNG facility. Neither the Coast Guard nor 

the FERC has authority to require waterway resources of anyone other than the applicant under 

any statutory authority or under the ERP or the Cost Sharing Plan (see section 4.12.8). However, 

as a general proposition, the Coast Guard in its WSR directed Downeast to "adequately 

demonstrate that an effective security regime has been established during the Canadian portion 

of the vessels' planned route prior to a loaded LNG vessel being allowed to transit to the 

facility." For Downeast to "adequately demonstrate" that an effective security regime has been 

established, it must show that the vessel is being provided with, and has the ability to implement, 

security measures that are at least equivalent to the level of security required for vessels 

transiting waters of the United States with similar characteristics (e.g., population densities, key 

port areas, critical infrastructure, etc.). 

Although the LOR and WSR each provide a list of suggested mitigation measures for 

responsibly managing the maritime safety and security risks associated with LNG marine traffic, 

the necessary vessel traffic and/or facility control measures may change depending on changes in 

conditions along the waterway. The Coast Guard regulations in 33 CFR 127 require that 

applicants annually review WSAs until a facility begins operation. Accordingly, Downeast is 

required to submit a report to the Coast Guard identifying any changes in conditions, such as 

changes to the port environment, the LNG facility, or the tanker route, that would affect the 

suitability of the waterway. Downeast’s provided substantiation of its internal review to the 

Coast Guard on September 13, 2011. In a letter dated November 10, 2011, the Coast Guard 

responded that the updates did not change the overall port environment, nor did they affect the 

suitability of the waterway for marine LNG traffic and that the Downeast WSA did not need to 

be amended at that time. 

On March 8, 2013, Downeast submitted the results of their annual review. In its response dated 

April 3, 2013, the Coast Guard determined that the reported updates in demographics, vessel 

traffic numbers, and resource capabilities did not substantially change the overall port 

environment nor affect the suitability of the waterway for marine LNG traffic, and therefore did 

not constitute a revision of, or amendment to, the WSA at this time. Further, the Coast Guard 

reminded Downeast that any significant changes to the physical description/layout of the 

proposed project, modifications to the proposed operation, alterations to the intended transit 

route, revisions to applied risk management methodologies, and/or changes to identified resource 

capabilities would need to be provided for Coast Guard review and validation and the WSA 

updated accordingly. On January 3, 2014, Downeast submitted the results of their latest annual 

review and on February 24, 2014, the Coast Guard determined that the reported updates to 

demographics, vessel traffic numbers and resource capabilities were clerical and do not affect the 

suitability of the waterway for LNG marine traffic. 

Under the Ports and Waterways Safety Act, the Magnuson Act, the Maritime Transportation 

Security Act of 2002, and the Safety and Accountability For Every Port Act, the COTP has the 

authority to prohibit LNG transfer or LNG vessel movements within his or her area of 

responsibility if he or she determines that such action is necessary to protect the waterway, port 

or marine environment. If this project is approved and if appropriate resources are not in place 
4-357 4.12 – Reliability and Safety

prior to LNG vessel movement along the waterway, then the COTP would consider at that time 

what, if any, vessel traffic and/or facility control measures would be appropriate to adequately 

address navigational safety and maritime security considerations. Therefore, we recommend 

that:

• Downeast should receive written authorization from the Director of OEP before 

commencement of service at the LNG terminal. Such authorization will only be 

granted following a determination by the Coast Guard, under its authorities under 

the Ports and Waterways Safety Act, the Magnuson Act, the Maritime 

Transportation Security Act of 2002, and the Safety and Accountability For Every 

Port Act, that appropriate measures to ensure the safety and security of the facility 

and the waterway have been put into place by Downeast or other appropriate 

parties. 

4.12.8 Emergency Response and Evacuation Planning

As required by 49 CFR § 193.2059, Downeast would need to prepare emergency procedures 

manuals that provide for: a) responding to controllable emergencies and recognizing an 

uncontrollable emergency; b) taking action to minimize harm to the public including the possible 

need to evacuate the public; and c) coordination and cooperation with appropriate local officials. 

Specifically, § 193.2509(b)(3) requires “Coordinating with appropriate local officials in 

preparation of an emergency evacuation plan...”

Section 3A(e) of the Natural Gas Act, added by Section 311 of EPAct 2005, stipulates that in any 

order authorizing an LNG terminal, the Commission must require the LNG terminal operator to 

develop an ERP in consultation with the Coast Guard and state and local agencies. The Coast 

Guard’s WSR also recommends that that the ERP be developed in consultation with the Coast 

Guard and other cognizant agencies, plus all federal, state/provincial, and local stakeholders with 

responsibilities related to the proposed project. The WSR states that, “Additionally, bilateral 

arrangements to ensure appropriate cross-boundary emergency response capabilities under the 

existing CANUSLANT48 agreement would be required,” but acknowledges that how the ERP 

development “process applies to Canada and whether Canadian officials will wish to be involved 

are issues as yet to be determined.” The FERC must approve the ERP prior to any final approval 

to begin construction. Therefore, we recommend that:

• Downeast should develop an ERP (including evacuation) and coordinate procedures 

with the Coast Guard; state/provincial, county, and local emergency planning 

groups; fire departments; state and local law enforcement; and appropriate 

federal/tribal agencies. This plan should include at a minimum: 

a. designated contacts with tribal, state and local emergency response agencies;

b. scalable procedures for the prompt notification of appropriate local officials and 

emergency response agencies based on the level and severity of potential 

incidents;

 48 Acronym for Canada, United States, Atlantic. CANUSLANT refers to the environmental response protocol is in 

place between the U.S. and Canada for spills of oil and other noxious substances.
4.12 – Reliability and Safety 4-358

c. procedures for notifying residents and recreational users within areas of 

potential hazard;

d. evacuation routes/methods for residents and public use areas that are within any 

transient hazard areas along the route of the LNG marine transit;

e. locations of permanent sirens and other warning devices; and

f. an “emergency coordinator” on each LNG vessel to activate sirens and other 

warning devices.

The ERP should be filed with the Secretary for review and written approval by the 

Director of OEP prior to initial site preparation. Downeast should notify the FERC 

staff of all planning meetings in advance and should report progress on the 

development of its ERP at 3-month intervals.

A number of organizations and individuals have expressed concern that the local community 

would have to bear some of the cost of ensuring the security and emergency management of the 

LNG facility and the LNG vessels while in transit and unloading at the berth. Section 3A(e) of 

the Natural Gas Act (as amended by EPAct 2005) specifies that the ERP must include a CostSharing Plan that contains a description of any direct cost reimbursements the applicants agree to 

provide to any state and local agencies with responsibility for security and safety at the LNG 

terminal and in proximity to LNG vessels that serve the facility. Therefore, we recommend 

that:

• The ERP should include a Cost-Sharing Plan identifying the mechanisms for 

funding all project-specific security/emergency management costs that would be 

imposed on tribal, state and local agencies. In addition to the funding of direct 

transit-related security/emergency management costs, this comprehensive plan 

should include funding mechanisms for the capital costs associated with any 

necessary security/emergency management equipment and personnel base. The 

Cost-Sharing Plan should be filed with the Secretary for review and written 

approval by the Director of OEP prior to initial site preparation.

The cost-sharing plan must specify what the LNG terminal operator would provide to cover the 

cost of the tribal, state and local resources required to manage the security of the LNG terminal 

and LNG vessel, and the state and local resources required for safety and emergency 

management, including:

• Direct reimbursement for any per-transit security and/or emergency management costs 

(for example, overtime for police or fire department personnel);

• Capital costs associated with security/emergency management equipment and personnel 

base (for example, patrol boats, firefighting equipment); and

• Annual costs for providing specialized training for local fire departments, mutual aid 

departments, and emergency response personnel; and for conducting exercises.

The cost-sharing plan must include the LNG terminal operator’s letter of commitment with 

agency acknowledgement for each state and local agency designated to receive resources.
4-359 4.12 – Reliability and Safety

4.12.9 Conclusions on Facility Reliability and Safety

As part of the NEPA review, Commission staff must assess whether the proposed facilities 

would be able to operate safely and securely to minimize potential public impact. Based on our 

technical review of the preliminary engineering designs, we conclude that sufficient layers of 

safeguards would be included in the facility designs to mitigate the potential for an incident that 

could impact the safety of the off-site public.

DOT reviewed the data and methodology Downeast used to determine the design spills based on 

the flow from various leakage sources, including piping, containers, and equipment containing 

hazardous liquids. In a letter to FERC dated January 30, 2014, DOT stated it has no objection to 

Dowenast’s methodology for determining the candidate design spills used to establish the 

required siting for its proposed LNG import facility. Based on the hazard area calculations

performed by Downeast, we conclude that potential hazards from the siting of the facility at this 

location would not have a significant impact on public safety.

Since 1959, ships have transported LNG without a major release of cargo or a major accident 

involving an LNG vessel. For the past 40 years, LNG shipping operations have been safely

conducted in U.S. ports and waterways. All LNG vessels entering U.S. waters are required to be 

certified by the Coast Guard as designed and operating in accordance with both international 

standards and the U.S. regulations for bulk LNG carriers under 46 CFR 154. As a result, the 

possibility of a LNG release due to an accident, such as a collision or grounding, is considered 

minimal. In addition, current operational procedures in use by the Coast Guard in U.S. ports, 

such as managing ship traffic and active ship control in inner and outer harbors, further reduce 

the potential of LNG spill from accidental causes.

Potential results from intentional acts and threats identified by marine safety, law enforcement, 

and intelligence agencies must also be considered. Such scenarios, including attacks with 

shoulder-fired weapons, explosives, and attacks by aircraft and other boats, could result in spills 

from LNG carriers visiting the proposed project. Security procedures for both the facility and 

the LNG carriers could be used to reduce the potential of an LNG spill from intentional causes. 

Both the on-shore facility and the LNG carriers would be subject to stringent requirements for 

security plan development and approval by the Coast Guard under Title 33, CFR, Parts 104 and 

105; the MTSA; the ISPS; and SOLAS.

If an LNG spill were to occur along the waterway, the primary hazard to the public would be 

from radiant heat from a pool fire. In order to assess the maritime safety and security risks of 

LNG marine traffic travelling to the proposed facility, hazard distances from both accidental and 

intentional events were estimated for LNG carriers with cargo capacities up to 265,000 m3. 

Based on the results of this analysis, the Coast Guard recommended that the waterway along the 

proposed carrier transit route would be suitable for the type and frequency of LNG marine traffic 

associated with this proposed project. However, the Coast Guard’s recommendation is 

contingent upon implementation of the recommended measures, outlined in the WSR, to 

responsibly manage the maritime safety and security risks. 

The Coast Guard’s WSR, which accompanied the LOR in January 2009, outlined the Coast 

Guard’s validation process and documented those items considered in making the 

recommendation to the FERC as to the suitability of the waterway for LNG marine traffic. 
4.12 – Reliability and Safety 4-360

Although the Coast Guard’s WSR was very comprehensive, it was not meant to be all inclusive. 

Rather, the intent was to provide a summary of the review process that was followed as well as 

deliver an executive overview of the applicant’s WSA - both designed to address potential 

navigation safety and security risks associated with the proposed transit route.

Additionally, it should be understood that the Coast Guard's LOR is solely a recommendation 

made to the FERC on whether the COTP considers a particular waterway, in this case the 

Passamaquoddy Bay and its approaches, suitable for LNG marine traffic from a safety and 

security perspective. Accordingly, the Coast Guard’s LOR should not be perceived as being a 

form of licensure or federal permitting action, nor does it, within itself, constitute approval or 

disapproval of any given waterway for a specified use. Likewise any/all recommended 

safeguards and/or risk reduction strategies contained therein, or within the accompanying WSR, 

should not be perceived as being prescribed conditions by the Coast Guard. However, under the 

Ports and Waterways Safety Act, the Magnuson Act, the Maritime Transportation Security Act 

of 2002, and the Safety and Accountability For Every Port Act, the COTP has the authority to 

prohibit LNG transfer or LNG vessel movements within his or her area of responsibility if he or 

she determines that such action is necessary to protect the waterway, port or marine environment. 

If this project is approved and if appropriate resources are not in place prior to LNG vessel 

movement along the waterway, then the COTP would consider at that time what, if any, vessel 

traffic and/or facility control measures would be appropriate to adequately address any 

navigational safety and maritime security considerations.

4.12.10 Pipeline Safety Standards

The transportation of natural gas by pipeline involves some incremental risk to the public in the 

event of an accident and subsequent release of gas. The greatest hazard is a fire or explosion 

following a major pipeline rupture. Methane, the primary component of natural gas, is colorless, 

odorless, and tasteless. It is not toxic, but is classified as a simple asphyxiate, possessing a slight 

inhalation hazard. If breathed in high concentration, oxygen deficiency can result in serious 

injury or death. Methane has an ignition temperature of 1,000°F and is flammable at 

concentrations between 5.0 percent and 15.0 percent in air. Unconfined mixtures of methane in 

air are not explosive. However, a flammable concentration within an enclosed space in the 

presence of an ignition source can explode. It is buoyant at atmospheric temperatures and 

disperses rapidly in air.

The DOT is mandated to provide pipeline safety under Title 49, U.S.C. Chapter 601. The 

Pipeline and Hazardous Materials Safety Administration (PHMSA), OPS, administers the 

national regulatory program to ensure the safe transportation of natural gas and other hazardous 

materials by pipeline. It develops safety regulations and other approaches to risk management 

that ensure safety in the design, construction, testing, operation, maintenance, and emergency 

response of pipeline facilities. Many of the regulations are written as performance standards 

which set the level of safety to be attained and allow the pipeline operator to use various 

technologies to achieve safety. PHMSA ensures that people and the environment are protected 

from the risk of pipeline incidents. This work is shared with state agency partners and others at 

the federal, state, and local level. Section 5(a) of the Natural Gas Pipeline Safety Act provides 

for a state agency to assume all aspects of the safety program for intrastate facilities by adopting 

and enforcing the federal standards, while Section 5(b) permits a state agency that does not 

qualify under Section 5(a) to perform certain inspection and monitoring functions. A state may 
4-361 4.12 – Reliability and Safety

also act as DOT's agent to inspect interstate facilities within its boundaries; however, the DOT is 

responsible for enforcement action. The state of Maine is authorized by PHSMA under 

Section 5(a) to assume all aspects of the safety program for intrastate facilities. 

The DOT pipeline standards are published in Parts 190-199 of Title 49 of the CFR. Part 192 of 

49 CFR specifically addresses natural gas pipeline safety issues. Under a Memorandum of 

Understanding on Natural Gas Transportation Facilities (Memorandum) dated January 15, 1993 

between the DOT and the FERC, the DOT has the exclusive authority to promulgate federal 

safety standards used in the transportation of natural gas. Section 157.14(a)(9)(vi) of the FERC's 

regulations require that an applicant certify that it would design, install, inspect, test, construct, 

operate, replace, and maintain the facility for which a certificate is requested in accordance with 

federal safety standards and plans for maintenance and inspection, or shall certify that it has been 

granted a waiver of the requirements of the safety standards by the DOT in accordance with 

Section 3(e) of the Natural Gas Pipeline Safety Act.

The FERC accepts this certification and does not impose additional safety standards other than 

the DOT standards. If the Commission becomes aware of an existing or potential safety 

problem, there is a provision in the Memorandum to promptly alert DOT. The Memorandum 

also provides for referring complaints and inquiries made by state and local governments and the 

general public involving safety matters related to pipeline under the Commission's jurisdiction. 

The FERC also participates as a member of the DOT's Technical Pipeline Safety Standards 

Committee which determines if proposed safety regulations are reasonable, feasible, and 

practicable.

The natural gas pipeline and associated aboveground facilities proposed for the Downeast LNG 

Project must be designed, constructed, operated, and maintained in accordance with the DOT 

Minimum Federal Safety Standards in 49 CFR 192. The regulations are intended to ensure

adequate protection for the public and 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 defines area classifications, based on population density in the vicinity of the 

pipeline, and specifies more rigorous safety requirements for populated areas. The class location 

unit is an area that extends 220 yards on either side of the centerline of any continuous 1-mile 

length of pipeline. The four area classifications are defined as follows:

• Class 1 Location with 10 or fewer buildings intended for human occupancy.

• Class 2 Location with more than 10 but less than 46 buildings intended for human 

occupancy.

• Class 3 Location with 46 or more buildings intended for human occupancy or where 

the pipeline lies within 100 yards of any building, or small well-defined 

outside area occupied by 20 or more people during normal use.

• Class 4 Location where buildings with four or more stories aboveground are 

prevalent.

Class locations representing more populated areas require higher safety factors in pipeline 

design, testing, and operation. Pipelines constructed on land in Class 1 locations must be 
4.12 – Reliability and Safety 4-362

installed with a minimum depth of cover of 30 inches in normal soil and 18 inches in 

consolidated rock. Class 2, 3, and 4 locations, as well as drainage ditches of public roads and 

railroad crossings, require a minimum cover of 36 inches in normal soil and 24 inches in 

consolidated rock. All pipelines installed in navigable rivers, streams, and harbors must have a 

minimum cover of 48 inches in soil or 24 inches in consolidated rock.

Class locations also specify the maximum distance to a sectionalizing block valve (10.0 miles in 

Class 1, 7.5 miles in Class 2, 4.0 miles in Class 3, and 2.5 miles in Class 4). Pipe wall thickness 

and pipeline design pressures, hydrostatic test pressures, maximum allowable operating pressure, 

inspection and testing of welds, and frequency of pipeline patrols and leak surveys must also 

conform to higher standards in more populated areas. The majority of the proposed sendout 

pipeline route would cross open land that is sparsely populated. About 24 miles of proposed 

pipeline route would be located in Class 1 areas, and about 4.9 miles would be in a Class 2 area,

and 0.9 miles would be located in Class 3 areas. No portion of the sendout pipeline would be in 

Class 4 areas. In addition, all pipeline interconnects, and pipeline facilities within the fenced 

enclosures of the meter station, launcher and receiver, and MLVs would be designed and 

constructed to meet Class 3 requirements.

If a subsequent increase in population density adjacent to the right-of-way indicates a change in 

class location above existing design for the pipeline, Downeast would reduce the maximum 

allowable operating pressure or replace the segment with pipe of sufficient grade and wall 

thickness, if required to comply with the DOT code of regulations for the new class location.

The Pipeline Safety Improvement Act of 2002 required operators to develop and follow a written 

integrity management program that contained all the elements described in 49 CFR 192.911 and 

addressed the risks on each transmission pipeline segment. Specifically, the law establishes an 

integrity management program which applies to all high consequence areas (HCA).

The DOT has published rules that define HCAs where a gas pipeline accident could do 

considerable harm to people and their property and requires an integrity management program to 

minimize the potential for an accident. This definition satisfies, in part, the Congressional 

mandate for DOT to prescribe standards that establish criteria for identifying each gas pipeline 

facility in a high-density population area.

The HCAs may be defined in one of two ways. In the first method an HCA includes: 

• current Class 3 and 4 locations;

• any area in Class 1 or 2 where the potential impact radius49 is greater than 660 feet and 

there are 20 or more buildings intended for human occupancy within the potential impact 

circle;50 or 

• any area in Class 1 or 2 where the potential impact circle includes an identified site.51

 49 The potential impact radius is calculated as the product of 0.69 and the square root of the maximum allowable 

operating pressure of the pipeline in psi multiplied by the pipeline diameter in inches.

50 The potential impact circle is a circle of radius equal to the potential impact radius. 51 An identified site is an outside area or open structure that is occupied by 20 or more persons on at least 50 days in 

any 12-month period; a building that is occupied by 20 or more persons on at least five days a week for any 

10 weeks in any 12-month period; or a facility that is occupied by persons who are confined, are of impaired 

mobility, or would be difficult to evacuate.
4-363 4.12 – Reliability and Safety

In the second method, an HCA includes any area within a potential impact circle which contains:

• 20 or more buildings intended for human occupancy; or

• an identified site. 

Once a pipeline operator has determined the HCAs on its pipeline, it must apply the elements of 

its integrity management program to those segments of the pipeline within the HCAs. The DOT 

regulations specify the requirements for the integrity management plan at Section 192.911. The 

HCAs would be determined based on the relationship of the pipeline centerline to other nearby 

structures and identified sites. Of the 29.8 miles of the proposed sendout pipeline, Downeast has 

identified approximately 2.7 miles that would be classified as HCA. The pipeline integrity 

management rule for HCAs requires inspection of the entire pipeline in HCAs every seven years. 

Table 4.12.9-1 lists HCA locations by milepost.

TABLE 4.12.9-1

Locations of High Consequence Areas

Beginning 

Milepost

Ending 

Milepost Criteria Distance To Pipeline Land Use Comments

15.60 16.50 Class 3 < 660 feet Residential - single 

family

Baring, ME

18.10 18.10 Identified Site < 660 feet Truck Stop Potential for 20+ people

21.40 22.40 Class 2, 20+ houses 741 ft. PIR Residential - single 

family

Woodland, ME. Includes over 20 

houses within a 741-ft. radius 

Potential Impact Radius, plus two 

identified sites (apartments or 

churches) near Milepost 22.1

23.80 24.60 Class 2, 20+ houses 741 ft. PIR Residential - single 

family

Area along U.S. Hwy. 1 with 

approx. 20 houses inside a 741-ft. 

radius Potential Impact Radius

Part 192 prescribes the minimum standards for operating and maintaining pipeline facilities, 

including the requirement to establish a written plan governing these activities. The sendout 

pipeline would be continuously monitored from a SCADA system at an operations control 

center. The control room personnel would be qualified (per Subpart N of 49 CFR Part 192) to 

identify and respond to abnormal conditions on the pipeline system. Downeast would prepare an 

Operations and Maintenance Procedures manual for the pipeline system that meets the 

requirements of 192.605. The pipeline would be patrolled and inspected on the ground on a 

periodic basis per DOT requirements. The frequency of these inspections would be affected by 

activity along the pipeline route such as construction or possible encroachment. These 

inspections would identify conditions indicative of pipeline leaks, evidence of pipeline damage 

or deterioration, damage to erosion controls, loss of cover, third-party activities or conditions 

which may presently or in the future affect pipeline integrity, safety, or operation of the pipeline. 

The pipeline system would participate in the state “One Call” system. The “One Call” system 

for Maine is the Dig Safe System®, located in Massachusetts, which is enforced by the Maine 

PUC. 
4.12 – Reliability and Safety 4-364

Under Section 192.615, each pipeline operator must also establish an emergency plan that 

includes procedures to minimize the hazards in a natural gas pipeline emergency. Key elements 

of the plan include procedures for:

• receiving, identifying, and classifying emergency events, gas leakage, fires, explosions, 

and natural disasters;

• establishing and maintaining communications with local fire, police, and public officials, 

and coordinating emergency response;

• emergency shutdown of system and safe restoration of service;

• making personnel, equipment, tools, and materials available at the scene of an 

emergency; and

• protecting people first and then property, and making them safe from actual or potential 

hazards.

Part 192 requires that each operator must establish and maintain liaison with appropriate fire, 

police, and public officials to learn the resources and responsibilities of each organization that 

may respond to a natural gas pipeline emergency, and to coordinate mutual assistance. The 

operator must also establish a continuing education program to enable customers, the public, 

government officials, and those engaged in excavation activities to recognize a gas pipeline 

emergency and report it to appropriate public officials. The emergency response planning 

conducted by Downeast would incorporate the requirements of these procedures. Necessary 

personnel and equipment would be provided by Downeast or by contracting specialized firms.

4.12.11 Pipeline Accident Data

The DOT requires all operators of natural gas transmission pipelines to notify the DOT of any 

significant incident and to submit a report within 20 days. Significant incidents are defined as 

any leaks that:

• caused a death or personal injury requiring hospitalization; or

• involve property damage of more than $50,000 (1984 dollars52).

During the 20 year period from 1994 through 2013, a total of 1,237 significant incidents were 

reported on the more than 300,000 total miles of natural gas transmission pipelines nationwide.

Additional insight into the nature of service incidents may be found by examining the primary 

factors that caused the failures. Table 4.12.11-1 provides a distribution of the causal factors as 

well as the number of each incident by cause.

The dominant causes of pipeline incidents are corrosion and pipeline material, weld or 

equipment failure constituting 48.2 percent of all significant incidents. The pipelines included in 

the data set in table 4.12.11-1 vary widely in terms of age, diameter, and level of corrosion 

control. Each variable influences the incident frequency that may be expected for a specific 

segment of pipeline.

 52 $50,000 in 1984 dollars is approximately $115,000 as of March 2014 (CPI 2014)
4-365 4.12 – Reliability and Safety

The frequency of significant incidents is strongly dependent on pipeline age. Older pipelines 

have a higher frequency of corrosion incidents, since corrosion is a time-dependent process. The 

use of both an external protective coating and a cathodic protection system53, required on all 

pipelines installed after July 1971, significantly reduces the corrosion rate compared to 

unprotected or partially protected pipe.

TABLE 4.12.11-1

Natural Gas Transmission Pipeline Serious Incidents by Cause (1994-2013) a/

Cause No. of Incidents Percentage e/

Corrosion 292 23.6

Excavation b/ 211 17.0

Pipeline material, weld or equipment failure 304 24.6

Natural force damage 142 11.5

Outside force c/ 74 6.0

Incorrect operation 33 2.7

All other causes d/ 181 14.6

TOTAL 1,237 -

a/ All data gathered from PHMSA Significant incident files, March 25, 2014

b/ Includes third party damage

c/ Fire, explosion, vehicle damage, previous damage, intentional damage

d/ Miscellaneous causes or unknown causes

e/ Due to rounding, column does not total 100 percent

Outside force, excavation, and natural forces are the cause in 34.5 percent of significant pipeline 

incidents. These result from the encroachment of mechanical equipment such as bulldozers and 

backhoes; earth movements due to soil settlement, washouts, or geologic hazards; weather 

effects such as winds, storms, and thermal strains; and willful damage.

Older pipelines have a higher frequency of outside forces incidents partly because their location 

may be less well known and less well marked than newer lines. In addition, the older pipelines 

contain a disproportionate number of smaller-diameter pipelines which have a greater rate of 

outside forces incidents because small diameter pipelines are more easily crushed or broken by 

mechanical equipment or earth movement. Table 4.12.11-2 shows various causes of outside 

force incidents.

Since 1982, operators have been required to participate in "One Call" public utility programs in 

populated areas to minimize unauthorized excavation activities in the vicinity of pipelines. The 

"One Call" program is a service used by public utilities and some private sector companies (e.g.,

oil pipelines and cable television) to provide preconstruction information to contractors or other 

maintenance workers on the underground location of pipes, cables, and culverts.

 53 Cathodic protection is a technique to reduce corrosion (rust) of the natural gas pipeline through the use of an 

induced current or a sacrificial anode (like zinc) that corrodes at faster rate to reduce corrosion.
4.12 – Reliability and Safety 4-366

TABLE 4.12.11-2

Outside Forces Incidents by Cause (1994-2013) a/

Cause No. of Incidents Percent of all 

Incidents b/

Third-party excavation damage 176 41.2

Operator excavation damage 25 5.9

Unspecified excavation damage/previous damage 10 2.3

Heavy rain/floods 72 16.9

Earth movement 35 8.2

Lightning/temperature/high winds 21 4.9

Natural force (other) 14 3.3

Vehicle (not engaged with excavation) 45 10.5

Fire/explosion 8 1.9

Previous mechanical damage 5 1.2

Fishing or maritime activity 7 1.6

Intentional damage 1 0.2

Electrical arching from other equipment/facility 1 0.2

Unspecified/other outside force 7 1.6

TOTAL 427 99.9

a/ Excavation, Outside Force, and Natural Force from table 4.12.11-1.

b/ Due to rounding, column does not total 100 percent.

4.12.12 Impact on Public Safety

As stated above, Downeast would comply with the DOT pipeline safety standards as well as 

regular monitoring and testing of the pipeline. While pipeline failures are rare, the potential for 

pipeline systems to rupture and the risk to nearby residents is discussed below. 

The serious incidents data summarized in table 4.12.12-1 include pipeline failures of all 

magnitudes with widely varying consequences. Table 4.12.12-1 presents the average annual 

injuries and fatalities that occurred on natural gas transmission lines in the 5-year period between 

2009 and 2013. 

TABLE 4.12.12-1

Injuries and Fatalities - Natural Gas Transmission Pipelines

Year Injuries Fatalities

2009 11 0

2010 a/ 61 10

2011 1 0

2012 7 0

2013 2 0

a/ All of the public fatalities in 2010 were due to the Pacific Gas and Electric pipeline rupture and fire in San Bruno, California 

on September 9, 2010.
4-367 4.12 – Reliability and Safety

The majority of fatalities from pipelines are due to local distribution pipelines not regulated by 

FERC. These are natural gas pipelines that distribute natural gas to homes and businesses after 

transportation through interstate natural gas transmission pipelines. In general, these distribution 

lines are smaller diameter pipes and/or plastic pipes which are more susceptible to damage. 

Local distribution systems do not have large right-of-ways and pipeline markers common to the 

FERC regulated natural gas transmission pipelines.

The nationwide totals of accidental fatalities from various anthropogenic and natural hazards are 

listed in table 4.12.12-2 to provide a relative measure of the industry-wide safety of natural gas 

transmission pipelines. Direct comparisons between accident categories should be made 

cautiously, however, because individual exposures to hazards are not uniform among all 

categories. The data nonetheless indicate a low risk of death due to incidents involving natural 

gas transmission pipelines compared to the other categories. Furthermore, the fatality rate is 

much lower than the fatalities from natural hazards such as lightning, tornados, or floods.

TABLE 4.12.12-2

Nationwide Accidental Deaths a/

Type of Accident Annual Number of Deaths

All accidents 117,809

Motor vehicle 45,343

Poisoning 23,618

Falls 19,656

Injury at work 5,113

Drowning 3,582

Fire, smoke inhalation, burns 3,197

Floods b/ 89

Lightning b/ 52

Tornado b/ 74

Natural gas distribution lines c/ 14

Natural gas transmission pipelines c/ 2

a/ All data, unless otherwise noted, reflects 2005 statistics from U.S. Census Bureau, Statistical Abstract of the United States: 

2010 (129th Edition) Washington, DC, 2009; http://www.census.gov/statab.

b/ NOAA National Weather Service, Office of Climate, Water and Weather Services, 30 year average (1983-2012) 

http://www.weather.gov/om/hazstats.shtml.

c/ PHMSA significant incident files, March 25, 2014. http://primis.phmsa.dot.gov/comm/reports/safety/, 20 year average.

The available data show that natural gas transmission pipelines continue to be a safe, reliable 

means of energy transportation. From 1994 to 2013, there were an average of 62 significant 

incidents, 10 injuries and 2 fatalities per year. The number of significant incidents over the more 

than 300,000 miles of natural gas transmission lines indicates that the risk is low for an incident 

at any given location. The operation of the sendout pipeline would represent a slight increase in 

risk to the nearby public.
4.13 – Cumulative Impacts 4-368

4.13 CUMULATIVE IMPACTS

In 40 CFR 1508.7, the President’s CEQ defines cumulative impacts as the “impacts on the 

environment that result from the incremental impact of the action when added to other past, 

present, and reasonably foreseeable future actions regardless of what agency (federal or nonfederal) or person undertakes such other actions.” Although the individual impact of each 

individual project may be minor, the additive or synergistic impacts from multiple projects could 

be significant. Impacts subject to cumulative effects analysis for the Downeast LNG Project 

were identified by determining the environmental impact issues associated with the proposed 

action; establishing the geographic scope of the study area; establishing the time frame of the 

analysis; and identifying other past, present, and/or reasonably foreseeable future actions that 

have affected, or could affect, the resources of concern.

For this analysis, we looked at potential impacts from known projects existing or proposed along 

Passamaquoddy Bay and/or near the proposed LNG terminal, LNG projects that would use the 

M&NE system, and other relevant projects in Washington County. More geographically distant 

projects (e.g., Northeast Gateway LNG, Neptune LNG, Cacouna Energy LNG, Rabaska LNG) 

are not assessed because their impact would generally be localized and, therefore, would not 

contribute significantly to cumulative impacts in the proposed project area.

Construction of the Downeast LNG Project would result in both short- and long-term, minor to 

moderate environmental impacts. Impacts associated with construction and operation of the 

LNG terminal would be permanent (e.g., land use change) and temporary (e.g., constructionrelated noise). Impacts associated with construction and operation of the pipeline generally 

would be short-term and minor because resources within the area affected by construction would 

be restored or allowed to revegetate following pipeline installation. Some long-term impacts 

could occur, however, if resources cannot be restored to original conditions (e.g., cleared forest 

lands), or when resources are permanently affected due to operational and maintenance 

requirements (e.g., vegetation maintenance within the operational pipeline rights-of-way).

The environmental impact analysis contained in this EIS indicates that pipeline construction and 

operation activities for the Downeast LNG Project would result in short-term and minor impacts 

associated primarily with construction across waterbodies and wetlands, fish and other wildlife 

habitats, recreation, socioeconomics, transportation, and noise. Long-term impacts associated 

with construction of the LNG terminal and pipeline-related, aboveground facilities are somewhat 

greater, and would include the permanent clearing of timber at the terminal and along the 

permanent pipeline right-of-way, and the prohibition of construction or excavation above the 

subsurface pipeline. Although these types of impacts were not considered significant for the 

Downeast LNG Project, they were considered on a cumulative impact basis in association with 

the review of other identified projects in the area. 

The cumulative impact analysis in the draft EIS considered other approved, constructed, 

proposed, or announced LNG facilities in Maine and Maritimes Canada. However, since 

publication of the draft EIS, some of these LNG projects (Quoddy Bay, Calais, and Maple) have 

been put on hold and/or the environmental review process has been terminated. Therefore, these 

projects are no longer included in our cumulative impacts analysis. In addition, the Pleasant 

Point/Western Passage Tidal Energy Project has been combined with our analysis of the 

Tidewalker Tidal Energy Project.
4-369 4.13 – Cumulative Impacts

We also contacted officials in eastern Washington County, Maine, to identify other projects that 

should be addressed in this cumulative impacts analysis. Responses were received from officials 

in Calais and Eastport, Maine. The COE has recorded more than two hundred permit actions in 

the area since 1988; most had limited impacts on aquatic resources and qualified for general 

permits. The exceptions are the two completed M&NE Pipeline projects listed below. The 

projects included in our cumulative impacts analysis consist of the following:

• Downeast LNG Project – Robbinston, Maine. Described in section 2.0 of this EIS.

• EMEC electric transmission line – Robbinston, Maine. This is a nonjurisdictional facility 

associated with the Downeast LNG Project. The facility and potential environmental 

impacts are described in section 2.9 of this EIS.

• Canaport LNG Project – St. John, New Brunswick, Canada. Canaport LNG Project is an 

LNG receiving, storage, and regasification terminal in St. John, New Brunswick that 

started receiving LNG in June 2009. The facility is the first LNG regasification plant in 

Canada, supplying natural gas to Canadian and American markets. Canaport has two

160,000 m3 storage tanks and potential for addition of a third tank, with a maximum 

sendout capacity of 1.2 Bcfd. A 90-mile-long pipeline delivers natural gas from the 

Canaport LNG site to an interconnection with the M&NE pipeline near the U.S. border.

• Deep Panuke Offshore Gas Development Project – Southeast of Halifax, Nova Scotia, 

Canada. Installation of a jack-up mobile offshore production unit (MOPU), a maximum 

of nine subsea wells (five production, one injection, and three future production wells), 

up to nine 10-inch-diameter subsea production flowlines tied to the MOPU, and a 

22-inch-diameter subsea pipeline connecting to M&NE’s facilities in Goldboro, Nova 

Scotia. Onshore components will consist of monitoring, pressure-control, and pig 

launching and receiving facilities, in addition to a small building housing SCADA 

equipment. Gas production began in mid-2013.

• M&NE Pipeline Project, Baileyville to Westbrook, ME – Approximately 347 miles of 

gas pipeline, consisting of 200 miles of mainline between Westbrook (York County) and 

Baileyville (Washington County) and 147 miles of lateral pipeline; two new compressor 

stations; twelve new meter stations; and associated aboveground facilities. The 

Commission authorized the project in July 1998 and it was placed into service in 

December 1999.

• M&NE Phase IV Project – various counties in Maine and Massachusetts. Expansion of 

M&NE’s existing system consisting of 1.7 miles of new 30-inch-diameter pipeline in 

Washington County, Maine; two new aboveground meter stations (Washington and 

Cumberland Counties, Maine); five new compressor stations (Hancock, Penobscot, 

Waldo, Cumberland, and York Counties, Maine); and minor modifications to existing 

compressor and meter stations (Washington and Sagadahoc Counties, Maine and Essex 

County, Massachusetts). The Commission authorized the Phase IV Expansion Project on 

February 15, 2007. Construction was completed and the facilities placed into service in 

January 2009. 

• Tidewalker Tidal Energy Project – Half Moon Cove, Cobscook, Maine. Tidewalker 

Tidal Energy Project (Tidewalker) would involve construction of a dam at the location of 
4.13 – Cumulative Impacts 4-370

a former toll bridge connecting Moose Island (Eastport, Maine) to the mainland at Perry,

Maine. The proposed dam would be approximately 1,210 feet long with a maximum 

depth of 40 feet below MSL and a maximum elevation of 27 feet above MSL. Two small 

dams existing along the easterly perimeter of Half Moon Cove were constructed in the 

1930s to isolate the tidal basin from Passamaquoddy Bay. Half Moon Cove discharges 

into Cobscook Bay at the site of the proposed rockfill dam/powerhouse. Tidewalker 

received a preliminary permit from FERC in April 2007 to develop a full permit and 

license application for this location (P-12704). The integrated licensing process was 

terminated by FERC in November 2009, and an application for a successive preliminary 

permit was filed in March 2010 with the Maine DEP (Maine DEP 2010). A final 

application to FERC is anticipated in 2014.

• Halcyon Pennamaquan Tidal Energy Project - Pennamaquan Estuary, Town of 

Pembroke, Maine. A 1,500-foot-long Halcyon Enclosure will consist of up to 17 Alstom 

Power bulb turbine gensets placed horizontally within the powerhouse caissons at the 

center, a boat lock and concrete minicaissons reaching to each shoreline. Power output is 

expected to be at least 25.6 MW. The facility will interconnect with an upgraded 

transmission line on Hershey Neck Road which terminates at the Bangor Hydro Electric 

Company substation in Pembroke. Completion is expected in 2017.

• Ocean Renewable Power Company (ORPC) Western Passage Tidal Energy Project –

(Eastport tidal sites at Western Passage of Passamaquoddy Bay and at Cobscook Bay). 

The project consists of a tidal (or ocean) current electric power generation facility that 

would utilize a series of underwater ocean current generation modules. No dams, 

spillways, penstocks, powerhouses, tailraces, or other structures within or near the 

proposed tidal energy project area would be constructed as part of this proposed project. 

ORPC received preliminary permits from FERC in July 2007 (P-12711 for Cobscook 

Bay and P-12680 for Western Passage). The notice of intent to file a license application 

and draft application for a pilot project license was filed in July 2009. ORPC placed its 

first prototype turbine generator unit online at the Cobscook Bay site in September 2012, 

and will evaluate production for about three years to determine the potential for large 

scale power production.

• U.S. Route 1 Reconstruction – Eastport to Calais, Maine. Reconstruction of U.S. Route 1 

along the 12 miles between Eastport and Calais was completed in summer 2008 (Maine 

DOT 2007).

• Border Crossing – Calais, Maine. Construction of a new border crossing facility between 

the United States and Canada completed in November 2009.

• Atlantic Salmon Aquaculture Facilities – Eastport, Maine. Cooke Aquaculture Inc. 

conducted a rehabilitation of aquaculture facilities on the coast. The facilities are 

currently in operation.

• Port of Eastport Gateway Project – Eastport, Maine. The port is in the planning phase of 

this project that would be designed to restore rail freight service to the port of Eastport. 

The port is also developing a proposal to replace the existing breakwater pier with a new 

municipal pier. Existing facilities at the port include the Estes Head Cargo Terminal,

which can accommodate a ship of 900 feet in Berth A and one up to 550 feet in Berth B. 
4-371 4.13 – Cumulative Impacts

Berth B also accommodates barges. There are several open storage areas and warehouses 

on the site. The operations are supervised from the Federal Marine Terminal offices 

located above the Estes Head pier. Approach depths to the Estes Head pier are in excess 

of 100 feet, and the mean low water depth is 64 feet.

• Stetson Mountain Wind Power Project –Washington County, Maine. Proposed by First 

Wind, to include 38 wind energy turbines (57 megawatts) on a ridgeline on Stetson 

Mountain between the communities of Danforth and Springfield. An application filed 

with the Maine Land Use Regulation Commission was approved on January 3, 2008. 

The project officially began generating power on a commercial basis in January 2009. 

The Stetson Phase II project, which became operational in April 2010, added 17 turbines 

(25.5 megawatts) on Jimmey and Owl Mountains. First Wind has a 15-year purchase 

agreement with Harvard University for half of Stetson II’s output. The rest is sold to 

Constellation Energy of Maryland, an energy product and services supplier to wholesale 

and retail electric customers.

There are several other projects that were announced or proposed in the area, but have been 

cancelled or the applications withdrawn since issuance of our draft EIS. For this reason, we have 

not included the following projects in our cumulative impacts analysis.

• Quoddy Bay LNG Project – Pleasant Point, Maine. Quoddy Bay’s once proposed LNG 

terminal site is about 8.0 miles south of Downeast’s proposed site. The Quoddy Bay 

LNG Project would include two LNG ship berths and associated unloading platforms and 

pipeline, three 160,000 m3 storage tanks, and a 36-mile-long, 36-inch-diameter natural 

gas sendout pipeline extending from the LNG terminal to the existing M&NE pipeline 

system at the Baileyville, Maine compressor station. During operation, the Quoddy Bay 

LNG Project would receive about 60 LNG vessels per year. On October 17, 2008, FERC 

dismissed Quoddy Bay LNG’s application to build and operate an LNG import terminal 

and associated pipeline.

• Calais LNG Project – Calais, Maine. In December 2009, Calais LNG filed an application 

with the FERC proposing to construct and operate an LNG import terminal and storage 

facility in Calais, Maine, about 15 miles north of Downeast’s Robbinston, Maine 

location. The facility would have a nominal sendout capacity of about 1.0 Bcfd and a 

peak sendout capacity of 1.5 Bcfd. The 330-acre site would include 2,800 feet of 

shoreline along the St. Croix River and Passamaquoddy Bay. The LNG terminal would 

be located near Ford Point on the St. Croix River in the City of Calais. The project would 

also include the installation of a 20-mile-long, 36-inch-diameter sendout pipeline, 

originating at the LNG terminal and ending at an interconnect with the M&NE pipeline 

system in Princeton. During operation, the Calais LNG Project would receive about 100 

LNG vessels per year. In April 2012, the Commission dismissed Calais LNG’s 

application to build and operate an LNG import terminal and associated pipeline.

• EMEC Transmission Line and Substation to the Calais LNG terminal – If the Calais LNG 

terminal were constructed, electric power to the terminal would be supplied by EMEC 

with a direct tie-in to the property site. EMEC would install a new electric transmission 

line from a proposed switching station located off U.S. Route 9 near King Street in Calais 

to a new substation that would be located in the LNG terminal property, accessible from 
4.13 – Cumulative Impacts 4-372

U.S. Route 1. The electric transmission line would be approximately 6.7 miles in length 

and would consist of a 69-kV line. In its application to the FERC, Calais LNG indicated 

that more than 95 percent of the new transmission line would be a dual corridor with the 

Calais LNG sendout pipeline from portions of the route between MP 6.6 to MP 20.7.

• Bear Head LNG Project – Point Tupper, Nova Scotia, Canada. Construction began in 

2004, but was placed on hold indefinitely in February 2007 due to lack of long-term LNG 

supply.

• Maple LNG – Goldboro, Guysborough County, Nova Scotia, Canada. Proposed new 

LNG import, storage, and regasification facilities with a sendout capacity of 1.0 Bcfd, 

constructed in association with an adjacent petrochemical complex and an electric cogeneration facility. The project received environmental approval by the Nova Scotia 

Environmental Minister on March 15, 2007 and a construction permit from the Nova 

Scotia Utility and Review Board in June 2008. However, Maple LNG has since 

suspended activity on the project and no work is ongoing.

• Commercial Fabrication Facilities – Passamaquoddy Tribal Government, Maine. The 

project would provide facilities for airplane parts refurbishment and assembly of prefabricated homes. The project appears to be on hold.

• M&NE Phase V Project – In April 2008, M&NE entered into the FERC pre-filing 

process for its planned Phase V Project, which would increase capacity on its system by 

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

months (FERC Docket Number PF08-17-000). The Phase V Project would provide 

additional capacity to transport new natural gas supplies from EnCana’s Deep Panuke 

project in Maritimes Canada, and was proposed to be in service in November 2010. 

However, on March 2, 2009, M&NE notified FERC that it would not proceed with the 

pre-filing process for the project.

• Pleasant Point/Western Passage Tidal Energy Project – Pleasant Point Passamaquoddy 

Indian Territory, Western Passage (Kendall Head and First Island). The project proposed 

by the Passamaquoddy Tribe (contractor, Distributed Generation Systems, Inc., and 

subcontractor UEK Corporation) would generate less than 5 kW of electric energy, 

allowing for local distribution to Eastport and Perry, Maine and the Tribe. The 

Passamaquoddy Tribe received a preliminary permit in November 2007 (P-12710) to test 

8-foot underwater turbines at Kendall Head and First Island, which was terminated on 

May 27, 2010 at the request of the Passamaquoddy Tribe.

Table 4.13-1 presents a summary of the expected cumulative impacts of the Downeast LNG 

Project and other identified LNG, natural gas pipeline, and industrial/commercial projects 

identified in the project area. The following is a brief analysis of the cumulative impacts on the 

resources resulting from the proposed Downeast LNG Project and the other projects listed in 

table 4.13-1.
4-373 4.13 – Cumulative Impacts

TABLE 4.13-1

Cumulative Impacts of the Downeast LNG Project and Other Projects in the Downeast Project Area

Project Land 

Disturbance

Marine 

Disturbance

Marine 

Transportation

Air

Quality Wetlands Surface Waterbodies

LNG

Safety

Downeast LNG Yes Yes Yes Yes Yes Yes Yes

Canaport LNG Yes Yes Yes Yes Yes Yes Yes

Deep Panuke Offshore Project Yes Yes Yes Yes IU IU Yes

M&NE Pipeline Baileyville to Westbrook Yes No No Yes Yes Yes No

M&NE Phase IV Yes No No Yes Yes Yes No

Tidewalker Tidal Energy Yes Yes Yes Yes No No No

Halcyon Pennamaquan Tidal Energy Yes Yes No No IU Yes No

Pleasant Point Tidal Energy Project IU Yes Yes Yes No No No

ORPC Western Passage Tidal Energy 

Project

No Yes Yes Yes No No No

ORPC Cobscook Bay Tidal Energy 

Project

No Yes Yes Yes No No No

Atlantic Salmon Aquaculture Facilities No Yes Yes No No No No

U.S. Route 1 Reconstruction Yes No No Yes IU IU No

Calais Border Crossing Yes No No Yes Yes Yes No

Port of Eastport Gateway Project Yes No Yes Yes No No No

Machias Area Airport Yes No No Yes Yes Yes No

Stetson Mountain Wind Project Yes No No Yes Yes Yes No

IU = Information unavailable

4.13.1 Water Resources

During construction of marine facilities associated with the Downeast LNG terminal, marine 

surface water quality would be affected primarily from turbidity. However, this impact would be 

localized and short term, occurring only in the immediate vicinity of the terminal facilities and 

during construction. Similar surface water impacts would likely occur during construction of the 

marine components of other projects listed in table 4.13-1. However, because the construction 

time periods and physical impact areas for these projects would not overlap, cumulative impact 

on surface water quality from turbidity during construction would be negligible.

During operation, passage of LNG vessels along the 16.6 nautical miles of waterway to the 

Downeast LNG terminal could potentially affect surface water quality. Based on available 

information, operation of those projects listed in table 4.13-1 could have cumulative effects to 

marine water quality as a result of additional marine traffic along the navigation channel, which 

would involve cooling water withdrawals and discharges, and installation of structures (ocean 

current generation modules) within the navigation channel. No degradation of water quality is 

expected during operation of these projects. Water withdrawals and discharges for vessel engine 

cooling could result in elevated water temperatures and impingement of marine organisms; 

however, these impacts along the navigation channel would be minor and temporary and would 

occur over a large area at varying times. In the project area, these impacts would be mitigated by 
4.13 – Cumulative Impacts 4-374

significant tidal fluctuations and high densities of zooplankton and ichthyoplankton, such that the 

overall impacts on marine organisms in the project area would have an inconsequential effect to 

overall community populations and associated fish stocks. 

The pipeline associated with the proposed Downeast LNG Project would require the crossing of 

waterbodies. Based on available information, some of the other projects included in table 4.13-1 

also involved waterbody crossings by pipelines or roads. However, we do not believe any of the 

other projects crossed the same waterbodies as the Downeast pipeline; therefore, there would be 

no cumulative impacts on specific waterbodies.

To minimize impacts on water resources, Downeast has agreed to follow the FERC staff’s

Wetland and Waterbody Construction and Mitigation Procedures. For the other facilities listed 

in table 4.13-1 in the United States, each proponent must comply with federal, state, and local 

permit requirements and crossing methods for each waterbody crossing. For those facilities in 

Canada, project proponents must follow Canadian regulations and procedures. Generally, 

impacts from construction of the pipelines and roads across surface waters would be short-term. 

No long-term or significant cumulative impacts on waterbodies crossed by the projects listed in 

table 4.13-1 would be expected following restoration.

4.13.2 Wetlands

At the proposed location of the Downeast pier, there are approximately 5.91 acres of subtidal 

wetlands and 0.7 acre of intertidal wetlands. Construction and operation of the marine facilities 

associated with the Downeast LNG terminal would permanently affect a portion of these tidal 

wetlands. The acreage of permanent impact on tidal wetlands of other projects included in 

table 4.13-1 is not known at this time. Downeast has attempted to minimize the area of 

permanent impact on tidal wetlands through the design and location of the permanent pier. In 

addition, Downeast would minimize and mitigate for its impacts on wetlands by implementing 

its Plan, Procedures, and Soil Erosion and Sediment Control Guidelines, as well as providing 

compensatory mitigation and wetland preservation to satisfy the terms and conditions of its COE 

Section 404 permit. It is expected that the other projects listed in table 4.13.1 have followed or 

will follow a similar approach to avoid, minimize, and mitigate for permanent impact on 

wetlands.

Construction of the pipeline component of the proposed Downeast LNG Project would 

temporarily affect wetlands. Most of this impact would be short-term, with disturbed areas 

allowed to revegetate following construction. Impact on forested wetlands within the new 

operational right-of-way would be long-term, as vegetation maintenance of the pipeline right-ofway would maintain previously forested wetlands in a herbaceous or scrub-shrub cover type. In 

evaluating alternatives for Downeast’s sendout pipeline, we conducted detailed evaluations of 

route alternatives and route variations. We examined route alternatives that could reduce or 

avoid impacts on environmentally sensitive resources and route variations that could avoid or 

reduce construction impacts on specific, localized resources such as particular wetland areas.

Based on available information, the other projects included in table 4.13-1 could also temporarily 

impact wetlands. In most instances, cumulative effects of the temporary wetland impacts would 

be minimal because of the limited temporal and spatial overlap between the projects. In 

addition, each project listed in table 4.13-1 would be required to examine alternatives that avoid 
4-375 4.13 – Cumulative Impacts

or reduce environmental impacts, including impacts to wetlands. For facilities in the United 

States, each of the project proponents is required to provide compensatory mitigation for 

unavoidable wetland impacts, as required by the terms and conditions of their respective COE 

Section 404 permits. For facilities in Canada, project proponents must follow Canadian 

regulations and procedures. Mitigation measures would be implemented to restore disturbed 

wetlands in accordance with other federal, state, and local permit requirements. 

4.13.3 Special Status Species

Consultation with the FWS and NOAA Fisheries identified a number of federal and/or state 

special status species that may be in the Downeast LNG Project area. The same special status 

species could occur in the project areas of the other projects listed in table 4.13-1. Lead agencies 

for federal projects would be required to consult with federal, state and local agencies to 

determine which species could occur within the project areas in order to evaluate potential 

impacts on those species and their habitats and to implement measures to avoid, minimize or 

mitigate the impacts. 

The Downeast LNG Project would incrementally add to impacts on ESA-listed whales and other 

marine mammals protected by the MMPA because of increased vessel traffic along the waterway 

for LNG marine traffic by as many as 60 vessels per year. The waterway currently sees about

120 vessels per year calling on the ports of Eastport, Maine and Bayside, New Brunswick. The 

other projects listed in table 4.13-1 may contribute to cumulative impacts on special status 

species. For example, the Port of Eastport Gateway project on Estes Head could increase traffic 

by cargo vessels and barges, and the tidal energy projects would add construction and 

maintenance vessels to the waterway. As a result of these projects, vessel traffic would be 

expected to increase; however, the potential increase is unknown at this time. 

Despite the potential for increased vessel traffic along the waterway, cumulative impacts on 

protected marine mammals would be mitigated through the vessel strike avoidance plan that each 

project would be required to implement. Downeast has developed such a plan that would 

encourage vessels under a charter party agreement to abide by procedures aimed at minimizing 

and avoiding contact with the whales and incorporate spatial and temporal exclusions pursuant to 

IMO and NOAA Fisheries guidance and regulations. We believe that with these agreements in 

effect, adequate mitigation of cumulative impacts on whales would be achieved.

Downeast has identified bald eagle habitat that could be affected by project construction or 

operation. The bald eagle receives protection under the Bald and Golden Eagle Protection Act, 

the MBTA, and the Lacey Act. Projects subject to NEPA review would conduct consultation 

with federal and state agencies to develop and then implement minimization, avoidance and 

mitigation plans to prevent adverse impacts on the bald eagle. We expect no significant 

cumulative impacts on this species.

4.13.4 Fisheries and Aquatic Resources

During construction of marine facilities associated with the Downeast LNG terminal, marine 

fisheries and aquatic resources would be affected from disturbance of bottom habitats, increased 

turbidity, and noise. Resources affected would include designated EFH. These impacts would 

be localized and short-term, occurring only in the immediate vicinity of the terminal facilities 
4.13 – Cumulative Impacts 4-376

and only during construction. Similar impacts would likely occur during construction of the 

marine components of other projects listed in table 4.13-1. However, because the construction 

time periods and physical impact areas for these projects are not expected to overlap, cumulative 

impacts on marine fisheries and aquatic organisms during construction of the projects would be 

insignificant.

In addition to the permanent impacts on bottom habitat from the Downeast LNG pier, including 

possibly on eelgrass from operation of LNG vessels arriving at the pier, based on available 

information operation of those projects listed in table 4.13-1 also would result in such permanent 

impacts. There also is a potential impact from the tidal energy projects to affect salmon farming 

along Western Passage. In addition, operation of the other listed projects with marine facilities 

potentially would have permanent impacts on marine fisheries and aquatic resources. Downeast 

has attempted to minimize the area of permanent impact on marine habitat through terminal 

siting and design. It is expected that the other projects listed in table 4.13-1 have followed a 

similar approach to avoid, minimize, and mitigate for permanent impact on marine habitats.

During operation, passage of LNG vessels along the 16.6 nautical miles of waterway to the 

Downeast LNG terminal could potentially affect fisheries and marine mammals, including injury 

or destruction from vessel strikes, noise harassment, reduced food supply from ichthyoplankton 

and zooplankton loss and entrainment of juvenile fish resulting from water withdrawals while the 

vessel is in transit and moored at the LNG terminal. Based on available information, during 

operation of the marine-related projects listed in table 4.13-1, cumulative effects to marine 

fisheries and mammals could result from the combination of the additional marine traffic and the 

construction and maintenance apparatus associated with the tidal energy projects and the ocean 

current generation modules in or close to the waterway. This would result in an increased 

potential for vessel strikes with whales or sea turtles. Increasing vessel traffic in the action area 

also raises concerns about the potential effects of noise pollution on marine mammals and sea 

turtles, which may result in auditory trauma, temporary or permanent loss of hearing sensitivity, 

habitat exclusion, habituation, and disruption of other normal behavior patterns such as feeding, 

migration, and communication. In locations with increased background noise conditions, due to 

cumulative vessel noise from increased vessel traffic, North Atlantic right whales have been 

shown to produce vocalizations at a lower rate and at a higher average frequency. Such 

behavioral changes may be correlated to potential masking effects from increased background 

noise (Parks et al. 2007). However, further study is needed to determine if such behavioral 

changes are a direct response to increased noise, and to determine any long-term effects on 

limiting reproduction and recovery of this species (Parks et al. 2007). 

4.13.5 Terrestrial Resources

Construction and operation of the proposed Downeast LNG Project would affect terrestrial 

vegetation and wildlife habitats. Based on available information, construction and operation of 

the other projects listed in table 4.13-1 would also affect terrestrial vegetation and wildlife 

habitats. If the projects listed in table 4.13-1 were to be constructed at or near the same time, the 

combination of construction activities could have a cumulative impact on vegetation and wildlife 

living in the immediate area. Clearing, grading, and other construction activities associated with 

the Downeast project, along with other area construction projects, could result in the removal of 

vegetation, alteration of wildlife habitat, displacement of wildlife, and other secondary effects 

such as increased population stress, disruption of predator-prey relationships, forest 
4-377 4.13 – Cumulative Impacts

fragmentation, and establishment of invasive plant species. The construction of multiple large 

industrial projects at or near the same time could result in a significant amount of land clearing 

activities, with a potential cumulative impact on forest resources in the immediate area of the 

projects. During construction activities, mobile species would be able to relocate to adjacent 

habitat and then reoccupy open project lands after those areas were restored. However, for most 

of the projects listed in table 4.13-1, the construction time periods and physical impact areas are 

not expected to overlap; therefore, cumulative impacts on terrestrial resources would not be 

significant. 

4.13.6 Air Quality and Noise

Construction of the proposed Downeast LNG Project would generate emissions from operation 

of heavy equipment and worker vehicles, and fugitive dust from ground-disturbing activities. 

Similar activities during construction of the other projects listed in table 4.13-1 would be 

expected to generate similar emissions. Cumulative air quality impacts would depend on the 

timing of construction of each project. However, for most of the projects listed in table 4.13-1, 

the construction time periods and physical impact areas are not expected to overlap; therefore, 

cumulative air quality impacts from project construction are not expected to be significant.

During operation, vessel emissions would be generated by the travel of the LNG import vessel, 

three or four tugs, and an unspecified number of escort vessels within the moving safety/security 

zone. Emissions in the fixed zone (with vessel moored) would be generated by the LNG import 

vessel, one standby tug, and one escort vessel. In addition, emissions would be generated from 

the SCVs, emergency generator, diesel fire pump, seawater fire pump, and emergency venting. 

To address the concerns of the public in the region, we requested that Downeast provide a 

cumulative air quality impact assessment, including existing and proposed emission sources in 

the region, and including evaluation of impacts on nearby Class I and Class II areas. The impact 

assessment was consistent with the guidelines published in the Federal Land Managers Air 

Quality Related Values Workgroup Report. The results are described in section 4.11.1.5. We 

also evaluated potential cumulative emissions with other emission sources in Washington 

County. Table 4.13.6-1 compares the criteria pollutant emissions in Washington County with the 

combined emissions attributable to Downeast operations (stationary and maritime sources). 

During operation, project emissions of NO2 would represent about 6.3 percent of the county

emissions. All other project emissions would represent an even smaller fraction of the 

Washington County emissions.

Noise produced during construction of the listed projects could create short-term annoyances to 

nearby residents, and could have short-term impacts on some aquatic species, nesting birds, and 

other wildlife in the area. Noise impacts during the construction phase would be localized and 

would attenuate quickly as the distance from the noise source increases. These impacts would be 

temporary and would only occur during the actual construction activities for the projects. In 

addition, the projects would be separated by enough distance that noise impacts from 

construction would not be cumulative.

TABLE 4.13.6-1

Comparison of Project Emissions with Washington County Emissions a/
4.13 – Cumulative Impacts 4-378

Pollutant

Terminal

Operations

(tpy)

Vessel

Activities

(tpy)

Total

(tpy)

Washington

County

(tpy)

Project

Fraction

Nitrogen Oxides 70.9 46 117 1,74 6.3%

Carbon Monoxide 50.3 16.6 66.9 2,04 3.2%

PM10 2.5 1.87 4.37 738 0.6%

PM2.5 2.5 1.57 4.07 702 0.6%

VOCs 16.7 2.14 18.8 542 3.4%

Sulfur Dioxide 1.4 5.35 6.75 588 1.1%

a/ Washington County emissions data from the 2002 dataset: the EPA National Emission Inventory.

During operation, the Downeast LNG terminal would generate noise. Estimated noise levels, 

and mitigations to ensure that noise levels are below acceptable limits, are described in section 

4.11.2.5 of this EIS. As with construction noise, the projects listed in table 4.13-1 would be 

separated by enough distance that noise impacts during operation would not be expected to be 

cumulative. In the marine environment, increased vessel traffic from the marine projects listed

in table 4.13-1 would result in increased ambient background underwater noise. These 

cumulative noise levels could cause auditory trauma, temporary or permanent loss of hearing 

sensitivity, habitat exclusion, habituation, and disruption of other normal behavior patterns, such 

as feeding, migration, and communication, to marine mammals and sea turtles. However, noise 

associated with the normal operation of additional vessels along the waterway would likely cause 

an insignificant incremental increase in noise impacts.

4.13.7 Climate Change

Climate change is the modification of climate over time, whether due to natural causes or as a 

result of human activities. Climate change cannot be represented by single annual events or 

individual anomalies. For example, a single large flood event or particularly hot summer is not 

an indication of climate change. However, unusually frequent or severe flooding, or several 

consecutive years of abnormally hot summers over a large region may be indicative of climate 

change.

GHG emissions from vessel activity and stationary sources associated with operation of the 

proposed project are estimated at 208,938 tons CO2e. 

The Intergovernmental Panel on Climate Change (IPCC) is the leading international, 

multigovernmental scientific body for the assessment of climate change. The United States is a 

member of the IPCC and participates in the IPCC working groups. The leading United States 

scientific body on climate change is the United States Global Change Research Program 

(USGCRP). Thirteen federal departments and agencies54 participate in the USGCRP, which 

began as a presidential initiative in 1989 and was mandated by Congress in the Global Change 

Research Act of 1990.

The USGCRP have recognized that:

 54 The USEPA, USDOE, Department of Commerce, Department of Defense, Department of Agriculture, 

Department of the Interior, Department of State, USDOT, Department of Health and Human Services, National 

Aeronautics and Space Administration, National Science Foundation, Smithsonian Institution, and Agency for 

International Development.
4-379 4.13 – Cumulative Impacts

• Globally, anthropogenic GHGs have been accumulating in the atmosphere since the 

beginning of the industrial era causing recent global warming;

• Combustion of fossil fuels (coal, petroleum, and natural gas), combined with agriculture 

and clearing of forests is primarily responsible for the accumulation of GHG;

• The anthropogenic GHG emissions are the primary contributing factor to recent climate 

change; and

• Impacts extend beyond atmospheric climate change alone, and include changes to water 

resources, transportation, agriculture, ecosystems, and human health.

The USGCRP issued its Second National Climate Assessment (NCA) titled, Global Climate 

Change Impacts in the United States, in 2009 summarizing the impacts climate change has 

already had on the United States and what projected impacts climate change may have in the 

future. The report includes a breakdown of overall impacts by resource and impacts described 

for various regions of the United States. The Third NCA is currently in draft form and is 

scheduled for issuance in early 2014. 

Climate change has modified the environment in the area around the proposed project and is 

projected to cause additional changes to the project area. The Second and draft Third NCAs 

identifies climate change impacts that have occurred along coastal regions in the continental 

Northeast and Canadian Maritimes. Previous impacts on historical baseline climate and as well 

as projected climate change impacts that could affect the project area are identified below:

• Average temperatures have risen about 2° F since 1970 and are projected to increase 

another 2 to 4°F during this century;

• Winters in the Northeast are projected to be much shorter with fewer cold days and more 

precipitation with the length of the winter snow season would be cut in half;

• Cities that today experience few days above 100°F each summer would average 20 such 

days per summer;

• Short-term (one- to three-month) droughts are projected to occur as frequently as once 

each summer;

• Hot summer conditions would arrive three weeks earlier and last three weeks longer into 

the fall;

• Agricultural production, including dairy, fruit, and maple syrup, are likely to be adversely 

affected as favorable climates shift;

• The oceans are currently absorbing about a quarter of the CO2 emitted to the atmosphere 

annually and are becoming more acidic as a result, leading to concerns about potential 

impacts on marine ecosystems;

• Increasing risk from sea-level rise and storm surge;

• Coastal waters have risen about 2°F in several regions and are likely to continue to arm 

as much as 4 to 8°F this century with concomitant impacts on fisheries;
4.13 – Cumulative Impacts 4-380

• Infrastructure will be increasingly compromised by climate-related hazards, including sea 

level rise and coastal flooding, and intense precipitation events; and

• Coastal water warming may lead to the transport of invasive species through BWE during 

ship transit.

As identified in section 4.11.1, the project would be required to obtain a Title V Part 70 

operating permit to limit emissions of GHG from the Projects. Although the Project emissions 

would contribute to the overall amount of atmospheric GHG, it is impossible to quantify the 

impacts that the emissions of GHG from construction and operation of the Project would have on 

climate change. 

4.13.8 Cultural Resources 

Downeast continues to consult with the SHPO and Passamaquoddy Tribe regarding potential 

project impacts on cultural resources, traditional cultural properties, and religious interests of the 

Passamaquoddy Tribe, including possible impacts of LNG marine traffic on traditional waters 

and fisheries. We have recommended in section 4.10.4 of this EIS that Downeast complete such 

consultations prior to construction, so that the FERC and other cooperating agencies would be in 

compliance with the NHPA. In addition, the Coast Guard’s WSR recommends written 

verification that the Passamaquoddy Nation is satisfied with the resolution of its concerns about 

tribal resources in the waterway and the associated safety and security interests. Because no 

historic properties have been identified to date that would be adversely effected by Downeast’s 

proposal, that project would not be adding incrementally to cumulative regional impacts on 

cultural resources which are listed or eligible for listing on the NRHP.

Non-federal actions would need to comply with any mitigation measures required by the state of 

Maine. Any other projects with a federal nexus would have to adhere to section 106 of the 

NHPA, and follow the regulatory requirements of 36 CFR 800. Under those regulations, the lead 

federal agency, in consultation with the SHPO, would have to identify historic properties in the 

APE, assess potential project effects, and resolve adverse effects through an agreement document 

that outlines a treatment plan. The NHPA and its implementing regulations ensure that projects 

that require a federal permit, license, or approval would not have significant cumulative impacts 

on historic properties.

4.13.9 Socioeconomics and Environmental Justice

During construction, the other projects listed in table 4.13-1 could compete with the Downeast 

LNG Project for construction resources (labor, local services, equipment, and materials), if they 

were under construction concurrently. Several of the projects in Washington County are 

dissimilar in nature from the proposed Downeast LNG Project and most have already been 

constructed. Therefore, significant cumulative impacts on construction resources are unlikely.

Based on available information, operation of the projects listed in table 4.13-1 that involve 

marine transportation could have cumulative impacts on commercial fishing in the area as a 

result of the increased marine traffic. The Downeast LNG Project would result in an estimated 

60 LNG vessel calls per year. LNG vessels would follow a circuitous route through both United 

States and Canadian waters, virtually the same route as currently used by all deep-draft vessels 

servicing Passamaquoddy Bay port areas, including the ports of Bayside, New Brunswick, and 
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Eastport, Maine. These ports receive on average an estimated 120 deep-draft vessel arrivals per 

year. If the Downeast LNG Project was built, the associated LNG vessel traffic would result in 

roughly a 50 percent increase in anticipated deep-draft vessel traffic. The Coast Guardrecommended safety and security zones around LNG vessels during passage through Head 

Harbour Passage, Western Passage, and Passamaquoddy Bay would be in place for each of the 

LNG vessel trips. Coordination with the Coast Guard and other waterway and port authorities in 

the area, and advance notice of the arrival and departure of LNG vessels, along with the 

implementation of vessel traffic management practices recommended by the Coast Guard’s 

WSR, would reduce impacts on other marine traffic, both commercial and recreational. 

Downeast has also developed a Fishermen’s Communication, Coordination, and Compensation 

Plan to reduce any impacts on commercial fishing. It is expected that the other marine projects 

listed in table 4.13-1 would strive to avoid, minimize, or mitigate for impacts on commercial 

fisheries.

If other construction or pipeline projects were to occur during the construction phase of the 

Downeast LNG Project, tight labor markets could result, which in turn could lead to more nonlocal workers entering the local labor force for the duration of the construction. Given declining 

populations in recent years and the available capacity in local housing and schools, this could 

provide a beneficial cumulative impact on the local economy, with insignificant cumulative 

adverse impacts.

4.13.10 Land Use, Recreation, and Visual Resources

Construction and operation of the Downeast LNG Project would result in temporary and 

permanent changes in land use. The other projects listed in table 4.13-1 could also result in 

similar types of impacts on land uses. The total acreage permanently converted to industrial land 

use as a result of construction and operation of the projects listed in table 4.13-1 is not known. 

This conversion to industrial use would have a minor cumulative impact on land use in the 

region.

Recreational activities, including fishing and boating, occur along the shores of Passamaquoddy 

Bay and within its waters. The projects listed in table 4.13-1 could have a cumulative negative 

impact on these recreational activities, primarily during the period of active construction of 

terminals and offshore facilities. The cumulative impacts on recreation from construction 

activities would be short-term and would not be significant.

When operational, Downeast expects to receive about 60 LNG vessels annually. In addition, the 

Port of Eastport is proposing expanded facilities that could result in an increase in shipping 

traffic. In addition, repair and maintenance of the tidal energy projects close to or within the 

waterway would infrequently add barges and other maintenance apparatus (e.g., underwater 

remote-operated vehicles) to the waterway. Nevertheless, the cumulative impacts on recreational 

fishing and boating from the projects in the area would be insignificant. A limited number of 

small crafts use the vessel channel where marine traffic would be concentrated, and they would 

receive advance notice of an LNG vessel transit through established broadcasts to mariners. The 

safety and security zones, and other vessel traffic practices, recommended by the WSR may limit 

recreational and other boat traffic in the vicinity of LNG vessels. However, recreational fishing 

is very limited in Passamaquoddy Bay, most likely because of the large extent of the intertidal 

area exposed at low-water and the strong tidal currents.
4.13 – Cumulative Impacts 4-382

Land use and recreational activities could also be affected by the security zones established 

around the Downeast LNG terminal, trestle, and berthing pier. The exact area of prohibited 

activities near the project has not yet been determined. It would be included by Downeast in its

Operations and Emergency Manual and Facility Security Plan, which are required by federal law 

and must be submitted to the COTP Sector Northern New England for review and approval at 

least six months before the terminal is operational. While the exact security zone has not been 

established, it should not be a significant impact based on the limited land use and recreational 

activity near the terminal site.

The Downeast LNG Project and other projects listed in table 4.13-1 would have some visual 

impact on the immediate surroundings. Downeast has incorporated design specifications 

(described in section 4.7.4 of this EIS) to minimize the visual impact of its facilities. The area 

already has vessel traffic through the nearby waters, and the addition of up to about 60 vessels 

per year would not be a significant visual impact. Depending on the final lighting designs for the 

proposed Downeast LNG terminal, there could be increased outdoor lighting on the night sky. 

This should be minimized by the type and amount of lighting utilized and approved by the COTP 

Northern New England in the approval of the Facility Security Plan. Overall, the cumulative 

visual impacts of the Downeast LNG and other projects would not be significant. For the 

sendout pipeline, the construction area would be restored to pre-construction contours, as nearly 

as possible, and revegetated. There would be a permanent visual impact along the pipeline 

rights-of-way in the areas where forest land is cleared and the permanent rights-of-way are 

maintained in an herbaceous state. However, once revegetation is complete, these alterations of 

the landscape would be insignificant with the exception of forested areas, which would be 

maintained as non-forest vegetation on the permanent operational rights-of-way.

4.13.11 Safety

We have received comments regarding the cumulative safety impacts of the LNG and pipeline 

projects listed in table 4.13-1. These safety issues concern potential release of LNG from the 

terminals and/or LNG vessels, security along the LNG vessel transit routes, and potential 

pipeline accidents along the sendout pipeline route. Since issuance of the draft EIS, the Quoddy 

Bay, Calais, and Maple LNG Projects are no longer proposed; therefore, they were removed 

from the cumulative impacts analysis. The existing Canaport LNG Project is approximately 

60 miles from the proposed Downeast LNG terminal site. Given the distance between project 

facilities, there would be no overlap of the areas that could be affected by a potential accident.

Impacts from an accidental release of LNG from the Downeast LNG terminal and/or LNG 

vessels are discussed in detail in section 4.12 and are related to vapor dispersion and thermal 

radiation. As discussed in section 4.12, research conducted by Sandia and the subsequent report 

entitled Guidance on Risk Analysis and Safety Implications of a Large Liquefied Natural Gas 

(LNG) Spill over Water have provided guidance to the Coast Guard relative to the impacts of an 

LNG spill. The Coast Guard used the criteria developed by Sandia (Sandia 2004) to define the 

outer limits of the hazard zones, referred to as Zones of Concern, for assessing potential risks.

As discussed above, the Coast Guard’s WSR recommends vessel traffic operating practices, 

which includes safety and security zones around LNG vessels transiting to and from the LNG

terminal and vessel speed restrictions, among other parameters. This may limit recreational and 

commercial traffic within the vicinity of the LNG vessels during transit. 
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Pipeline safety is discussed in detail in section 4.12 using existing pipeline operational data. The 

available data shows that natural gas pipeline continues to be a safe, reliable means of energy 

transportation and, therefore, there would be no adverse cumulative safety impacts from the 

proposed pipeline facilities for the projects listed in table 4.13-1. 

4.13.12 Indirect Impacts

Commenters have asked that we discuss the foreseeable indirect consequences to the 

environment resulting from the proposed Downeast LNG Project. According to 40 CFR 

1508.8(b), indirect effects are caused by the action and are later in time or farther removed in 

distance, but are still reasonably foreseeable. We have assumed that the commenters are 

concerned that authorization of the project could be the initial step in widespread development of 

industrial and commercial structures or facilities in Washington County, Maine. To assess the 

potential for this to occur, we evaluated four potential factors that could lead to such 

development: secondary economic activity, economic clustering (or agglomeration), precedent, 

and entrepreneurial innovation.

Secondary Economic Activity

Secondary economic activity is associated with the re-spending of project-related dollars. This 

includes indirect effects (changes in sales, income, or employment within backward-linked 

industries that supply firms participating directly in a project) and induced effects (increased 

sales from households spending income earned via a project). An example might include 

increased demand for security officers associated with the LNG terminal.

If implementation of the proposed Downeast LNG Project resulted in a substantial amount of 

secondary economic activity, it could indicate the potential for industrialization. As reported in 

section 4.8, some additional jobs may result from secondary activities associated with 

construction and the purchases made by non-local workers for food, clothing, gasoline, and 

entertainment. This secondary job creation would likely be limited, but beneficial. Using 

assumptions that maximize potential secondary activity, a total average of 569 jobs, with a peak 

of about 650 jobs, could be associated with secondary economic activity during the construction 

period. Downeast also estimated that approximately 320 pipeline workers would be required 

during a nine-month pipeline construction period. The Downeast LNG terminal operations 

would support a total of 187 jobs in Washington County over the terminal’s lifecycle. Given the 

short-term increase in jobs during the construction phase and the limited number of permanent 

jobs expected during operation, the minimal level of secondary income and employment impacts, 

although beneficial, does not indicate a significant potential for industrialization. 

Economic Clustering

Economic clustering (often termed “economic agglomeration”) occurs when industries and 

businesses achieve cost savings by locating in proximity to one another or to essential 

infrastructure. For example, shipping and packaging facilities may cluster near ports because 

reduced transportation costs impart competitive advantage. A study conducted by the University 

of Maine found that terminal construction would support an estimated 375 jobs in Washington 

County in each year of the construction project. These workers would receive an estimated 

$15.3 million in income per year. An impact of 375 new jobs would be equivalent to 

2.67 percent of total employment in Washington County as of 2000. The study used an 
4.13 – Cumulative Impacts 4-384

employment multiplier of 2.04, meaning that each Washington County worker employed on the 

construction project would support an additional 1.04 workers within the county. However, it 

should be noted that the U.S. Bureau of Economic Analysis calculated an employment multiplier 

of 1.44 for Washington County, which would result in a smaller number of indirect jobs and 

lesser amounts of secondary income than predicted by the University of Maine study. By either 

calculation, the creation of secondary jobs and income, while beneficial to the County, would not 

be sufficient to create a significant agglomeration of businesses in proximity to the LNG terminal 

or to one another. 

Construction of the Downeast LNG Project is not likely to cause an adjacent industrial build-up. 

The project would facilitate supply of natural gas to the region. It is not proposing to be a local 

industrial distributor of natural gas. Heavy industry would not have any supply incentive to 

collocate near the Downeast LNG terminal; thus, there would be no economic clustering of 

heavy industry adjacent to the terminal. 

Precedent

There are existing industrial and commercial uses in and around Passamoquody Bay and 

Washington County, including commercial fishing, tourism, salmon aquaculture, tidal energy, 

and commercial ports. Approval of the Downeast LNG Project would result in another 

industrial/commercial use of the Bay. The Downeast LNG Project would not set a precedent for 

industrial/commercial use in the area.

Entrepreneurial Innovation

The process of permitting, constructing, and operating the proposed project could spur others to 

identify or invent potential commercial/industrial applications that would derive cost benefits by 

being located in the area. By definition, innovation and the motivation behind it is difficult to 

predict. However, it is reasonable to assume that construction and operation of the proposed 

project could lead to innovations, and it is possible that an entrepreneur could be spurred to 

identify a new industrial application that could be appropriate for Washington County. If that 

were to occur, the new application would still require review by the appropriate federal, state, 

and/or local agencies to determine whether the project is consistent with environmental and other 

regulatory requirements. Projects that do not meet regulatory requirements would not receive 

permits from the reviewing agencies.

Summary

As discussed above, secondary economic activity associated with the Downeast LNG Project 

would be minor and would not be sufficient to stimulate additional industrial growth. With 

respect to economic clustering, we were unable to identify situations where the creation of

secondary jobs and income would be sufficient to result in the establishment of a cluster of 

businesses near the proposed project. The Downeast LNG Project would not set a precedent for 

industrial/commercial use in the area. Although we recognize that the project could spur 

entrepreneurial innovation, any new development in the area would face the same regulatory 

review as the project to determine impacts and viability. 
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4.13.13 Conclusions About Cumulative Impacts

A determination of significance of the cumulative impacts for a specific resource is problematic 

because well-defined threshold values are typically undetermined. However, the majority of 

impacts we have identified for the proposed Downeast LNG Project would be temporary and 

minor. Consequently, their addition to other reasonably foreseeable impacts in the region does 

not result in a significant increase in permanent impacts.

There would be several notable permanent impacts, however. The permanent conversion of 

forest land communities to an herbaceous community along the proposed sendout pipeline in

combination with other past, present, or reasonably foreseeable future projects, could potentially 

fragment some wildlife habitat. Additionally, the Downeast LNG Project, together with the 

other projects in the area, would contribute to increased vessel traffic along the vessel channel. 

Although the Downeast LNG Project and other projects would result in the degradation of some 

wetland habitats, compensatory mitigation programs for each of these projects would be 

designed to provide a net benefit to the ecosystem.

As many of the project stakeholders and community residents have noted, the Downeast LNG 

Project, together with the other projects in the area, would cumulatively benefit the local 

economy through job creation and wages, tax revenues, and by providing a new source of 

competitively priced natural gas. A further effect would be a small increase in the area’s 

population. Adverse indirect impacts would be insignificant.