2-1 2.0 – Description of the Proposed Action 

2.0 DESCRIPTION OF THE PROPOSED ACTION 

The proposed action consists of the activities outlined by Jordan Cove and Pacific Connector in 

their applications to the FERC. The proposed facilities are more fully described in section 2.1 

below. 

The FERC and the cooperating agencies each have their own actions related to the review and 

approval of the Project. The FERC is the federal agency responsible for authorizing applications 

to construct and operate onshore LNG terminals and interstate natural gas transmission facilities, 

and is the lead federal agency for compliance with the NEPA. The COE is responsible for 

issuing dredging and wetland permits for the Project. The Coast Guard is responsible for 

determining the suitability of the waterway for LNG marine traffic. The BLM, BOR, and USFS 

must grant a right-of-way for the pipeline across federal lands under their management. The 

FWS will review the Project for compliance with the MBTA and will consult on species and 

habitats protected by the ESA. The EPA has the authority to review and veto COE decisions on 

Section 404 permits, and will review the EIS for compliance with the CAA and the NEPA. The 

DOT is responsible for pipeline safety. The Douglas County Land Department has an interest in 

land use compatibility, the crossing of county lands by the pipeline, and representing the interests 

of private landowners affected by the Pacific Connector pipeline in Douglas County. 

All of the cooperating agencies agree that the action to be studied in this EIS consists of Jordan 

Cove’s proposal to construct and operate an LNG import terminal at Coos Bay, the Port’s 

proposal to construct an access channel and slip for the LNG terminal, and Pacific Connector’s 

proposal to construct and operate a 234-mile-long natural gas sendout pipeline and associated 

facilities that would connect the LNG terminal with existing interstate and local distribution 

pipeline systems. In addition, the EIS addresses the potential environmental impacts related to 

LNG marine traffic in the waterway from the outer limit of the United States territorial sea (12 

nautical miles off shore) to the proposed LNG terminal location, including portions of the 

shoreline within the “Zones of Concern”1, and for species listed under the ESA to the limits of 

the Exclusive Economic Zone (EEZ) 200 nautical miles off shore. 

This EIS addresses facilities to be constructed and operated by companies that do not come 

under the jurisdiction of the FERC, but are related to the JCE & PCGP Project. The nonjurisdictional facilities include the NGL storage and sendout facilities, the facilities to be 

constructed and operated by Avista to handle the natural gas it receives from Pacific Connector, 

the interconnection facilities to be built and operated by PG&E, and various utility services to 

aboveground facilities along the Pacific Connector pipeline. 

2.1 PROJECT COMPONENTS 

Figure 1-1 illustrates the general location of the Project. The main Project components consist of 

the waterway for LNG marine traffic, the LNG import terminal and associated facilities to be 

constructed by the Port and Jordan Cove, and the pipeline and ancillary facilities to be 

constructed by Pacific Connector. Section 4 of this EIS addresses specific environmental 

 

1

 The “Zones of Concern” are described in Enclosure 11 of the Coast Guard’s NVIC 05-05. These zones are based on the report 

Guidance on Risk Analysis and Safety Implications of a Large Liquefied Natural Gas (LNG) Spill Over Water, December 2004 

(SAND2004-6258) prepared by the U.S. Department of Energy’s Sandia National Laboratories (Sandia Report). The Zones of 

Concern are more fully discussed in section 4.12 of this EIS. 
2-2 2.0 – Description of the Proposed Action 

resources that may be potentially impacted by construction and operation of the proposed 

facilities. 

2.1.1 Waterway for LNG Marine Traffic 

The Coast Guard defines the waterway for LNG marine traffic for this Project as extending from 

the outer limits of the United States territorial waters, 12 nautical miles off the coast of Oregon, 

and 7.5 nautical miles up the Coos Bay navigation channel to the proposed location of the Jordan 

Cove LNG import terminal (see figure 2.1-1). For the analysis in this EIS and the corresponding 

BA and EFH Assessment specific to species covered by the ESA and MSA, we considered 

impacts from LNG marine traffic extending out to the EEZ. 

2.1.2 Waterway Characteristics 

The federally maintained Coos Bay navigation channel extends from the mouth of Coos Bay to 

the City of Coos Bay Docks at about Channel Mile (CM) 15.1 (figure 2.1-2). The existing 

entrance to the bay is between two jetties, about 2,100 feet apart that extend about 3,000 feet 

from the shore. 

There is usually a southerly current during the summer months off the entrance jetties and a 

northerly current in the winter after strong southerly winds. The tidal range for Coos Bay is 

about 7 feet for mean spring range and about 3 feet for mean neap range. 

The channel width at the entrance mark is 1,500 feet, reducing to 700 feet at CM 0 and 300 feet 

to CM 1. From CM 1 to the proposed LNG terminal the authorized channel width is 300 feet. 

At the entrance, the water is 47 feet deep. But for the remainder of the navigation channel the 

minimum depth maintained by the COE is 37 feet mean lower low water (MLLW). 

2.1.2.1 Natural Hazards in the Waterway 

There is a bar in the Entrance Range with a depth of 37 feet, which establishes the minimum 

depth of the channel. The most favorable time for crossing the bar is on the last of the flood tide, 

and under certain conditions it is passable only at this time (a large ground swell, deep draft, 

storm conditions, or a combination of any of these). 

2.1.2.2 Human-Created Obstructions in the Waterway 

There are no bridges or overhead powerlines that cross the Coos Bay navigation channel between 

the channel entrance and the proposed LNG terminal. 
2.0 – Descr

2-3

Figure 2.1-1 Proposed LNG Carrier Transit Route 
2.0 – Descr

2-4

Figure 2.1-2 Coos Bay Navigation Channel and Other Features in the Vicinity of Proposed LNG Termin
2-5 2.0 – Description of the Proposed Action 

2.1.2.3 Aids to Navigation in the Waterway 

The COE maintains two rock jetties (south and north) at the entrance to the Coos Bay navigation 

channel. LNG carriers in route to the proposed LNG terminal site would navigate a series of five 

different legs along the Coos Bay navigation channel. Each leg is marked with marker buoys 

that have reciprocal or near reciprocal pairs of leading lights. The LNG terminal would be 

located on the north side of bay at the confluence of the Jarvis Turn leg and the Upper Jarvis 

Range leg. 

Based on Jordan Cove’s March 2008 Ship Simulation Study, the Coast Guard is requiring, in its 

WSR issued July 1, 2008, that before LNG carriers can enter the waterway four new aids to 

navigation must be added to the channel, and eight other existing aids to navigation must be 

relocated. In addition, a Physical Oceanographic Real-Time System (PORTS) must be 

contracted with NOAA to provide real time channel level, current, and weather data. 

2.1.2.4 Docks along the Waterway 

There are four existing recreational docks, one marina, and five commercial docks that are within 

the Zones of Concern along the waterway for LNG marine traffic. These berthing sites include: 

• Charleston Marina – at CM 2, on the south side of the bay at the community of 

Charleston, is a marina owned by the Port that is home to approximately 500 vessels 

including commercial fishing vessels, Coast Guard inspected and uninspected passenger 

vessels, and recreational vessels; 

• Cape Arago Dock – at CM 5.4, on the east side of the bay at the community of Empire, is 

a private facility operated by the Sause Brothers, with water depth about 20 feet, and one 

berth up with a 500-foot-long dock; 

• D. B. Western, Inc. – at CM 5.6, on the west side of the bay along the North Spit, is 

private facility, with water depth about 20 feet, and one berth with a 140-foot-long wharf; 

• North Bay Marine Industrial Park – at CM 5.7, on the west side of the bay along the 

North Spit, is owned by the Port, but currently not developed; 

• Empire Ramp – at CM 6, on the east side of the bay, owned by the City of North Bend, 

with a public dock and no slips; 

• Southport Lumber Company – at CM 6.3, on the west side of the bay along the North 

Spit, is private facility with water depth about 5 feet, able to take shallow barge traffic 

only; 

• BLM North Spit Dock – at CM 7, on the west side of the bay along the North Spit is a 

public dock with no slips; 

• Roseburg Forest Products Chip Terminal – at CM 7.9, on the west side of the bay along 

the North Spit, with water depth about 38 feet, and one berth with a 260-foot-long wharf; 

and 

• Pony Point Boat Ramp – at CM 9, on the east side of the bay, at the mouth of Pony 

Slough, is blocked from public access because of its location within the boundaries for 

the North Bend Airport. 

Marine traffic to and from those docks is discussed in more detail in sections 4.8.1, 4.9.1, and 

4.12.5.5 of this EIS. Recreational use of the public docks is discussed in section 4.7.1. 
2-6 2.0 – Description of the Proposed Action 

2.1.2.5 Current Marine Traffic on the Waterway 

The Port of Coos Bay includes six marine terminals with seven deep-draft berths and a variety of 

barge facilities. Existing commercial traffic along the Coos Bay navigation channel to and from 

these facilities includes large cargo ships primarily exporting wood chips. Commercial deepdraft cargo traffic has declined from about 300 ships per year 20 years ago to less than 50 today, 

and the Port expects it to remain at this level (ECONorthwest 2006). 

About 71 commercial fishing vessels called Coos Bay their home port in 2006 (ODFW 2007). A 

2005 study by the Oregon State Marine Board counted 30,996 boat trips annually in Coos Bay. 

About 88 percent of these boat trips involved fishing. Sections 4.9.1 and 4.12.5.5 of this EIS 

discusses potential Project-related impacts on marine traffic in Coos Bay. Recreation boating 

and fishing is discussed further in section 4.7.1. 

2.1.2.6 Safety Measures Currently in Place for Existing Vessel Traffic 

All large commercial vessels moving up and down the Coos Bay navigation channel must be 

accompanied by a licensed pilot. Pilotage service is provided by the Coos Bay Pilots Association. 

The Coast Guard WSR requires that a pilot must board a LNG carrier heading to the Jordan Cove 

terminal at least 5 miles outside the sea buoy. Jordan Cove must provide simulator training for all 

pilots and tug operators prior to commencing operations at the LNG terminal. 

2.1.2.7 Population Adjacent to the Waterway 

The Zones of Concern along the waterway for LNG marine traffic to the Jordan Cove terminal 

would overlap the communities of Charleston, Barview, Empire, and the cities of North Bend 

and Coos Bay. Population density within the Zones of Concern is shown on figure 4.8-1. 

Combined, the unincorporated communities of Charleston and Barview were estimated to have a 

total population of 6,000 people in 2005 (South Slough NERR 2006). The neighborhood of 

Empire has been absorbed into the city of Coos Bay, which had a population of 16,210 people in 

2007, while the city of North Bend had a population of 9,830 people (Proehl 2008). A more 

detailed discussion of population along the waterway is included in section 4.8.1. 

2.1.2.8 Coast Guard Review of Waterway Suitability for LNG Marine Traffic 

The Coast Guard is responsible for issuing an LOR regarding the suitability of the waterway for 

LNG marine traffic. Jordan Cove produced a WSA that was submitted to the Coast Guard for 

review. During the validation process, the Coast Guard consulted with a variety of stakeholders, 

including state and local emergency responders, marine pilots, towing industry representatives, 

members of the Port Waterway Safety Committee, and the Area Maritime Security Committee. 

The Coast Guard designated the WSA as Sensitive Security Information (SSI) as defined in 49 

CFR 1520. Because any unauthorized disclosure of these details could be employed to 

circumvent the proposed security measures, they are not releasable to the public, and the WSA is 

not a part of the FERC public record in this proceeding. 

Following the guidance in NVIC 05-05, the Coast Guard completed its review of the WSA, and 

issued a WSR on July 1, 2008. A copy of the public portion of the WSR is attached to this EIS 

as Appendix B. The Coast Guard found the Coos Bay navigation channel is currently not 

suitable for LNG marine traffic, but could be made suitable if a number of conditions were met. 

The WSR identifies additional risk mitigation measures (RMM) that would be required to 
2-7 2.0 – Description of the Proposed Action 

responsibly manage navigation, safety, and security risks in order to make the Coos Bay 

navigation channel suitable for LNG marine traffic. Some of these RMMs include: 

• development of a Transit Management Plan; 

• restriction of LNG carriers to daylight transit during at least the first 6 months, unless 

approved in advance by the COTP Portland; 

• installment of an Automatic Information System (AIS) receiver and camera systems for 

use by the Coast Guard; 

• escorting of two tractor tugs for the entire transit of the Coos Bay navigation channel, 

with another tug assisting with docking at the terminal; 

• installment of additional aids to navigation; and 

• establishment of a moving safety and security zone for 500 yards around LNG carriers in 

transit in the waterway, and a 150-yard security zone to be established around an LNG 

carrier berthed at the terminal. 

The WSR is discussed in more detail in section 4.12.5 of this EIS. 

2.1.3 LNG Carriers 

There are currently 15 LNG exporting nations, which combined possess about 33 percent of the 

world’s natural gas reserves. According to the FERC’s regulations for applications under section 

3 of the NGA, Jordan Cove is not required to reveal market data about its LNG import terminal. 

Jordan Cove indicated that it may receive shipments from LNG exporting countries around the 

Pacific Rim. However, it has not provided specific details about the exact sources of its LNG 

and the oversea routes of the LNG carriers to the import terminal. 

Because we do not know the point of origin of the LNG shipments, we cannot discuss any details 

about the trans-oceanic voyages of the LNG carriers on their way to the Jordan Cove LNG 

import terminal. Nor has Jordan Cove provided details about the exact type and size of LNG 

carriers that would call at its proposed import terminal. 

The berth at the proposed Jordan Cove terminal could handle LNG carriers up to 217,000 cubic 

meters (m3) in capacity2. In its application to the FERC, Jordan Cove proposed to receive LNG 

carriers with capacities up to 160,000 m3. However, in March 2008, Jordan Cove had a 

consultant conduct an LNG carrier transit and maneuvering simulation study, with a 

representative of the Coos Bay Pilots Association, using simulator services provided by Marine 

Safety International in Middletown, Rhode Island, assisted by Towing Solutions of Spring Hill, 

Florida, to provide tug support simulations. The study indicated that LNG carriers up to 148,000 

m3

 in capacity could safely navigate to and from the proposed Jordan Cove LNG terminal using 

the existing Coos Bay navigation channel, with the benefit of high water conditions. Based on 

this study, the Coast Guard’s WSR, provided to the FERC on July 1, 2008, restricted the size of 

LNG carriers that can use the Jordan Cove import terminal to not more than 148,000 m3 in 

capacity (see Appendix B). 

As part of the waterway suitability review process, the Coast Guard used criteria developed by 

the Sandia National Laboratories (Sandia) in 2004 to define the outer limits of the hazard zones 

 

2

 In a February 20, 2009 filing with the FERC, Jordan Cove clarified that it used a 138,000 m3 capacity Moss Spherical LNG 

carrier as the model for the design of the slip and berth. The slip geometry necessary to dock a 138,000 m3 capacity LNG carrier 

can also physically accommodate LNG carriers up to 217,000 m3 in capacity (such as the Q-Flex class ships). 
2-8 2.0 – Description of the Proposed Action 

for assessing potential risks associated with the proposal. The 2004 Sandia report calculated the 

extent of the Zones of Concern based on LNG carriers with capacities ranging from 125,000 m3

to 150,000 m3. The proposed action evaluated in this EIS, and upon which the Coast Guard 

would base its LOR, assumes that LNG carriers berthing at the Jordan Cove import terminal 

would have capacities no greater than 148,000 m3. Therefore, we discuss potential Project 

impacts within the Zones on Concern along the waterway for LNG marine traffic related to the 

transit of LNG carriers up to 148,000 m3

 in capacity as formulated from the 2004 Sandia report. 

Local commercial pilots would guide LNG carriers during their voyage in the Coos Bay 

navigation channel. The LNG carriers would proceed up the waterway to the LNG terminal at 

speeds between 4 and 10 knots. As required by the WSR, two tugs would escort each LNG 

carrier within the Coos Bay navigation channel, and another tug would assist in docking the 

carriers at the Jordan Cove terminal. These tractor tugs must be at least 80-ton bollard pull tugs 

or larger. 

The narrative below is general in nature, describing typical attributes of LNG carriers. 

Additional information on LNG carrier regulations and safety measures is presented in section 

4.12.5 of this EIS. 

Vessels that transport LNG are specially designed to carry cold liquids for long distances. LNG 

carriers combine features of conventional vessel design with specialized materials and systems 

that can safely contain super-cooled liquids. In 2006 there were approximately 218 LNG carriers 

operating world-wide, ranging in capacity from 1,100 m3 to 154,000 m3 (LNG Express 2007). 

Jordan Cove’s Ship Simulation Study modeled its LNG carrier dimensions at 950 feet long, 150 

feet at the beam, with a loaded draft of 40 feet deep, and a capacity of 148,000 m3. The largest 

LNG carriers that are currently under construction would be about 217,000 m3 in capacity with a 

similar draft. Figures 2.1-3 and 2.1-4 illustrate typical LNG carriers. 

2.1.3.1 Profile 

LNG carriers have a distinctive appearance compared with other transport vessels. An LNG 

carrier has a high freeboard (i.e., that portion of the vessel above water) when compared with 

vessels such as an oil tanker because of the comparatively low density of the cargo. Because of 

the high freeboard, wind velocity can adversely affect the maneuverability of the vessel, 

particularly at slow speed, such as during docking. 

2.1.3.2 Hull System 

All LNG carriers are constructed with double hulls, which increases the structural integrity of the 

hull system and provides protection for the cargo tanks in case of an accident. The space 

between the inner and outer hulls is used for water ballast. The segregated ballast tanks prevent 

ballast water from mixing with any residue in the cargo tanks. The International Maritime 

Organization’s (IMO) Code for the Construction and Equipment of Ships Carrying Liquefied 

Gases in Bulk and Coast Guard regulations require that LNG carriers meet a Type IIG standard 

of subdivision, damage stability, and cargo tank location. 
2-9 2.0 – Description of the Proposed Action 

Figure 2.1-3. Typical Membrane Type LNG Carrier 
2-10 2.0 – Description of the Proposed Action 

Figure 2.1-4. Typical Designs for an LNG Ships 
2-11 2.0 – Description of the Proposed Action 

The Type IIG design ensures an LNG carrier could withstand flooding of any two adjacent 

compartments without any adverse effect upon the stability of the vessel. Type IIG design also 

requires that the cargo tanks must be a minimum of 30 inches from the outer hull and a minimum 

distance above the bottom of the vessel equal to the beam of the vessel divided by 15, or 6.5 feet, 

whichever is less. This distance is intended to prevent damage to the cargo tanks in case of low 

energy-type accidents that might occur in harbors and during docking. Most large LNG carriers 

have a distance of 10 to 15 feet between the outer hull and cargo tank. 

2.1.3.3 Containment Systems 

The LNG containment system on LNG carriers consists principally of the cargo tank (sometimes 

called a primary barrier), the secondary barrier, and insulation. The containment system also 

includes cargo monitoring and control and safety systems. 

Three basic tank designs have been developed for LNG cargo containment: prismatic freestanding, spherical, and membrane. The earliest form of LNG containment is the prismatic freestanding tank. It consists of an aluminum alloy or 9 percent nickel steel, self-supporting tank 

that is supported and restrained by the hull structure. Insulation consists of reinforced 

polyurethane foam on the bottom and the sides, with fiberglass on the top. The spherical tank 

design, also known as the Moss design, uses an unstiffened, spherical, aluminum alloy tank that 

is supported at its equator by a vertical cylindrical skirt, with the bottom of the skirt integrally 

welded to the vessel’s structure. This free-standing tank is insulated with multi-layer closed-cell 

polyurethane panels. In the membrane containment system, the membrane is supported by the 

inner hull through the insulation. Two forms of membrane are commonly used: the Technigaz 

membrane using stainless steel and the gas-transport membrane using Invar. An LNG carrier 

with a membrane-type containment system is shown on figure 2.1-3. Figure 2.1-4 depicts typical 

spherical and membrane designs for LNG carriers. 

2.1.3.4 Pressure/Temperature Control 

A basic goal of all LNG containment systems is to maintain the LNG cargo at or near 

atmospheric pressure and at the boiling temperature of the LNG (about -260°F). Any heat leak 

through the containment insulation results in vaporization of LNG, allowing the tank to remain at 

a constant temperature. The resultant vapor, referred to as boil off gas (BOG), is removed to 

maintain the tank pressure. The vapor ranges from 0.15 to 0.25 percent (by volume) per day and 

is used to supplement the bunker fuel in the carrier’s boilers. The Coast Guard does not permit 

routine venting of BOG to the atmosphere in the United States. Thus, all LNG carriers that trade 

in the United States are fitted with an internalized combustion energy system that allows the 

carrier’s boiler to consume all of the BOG to fuel the vessel’s steam propulsion system. As a 

result, LNG carriers have reduced emissions when compared with conventional oil-fired vessels. 

2.1.3.5 Ballast and Cooling Water 

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

port safely under various sea conditions. LNG cargo tanks are not used as ballast tanks because 

these tanks remain at cryogenic temperatures and contain a minimal amount of LNG during the 

return voyage. Consequently, LNG carriers must be designed to provide adequate ballast 

capacity in other locations. 
2-12 2.0 – Description of the Proposed Action 

Ballast water tanks are arranged within the LNG carrier’s double hull. To reduce the potential 

for leakage, the ballast tanks, cofferdams, and void spaces are typically coated to reduce 

corrosion. LNG carriers are also periodically inspected to examine the coating and to renew it as 

necessary. 

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

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

a constant draft during all phases of its operation. Under normal operating conditions, ballast 

water would be taken onto the vessel while the LNG carrier is offloading at the LNG import 

terminal, estimated to take 11 to 13 hours to complete. Ballast water is typically only discharged 

during loading operations at the LNG export terminal or during mid-ocean ballast water 

exchanges during the transit from the import terminal to the export terminal. No ballast water 

would be discharged near the LNG import terminal. 

Vessels unloading at LNG terminals also need cooling water for the engines that generate 

electrical power for the offloading pumps and other onboard systems. Jordan Cove is proposing 

to utilize a system that would use landside power for some limited ship functions to reduce 

overall vessel water usage. However, for safety reasons the Coast Guard requires that ships’ 

engines are powered up while at dock, therefore there would be cooling water needs during the 

entire time each vessel is at dock (estimated to be 18 to 24 hours), and use of total landside 

power rather than ship’s power (called “cold ironing”) would not be possible. Depending on the 

particular LNG carrier, an estimated combined 16.9 to 75.3 million gallons of ballast and engine 

cooling water may be taken on during LNG carrier offloading operations. As presented in the 

draft EIS, Jordan Cove had proposed to use a screen system and floating filtered water delivery 

system to avoid or minimize impacts to aquatic resources as a result of ballast and cooling water 

intake. However, because of recent concerns identified by the Coast Guard, it is unclear if such a 

system would be feasible because it would require certification and testing for each LNG carrier 

that would call at the terminal, a process that would be beyond the control of Jordan Cove. 

Jordan Cove is currently evaluating other options to replace a screen system, as well as the 

option of traditional water intake. We further discuss the potential impact of ballast and engine 

cooling water intake on aquatic resources in section 4.5.2. 

2.1.3.6 Ship Safety Systems 

The LNG carriers proposed for use at the Jordan Cove terminal would need to comply with all 

federal and international standards regarding LNG shipping. As such, vessels that transport 

LNG to the proposed import terminal would be fitted with an array of cargo monitoring and 

control systems. The systems include provisions for pressure monitoring and control, 

temperature monitoring of the cargo tanks and surrounding ballast tanks, emergency shutdown 

(ESD) of cargo pumps and closing of critical valves, monitoring of tank cargo levels, and gas 

and fire detection. 

The vessels that transport LNG to the terminal would be fitted with many navigation and 

communication systems, including: 

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

finders; 

• LORAN-C receivers; 

• echo depth finders; and 
2-13 2.0 – Description of the Proposed Action 

• a satellite navigation system. 

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

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

failure. 

2.1.3.7 Fire Protection 

All LNG carriers arriving at the proposed terminal would be constructed according to structural 

fire protection standards contained in the International Convention for the Safety of Life at Sea 

(SOLAS). This would be done under the review and approval procedures of the flag state. 

LNG carriers using the terminal would also be fitted with active fire protection systems that meet 

or exceed design parameters in Coast Guard regulations and international standards, such as the 

IMO Code for the Construction and Equipment of Ships Carrying Liquefied Gases in Bulk and 

SOLAS including: 

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

and all main cargo control valves; 

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

fire stations found throughout the vessel; 

• a dry powder extinguishing system for LNG fires; and 

• a carbon dioxide (CO2) system for protecting the machinery, ballast pump room, 

emergency generators, cargo compressors, etc. 

2.1.3.8 Crew Qualifications and Training 

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

Standards of Training, Certification and Watch Keeping for Seafarers. Key members of the crew 

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

must receive simulator training in the handling of the vessel and the cargo systems specific to the 

conditions at the Jordan Cove terminal site. In addition, each LNG carrier would enter the Coos 

Bay navigation channel under the navigational control of a Coos Bay pilot. 

2.1.3.9 Ship Selection 

The specific identity of LNG carriers that would unload at the terminal would depend on the 

commercial terms of the LNG purchase agreements. Transportation could be provided by either 

the LNG buyer or supplier. The different contractual arrangements for LNG transport can result 

in vessels of different sizes and countries of origin being used to transport LNG to the terminal. 

The existing Coos Bay navigation channel can only handle LNG carriers up to about 148,000 m3 

in capacity (see section 4.12.5 of this EIS). 

Vessels using the terminal would comply with the Coast Guard regulations for LNG carriers. 

This compliance is demonstrated by the operator of the LNG carrier having proper certificates 

authorizing the transport of LNG as follows: 

• United States Flag LNG Ship – The Coast Guard Certificate of Inspection (COI) must be 

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

issued for a period of 5 years and retention of the COI depends upon the continued 
2-14 2.0 – Description of the Proposed Action 

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

required annual inspections during the 5-year COI period. 

• Foreign Flag LNG Ship – The vessel must have a valid Certificate of Compliance (COC) 

issued by the Coast Guard. The certificate is issued after the vessel has proved that it 

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

by a Coast Guard Marine Safety Office (46 CFR 154). A COC is valid for a 2-year 

period and remains valid pending satisfactory completion of an annual mid-period 

examination between certificate renewals. 

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

flag state. Jordan Cove would continually monitor vessel unloading operations at the LNG 

terminal to ensure that the operations are according to their established procedures and to ensure 

that the vessels are maintained to all standards. 

2.1.4 Jordan Cove LNG Import Terminal 

Jordan Cove proposes to construct and operate a new LNG import terminal on the bay side of the 

North Spit of Coos Bay, Oregon. The general location of the LNG import terminal is shown on 

figure 2.1-5. The terminal would receive shipments of LNG from about 80 carriers per year3

 that 

could transport their cargos across oceans from countries throughout the world that have natural 

gas reserves and liquefaction facilities. The LNG carriers would proceed up the waterway about 

7.5 miles within the existing Coos Bay navigation channel to the proposed LNG import terminal. 

The Port would construct an access channel from the existing Coos Bay navigation channel, and 

a slip to be used by LNG carriers at the terminal. The terminal would contain facilities to 

unload, store, vaporize the LNG back into natural gas, and send the natural gas to the Pacific 

Connector pipeline. The LNG terminal would have a maximum sendout capacity of 1.2 Bscfd of 

natural gas. The proposed Port facilities are shown on figure 2.1-6. 

The proposed LNG import terminal would include an access channel and slip, LNG unloading 

facilities and a transfer pipeline, two LNG storage tanks, vaporization and vapor handling 

systems, NGL extraction facilities, a 37-MW natural gas-fired electrical power generation plant, 

other utilities, buildings, and support facilities. A layout of the proposed LNG terminal is shown 

on figure 2.1-7. In addition, this section discusses the locations where material dredged for the 

access channel and slip would be stored. 

 

3

 Jordan Cove based the estimate for LNG marine traffic in the waterway on the average size of an LNG carrier being about 

143,000 m3

 in capacity. If larger LNG carriers are used to transport LNG to the import terminal, the number of visits may be 

less. 
2-15 2.0 – Description of the Proposed Action 

Figure 2.1-5. Jordan Cove Project Location Map 
2-16 2.0 – Description of the Proposed Action 

Figure 2.1-6. General Location of Port Component, LNG Terminal, and PCGP (Western Portion) and 

Dredged Material Placement Sites 
2-17 2.0 – Description of the Proposed Action 

2.1.4.1 Access Channel 

The Port would dredge an access channel from the existing Coos Bay navigation channel to the 

LNG terminal slip (figure 2.1-8). The access channel would begin at the confluence between the 

Jarvis Turn and the Upper Jarvis Range at about CM 7.5 along the Coos Bay navigation channel. 

The access channel would be about 2,000 feet wide at the navigation channel and about 800 feet 

wide at the mouth of the proposed slip, and about 800 feet long at its northern edge and about 

1,400 feet long at its southern edge. It would be dredged to a minimum depth of minus (-) 45 

feet below 0.0 feet North American Vertical Datum of 1988 (NAVD88), with -3 feet of 

overdredge allowance. The walls of the access channel would be sloped to meet the existing 

bottom contours at an angle of 2.5 feet horizontal: 1 foot vertical. The access channel would 

cover about 31 acres below the MHHW line. 

To create the access channel about 1.3 million cubic yards (mcy) would be dredged out of Coos 

Bay. This dredging would affect about 15.8 acres of currently existing deep subtidal strata 

below –15 feet in depth; about 9.6 acres of existing shallow subtidal strata between the MLLW 

line and –15 feet; and about 5.7 acres of existing intertidal strata between the MLLW line and the 

MHHW line. The dredging would be done primarily with a hydraulic dredge, operating from 

adjacent uplands and from a barge in the bay. Details about dredging and the disposal of 

dredged materials are discussed in section 2.1.4 of this EIS. The ODSL is the owner of the 

bottom of the bay. The Port would need approval from ODSL, through its JPA, to dredge and 

use the access channel to the proposed LNG terminal. 

2.1.4.2 Slip 

The Port would construct and own a slip, excavated from current uplands, starting at the end of 

the access channel. The east side of the slip would have a berth for LNG carriers, and at the 

north end of the slip would be a dock for tractor tugs. A layout of the proposed slip is shown on 

figure 2.1-9. The Port has identified a potential future use of the western side of the slip as a 

general cargo dock, but no berth, structures, or other facilities are currently proposed for the 

western side of the slip. 

The inside dimensions at the toe of the slope of the slip would measure approximately 718 feet 

along the north boundary and approximately 1,460 feet and 1,211 feet along the western and 

eastern boundaries, respectively. The minimum water depth within the slip would be -45 feet 

NAVD88, with 3 feet of overdredge allowance. Side slopes for the slip would be constructed at 

an angle of 3 feet horizontal: to 1 foot vertical. The slopes would be armored with a minimum of 

2 feet of riprap at a grade of 1.75 feet horizontal: 1.0 foot vertical. The riprap would be clean 

rock, free of fine materials. The top of the riprap would be at plus (+) 8 feet NAVD88, while the 

top of the slope is proposed to be at + 25 feet NAVD88. The slip would affect about 41 acres of 

current uplands above the MHHW line. 
2.0 – Descr

2-18

Figure 2.1-7. Plot Plan of the LNG Terminal 
2.0 – Descr

2-19

Figure 2.1-8. Plot Plan of the Marine Facilities 
2.0 – Descr

2-20

Figure 2.1-9. Plot Plan of the Marine Berth 
2-21 2.0 – Description of the Proposed Action 

About 4.3 mcy of material would need to be removed to create the slip basin. Of this, about 1.0 

mcy would be dry excavated using land-based conventional scrapers and excavators to about 0.0 

feet NAVD88, and about 3.3 mcy would be hydraulically dredged below that point.4 Scrapers 

and dump trucks would transport the excavated material to the recommended placement 

locations, while the hydraulically dredged materials would be transported by a slurry pipeline to 

the recommended disposal areas. Section 2.1.4.4 provides more details about the dredging 

operations and disposal of materials. 

Structures that would be constructed by the Port for the LNG terminal berth on the east side of 

the slip would include an LNG unloading platform, four breasting dolphins, five mooring 

dolphins, and pipe and roadway trestle between the shore and unloading platform. The breasting 

and mooring structures would consist of steel pipe piles with concrete caps, and the breasting 

structures would be equipped with fenders. Access catwalks would connect the breasting 

structures to the unloading platform and to the mooring structures. The mooring structures 

would be equipped with access stairs, hand rails, quick release hooks, and lighting fixtures. 

The LNG unloading platform would be a single-level, reinforced-concrete beam structure, about 

115 feet wide by 60 feet deep, supported on steel pipe piles (figure 2.1-10). On top of the dock, 

at + 30 feet NAVD88, would be a mezzanine-type platform constructed of steel for maintenance 

of the triple-swivel assembly of the unloading arms. The top of the gangway tower would be 

about 13 feet high (figure 2.1-11). There would be a 167-foot-long trestle and pipe rack 

extending from the unloading platform to the shore. 

The LNG berth would create about 15 acres of impervious surface from the dock structures. The 

dock at the LNG berth would be supported by 136 pre-cast concrete pilings. An existing effluent 

line would have to be relocated around the slip. 

The Port would permit, construct, and own the slip. Jordan Cove would lease its berth on the 

east side of the slip from the Port, and construct and operate the LNG carrier unloading facilities 

(including the unloading arms and LNG transfer pipelines). 

The Port would also construct and own a tug dock and connecting trestle on the northern side of 

the slip that would serve the LNG terminal. The tug dock would be about 400 feet long and 12 

feet wide, and would be supported by thirty-three 18-inch octagonal concrete pilings. It could 

accommodate three high bollard tugs. 

 

4

 These numbers are derived from the report by Moffat & Nichols, International, revised March 4, 2008, entitled “Oregon 

International Port of Coos Bay, Oregon Gateway Marine Terminal, Draft Excavated & Dredged Material Management Plan,” 

filed by Jordan Cove with the FERC on May 22, 2008 in Docket No. CP07-444, as part of the copy of the Port’s COE 

application. 
2.0 – Descr

2-22

Figure 2.1-10. Marine Berth – Elevation View 
2.0 – Descr

2-23

Figure 2.1-11. Marine Berth – Section View 
2-24 2.0 – Description of the Proposed Action 

On the west side of the slip the Port has identified that it may construct and own a potential 

future dock for unspecified general cargo. According to the Port’s April 23, 2008 revised 

application to the COE,5 this potential future dock would likely accommodate a “roll on-roll off” 

type terminal, although an intended user has not yet made a commitment to the Port to locate 

there. The Port’s revised application to the COE states that this potential future dock is not part 

of the currently proposed Project. It is therefore not addressed in this EIS except for the 

discussion of potential future projects in cumulative effects (section 4.13). The only Port facility 

that is currently proposed at the western shoreline of the slip following construction, and that is 

addressed in this EIS, would be a narrow gravel area covering about 1.7 acres. 

Jordan Cove would essentially be the anchor tenant for the slip and Jordan Cove’s agreement 

with the Port is structured around accommodating the requirements of the LNG terminal. Any 

development of the cargo dock by the Port would have to conform to the priorities of the LNG 

terminal and the unloading of LNG carriers at Jordan Cove’s berth. 

2.1.4.3 LNG Terminal Components 

LNG Unloading and Transfer Facilities 

The LNG unloading system to be installed by Jordan Cove on its berth at the terminal slip would 

include unloading arms, gangway tower, firewater monitors, service utilities, and piping and 

associated valves. Four LNG unloading arms would be installed on the steel mezzanine 

unloading platform, three for normally unloading LNG to the terminal storage tanks and one for 

vapor return to the LNG carrier. Space would be provided for one additional LNG liquid 

unloading arm. The two middle arms would be piped for dual service arms capable of unloading 

LNG to the terminal storage tanks or returning vapor to the ship. The unloading arms would be 

16 inches in diameter, with an unloading design rate of 12,000 m3

/hr, based on use of three liquid 

arms. The arms would have a maximum design pressure of 250 psig at temperatures between – 

270 to + 150°F; with the nominal operating pressure expected to be about 90 psig at – 260°F. 

The unloading arms would be designed with swivel joints to provide the required range of 

movement between the ship and the shore connections. Each arm would be fitted with a 

hydraulically interlocked double ball valve and powered emergency release coupling 

(DBV/PERC) to isolate the arm and the ship in the event of an emergency condition where rapid 

disconnection of connected arms is required. Each arm would be fully balanced in the empty 

condition by a counterweight system and maneuvered by hydraulic cylinder drives. 

Onboard LNG carrier pumps would deliver the LNG from the carrier to the unloading system on 

the terminal berth. LNG would be transferred from the unloading arms to the on-shore storage 

tanks through one 2,600-foot-long, 36-inch-diameter cryogenic unloading line. 

Valves would be installed at the extremities of each transfer system in compliance with the 

National Fire Protection Association (NFPA) section 8.2 Piping System. The design of the 

unloading arms would include a system to enclose and capture all LNG liquids and natural gas 

(cool down and purge gas) during normal operations. 

The facilities would be designed to provide the safe transfer of LNG from the carriers to the onshore storage facilities. Design would be in accordance with applicable codes and standards, 

 

5

 A copy of the Port’s revised COE application was filed by Jordan Cove on May 22, 2008 in Docket No. CP07-444. 
2-25 2.0 – Description of the Proposed Action 

including but not limited to Oil Companies International Marine Forum (OCIMF), Society of 

International Gas Tanker and Terminal Operators (SIGTTO), American Petroleum Institute 

(API), American Society of Civil Engineers (ASCE), and section 8.4 of NFPA 59A for Marine 

Shipping and Receiving. 

LNG Storage Tanks 

Once transferred from the ships the LNG would be stored in two full-containment LNG storage 

tanks, each designed to store 160,000 m3 (1,006,000 barrels) of LNG at a temperature of -270 

degrees F, at a maximum internal pressure of 4.21 psig. Each LNG storage tank would consist of 

a primary inner steel container and a secondary outer concrete shell (see figure 2.1-12). Based 

on Jordan Cove’s Front End Engineering Design (FEED), the top of the dome of a tank would be 

about 180 feet above grade6

 and the diameter of the outer tank would be about 267 feet wide. 

These tanks would be designed so that both the primary inner container and the secondary outer 

concrete shell are capable of independently containing the stored LNG. The LNG storage tanks 

would be located north of the marine slip in an area that is currently mostly flat open land where 

the COE formerly deposited materials it dredged during maintenance of the Coos Bay navigation 

channel (see section 4.2 for a description of soils, section 4.4 for a description of vegetation, and 

section 4.7 for current land use). Through cut-and-fill construction, the base elevation of storage 

tanks would be raised to 20 feet above mean sea level (MSL). The LNG tanks would be 

enclosed within a storm surge barrier that would be 55 feet high. The storm surge barrier would 

be designed to contain the contents of one 160,000 m3

 storage tanks. 

The final design and supplier for the LNG storage tanks have not yet been selected by Jordan 

Cove. The conceptual preliminary design of all facility features is discussed in sections 4.12.2 

and 4.12.3 of this EIS. In general, each LNG storage tank would consist of the following 

elements: 

• 9 percent nickel steel open top inner primary container; 

• carbon steel liner around the primary container; 

• carbon steel doomed roof; 

• insulated aluminum deck over the inner container suspended from the roof; 

• reinforced concrete bottom slab with pedestals and seismic isolators; 

• reinforced concrete tank base slab with carbon steel liner plate; and 

• reinforced post tensioned concrete wall and reinforced concrete roof on the secondary 

outer container. 

Each storage tank would be built on a reinforced concrete slab foundation. The soil beneath the 

foundation would be improved using methods defined during subsequent geotechnical studies for 

the final design (see section 4.12.3 for more details about ground improvement based on 

geotechnical studies to meet seismic design standards). Base heating would not be necessary, as 

the tank base slab would be elevated. The load-bearing insulation on top of the base, beneath the 

inner storage tank container, would be cellular glass, capable of supporting the weight of the 

inner container and LNG. Concrete used for the construction of the LNG tanks would be in 

accordance with section 4.5 of NFPA 59A.

 

6

 In a filing with the FERC on February 20, 2009, Jordan Cove clarified that while each LNG storage tank would be 202 feet and 

7 and 7/8 inches high, with the ground elevation at 20 feet this translates to 173 feet and 9 and 9/16 inches above grade, from the 

top of the tank floor to the top of the dome. 
2.0 – Descr

2-26

Figure 2.1-12. Typical LNG Storage Tank 
2-27 2.0 – Description of the Proposed Action 

The inner container would be composed of 9 percent nickel steel A553 Type 1. It would be 

designed in accordance with API 620 Appendix Q. The inner container would consist of a shell 

and bottom, with the top open. It would not use a roof. Gas and gas pressure produced by the 

stored LNG would be contained by the self-supporting roof of the outer container. Vapor 

pressure from the LNG would be equalized through vents in the suspected deck and contained 

within the outer shell. 

The exterior walls of the outer container would be of reinforced concrete, lined with a butt 

welded compression ring and welded steel plates, and a reinforced concrete dome poured over a 

carbon steel framework. The inner liner of the outer container would be of type A516-60 carbon 

steel, while the bottom corner protection would be 9 percent nickel steel. The carbon steel inner 

liner would serve as a barrier to moisture migrating from the outside atmosphere to the insulation 

between the containers, and would also prevent vapor from escaping from the inner container 

during normal operations. A deck, of B209-5083-0 aluminum, would be suspended from the 

outer roof by hangers made of type 304 stainless steel. The top surface of the deck would be 

insulated with fiberglass. The outer tank roof and vapor space about the suspended deck would 

be at ambient temperature. 

The space between the inner and outer containers would be insulated with resilent blanket and 

expanded perlite, to keep the stored LNG at a temperature of – 270°F. There would be no 

penetrations through the inner container or outer container sidewall or bottom below the 

maximum liquid level. All piping into and out of the tank would enter from the top of the tank. 

Vapor Handling System 

During normal operation of the LNG import terminal facilities, ambient heat would cause a small 

amount of LNG to be turned back into a gaseous state. Low pressure vapor, or BOG, could be 

generated by several factors, including heat added to LNG during piping or pumping, barometric 

pressure changes, and ship flash. The vapor handling system would recover these vapors for 

either use in the facility fuel gas system, return to the LNG storage tank, or return to the LNG 

carrier. During an upset condition, vapor from the tanks would be directed to the vent to prevent 

over pressuring the LNG storage tanks. 

Jordan Cove planned for an allowable daily BOG rate of 0.05 percent per day from the storage 

tanks. Each storage tank would be equipped with a 20-inch-diameter BOG line. From the BOG 

header, vapors could be routed to the BOG compressors where the gas would be pressurized to 

about 60 psig and sent out to the LP fuel system. Excess BOG not required for the LP fuel 

system would be compressed in the second stage BOG compressors to about 180 psig and mixed 

with the LNG upstream of the sendout pumps. In the event that the LNG storage tank pressure is 

too high, and the BOG compression system is incapable of reducing the tank pressure, BOG may 

be directed from the tanks to the low pressure flare knockout drum for disposal. 

During LNG carrier unloading operations, vapors would be released from the LNG storage tanks 

due to simple displacement as the tanks are filled. A portion of this vapor would be returned to 

the ship to make up for the volume of liquid pumped out of the ship into the LNG storage tanks. 

In situations where the vapor returning to the LNG carrier would be warmer than -180°F, the 

returning vapor would be cooled by a spray de-superheater system protected by the downstream 

de-superheater knockout drum. This vapor would be returned to the LNG carrier through a 

single 16-inch-diameter articulated vapor return unloading arm. 
2-28 2.0 – Description of the Proposed Action 

LNG Sendout System 

Inside of each LNG storage tank would be two vertical submerged pumps that would transfer the 

LNG from the storage tanks to the sendout pumps. Each storage tank would also have a third, 

unequipped pump column as a backup, with a spare pump stored in the terminal warehouse. 

Combined, the two pumps would have a peak sendout rate of 1.0 Bscfd. Each in-tank pump 

would be designed for a rate up to 5,325 gpm. They would be driven by motors rated at about 

1,250 hp each. The pumps would normally be operated submerged with 1.5 psig tank pressure. 

LNG from the discharge of the in-tank pumps would be used to keep the rundown lines chilled. 

This “keep cool loop” would re-circulate a small slip stream of LNG back to the main unloading 

arm header immediately downstream of the unloading arm isolation valves, and this is returned 

to the LNG storage tanks. 

Jordan Cove would install six LNG sendout pumps to boost the LNG pressure to a sufficient 

level to enter the pipeline after vaporization. Five pumps would normally operate, at flow rate of 

about 2,000 gpm, with one pump reserved as a backup. These would be multi-stage, seal-less 

pumps, with the motor rated at about 3,000 hp. The pumps would boost the LNG from about 

170 psig to about 1,510 psig. 

Re-Gasification System 

A regasification system is required to convert the LNG from a liquid to natural gas prior to 

delivery into the sendout pipeline. Six submerged combustion vaporizers (SCV) (five plus one 

spare) would be used to heat the LNG and vaporize it into natural gas. Each vaporizer would be 

capable of vaporizing approximately 205 Mscfd of LNG, 200 Mscfd as sendout natural gas, and 

5 Mscfd routed to the LNG terminal fuel system. The vaporization equipment and control 

systems would be designed, fabricated, and installed in compliance with 49 CFR 193 § 2401, and 

sections 5.4.1(1) (relief valve capacity), 5.5 (combustion air supply), and 5.6 (products of 

combustion) of NFPA 59A, 2001 edition. 

Each SCV would provide about 120 million British thermal units per hour (MMBtu/hr) of heat to 

the LNG with an outlet temperature for the natural gas at about 40°F. Heat for the LNG 

vaporization would be supplied simultaneously from two sources, hot water from the quench 

system and combustion of fuel gas in the SCV water bath. Hot turbine exhaust from the power 

generation unit is recovered in a waste heat recovery unit by heating a water loop. The exhaust 

gas (at approximately 1,018°F) enters the condensing waste heat recovery unit (WHRU) where 

the gas is cooled due to cross-exchange with the circulating water from the SCV water bath. The 

circulating water cools the turbine exhaust to a nominal 120°F. The heat from the exhaust 

turbine is transferred to the water where it is further heated in the waste heat recovery unit. The 

hot water is then sparged into the SCV water bath between the LNG vaporization tube bundle 

and the normal combustion header distributor. The hot water would supplement the required 

firing of the combustion chamber in the SCV, thereby improving the thermal efficiency of the 

facility. 

During normal operation, fuel gas for the SCVs would be supplied from the BOG system, 

supplemented with gas from the vaporizer outlet. For startup, and in the event that the BOG is 

insufficient to maintain pressure in the header, fuel gas would be let down from the principal 

sendout line. The fuel gas system for the SCVs would be operated at 50 psig. 
2-29 2.0 – Description of the Proposed Action 

As a bi-product of the vaporization process, the SVCs produce slightly acidic water. Jordan 

Cove would add a caustic to this water to control pH, and the treated excess water from the 

SCVs would overflow to the neutralized water sump, before being pumped to the firewater pond. 

Section 4.3.2 of this EIS discusses the water used and produced by the vaporization process in 

more detail with regards to environmental considerations. 

Gas Metering 

The LNG terminal facilities would also include a gas metering system to meter the gas after it 

leaves the vaporizer and before it is sent to the sendout pipeline. The metering system would be 

a dedicated fiscal gas metering station provided for custody transfer of sendout gas. The 

metering systems would be supplied as a completed pre-engineered package including the flow 

measurement skids, associated instrumentation, analyzers, and flow computers. The metering 

package would include three metering tubes, of which two would normally be in operation, and 

the third would be a backup and also could be utilized as a calibration meter. The metering 

computer and electronics would be located in the control building. The metering system for the 

terminal would consist of redundant ultrasonic flow meters and custody transfer flow computers. 

Metering systems would be interfaced with the distributed control system via redundant Ethernet 

or serial link. 

Jordon Cove’s metering facilities would be located in the process area north of the SCVs. From 

there the natural gas would be transferred by Jordan Cove’s sendout pipeline to the Pacific 

Connector Meter Station along the access road to the west of the process area, north of the 

Roseburg wood chip facility.

Piping and Pipe Racks 

Jordan Cove would install piping systems in accordance with American Society of Mechanical 

Engineers (ASME) B31.3, and the piping would be designed to handle anticipated seismic loads. 

The use of flanges in cryogenic piping would be minimized, and piping connections would be 

done in accordance with NFPA 59A sections 6-3.1 and 6-3.1, with welding meeting the 

requirements of section 6-3.4. Valves exposed to cryogenic temperatures would be equipped 

with extended bonnets. For piping transporting cryogenic liquid, a total cellular glass insulation 

system is preferred. Pipe racks supporting LNG piping would be constructed of reinforced 

concrete columns and beams. Racks for non-cryogenic piping would be constructed of structural 

steel. 

Pressure Relief, Vent, and Flare Systems 

LNG from thermal relief valves and pressurized drains would be returned to the storage tanks. 

The majority of the process relief valves would be designed to discharge into a closed flare 

system. The LNG tank pressure safety valves, some fuel gas pressure letdown station relief 

valves, and the SCV safety valves would vent directly into the atmosphere. 

A low-pressure flare would be installed to handle the gas relieved during emergency conditions. 

The flare header would be purged with fuel gas, and could be ignited with an electronic pilot 

light. The elevated flare would be designed to comply with NFPA 59A Paragraph 5.4.1(a). 

Potential heat flux is limited by stack height to no more than 1,500 British thermal units per hour 

per square foot (Btu/ft2

/hr), plus solar radiation at grade. The flare would be located north of the 

process area. 
2-30 2.0 – Description of the Proposed Action 

Natural Gas Liquid Extraction Facilities 

Jordan Cove proposes to include NGL extraction facilities as part of its terminal to control 

sendout gas quality and recover NGL for sale by a non-jurisdictional third party. If the imported 

LNG has a high heating value, NGL would be extracted. NGL recovery may or may not be 

needed depending on the composition of the imported LNG, and the availability of a railroad to 

transport the NGL to another processing plant, so the terminal would be designed to operate 

independently of the NGL extraction facilities. 

LNG from the storage tanks would be pumped through a de-ethanizer system to recover the 

NGL. The rich LNG feed would be heated against the de-ethanizer overhead in a standard 

brazed aluminum LNG/gas exchanger. The cold side effluent would flow to the feed flash 

separator, where the flash liquid would be pumped to the de-ethanizer. The de-ethanizer is a 

packed column that separates the NGL from the pipeline gas. Vapor reboil for the column would 

be provided by the de-ethanizer reboiler, heated using hot oil from the hot oil system using a 

peripheral amount of low pressure fuel gas. The de-ethanizer bottoms stream would be pumped 

via NGL product pumps to battery units. Flash vapor from the feed flash separator would be 

compressed in the flash gas compressors, and the amount of flash would influence the amount of 

propane and heavier components sent to the de-ethanizer. The compressor discharge would be 

mixed with the de-ethanizer overhead and sent back through the hot side where the vapors would 

be condensed into a slightly sub-cooled lean LNG liquid stream. 

NGL extraction would be done within the process area, adjacent to the west of the SCVs. The 

system would have a peak throughput capacity of 1,000 Mscfd. The NGL would then be 

transported by pipeline to the NGL storage area along the access road to the terminal, on the west 

side of the Pacific Connector Meter Station, north of the Roseburg facility. From there, the NLG 

would be loaded onto rail cars for transport to a distance processing plant. See additional 

discussion about the non-jurisdictional NGL storage and transport facilities in section 2.2.1 of 

this EIS. 

Jordan Cove stated that it would only recover NGL if it is economically viable, and a railroad 

could be used to transport NGL from the site. Rail service is currently not available because the 

existing railroad to the site is inactive. However, the Port is moving forward with its planned 

acquisition of this rail line from Central Oregon & Pacific Railroad. If successful, the Port 

would then be required to rehabilitate the rail line. The Port estimates service on the line could 

resume by 2010. 

Support Buildings 

Table 2.1.4.3-1 lists the proposed support buildings for Jordan Cove’s LNG terminal. The 

administration building would be located along the access road to the terminal, west of the 

process area, adjacent to, on the east side of the Pacific Connector Meter Station, and north of the 

Roseburg facilities. The shop and warehouse would be along the access road, to the west of the 

administration building. The electrical substation would be on the north side of the process area, 

west of the shop. The control building would be located on the east side of the process area, 

south of the electrical substation. The firewater pumphouse would be located adjacent to the 

firewater pond on the southeast corner of the process area. The berth operation building would 

be situated adjacent and just east of the dock, south end of the transfer pipeline. 
2-31 2.0 – Description of the Proposed Action 

TABLE 2.1.4.3-1 

Support Buildings for the LNG Terminal 

Building Function Size Construction Materials Other Elements 

Administration Building 55 feet x 81 feet x 

21 feet high 

Steel exterior frame and 

pre-cast wall panels. 

Building would include vestibule, offices, 

conference room, restrooms, kitchen, file and 

storage room, and mechanical room 

Shop and Warehouse 100 feet x 102 

feet x 30 feet high 

Pre-fabricated steel frame 

with metal roof and siding 

Building would include offices, locker room, 

kitchen, shop, and cranes 

Control Building 126 feet x 89 feet 

x 12 feet high 

Reinforced masonry Building would include a control room, 

offices, storage, equipment room, and lunch 

room, laboratory, battery room, and 

restrooms 

Electrical Substation 120 feet x 60 feet 

x 20 feet high 

Reinforced masonry Building would contain switchgear and motor 

control centers 

LNG Berth Operator Building 32 feet x 16 feet x 

12 feet high 

Block wall and concrete roof Building would include operator area, 

restroom, transformer room, and battery 

room 

Firewater Pumphouse 60 feet x 40 feet x 

15 feet high 

Pre-fabricated steel frame 

with metal siding and roof 

Building would contain two electric driven 

pumps, two diesel driven pumps, and one 

electric motor driven jockey pump, with an 

installed spare 

Compressor Shelter 130 feet x 60 feet 

x 21 feet high 

Steel frame with metal roof 

and walls 

Building would induce 3 BOG compressors 

and 2 second stage BOG compressors 

Electrical Systems 

Electrical power for the LNG terminal would be provided mostly from an on-site gas turbine 

generator, nominally rated at 37 MW. The power generator at the terminal would be located 

within the process area, adjacent to, on the east side, of the SCVs. The gas turbine at the on-site 

electrical generating plant would be run on fuel gas, sourced mostly from BOG from the LNG 

storage tanks, pressurized to 300 psig. 

Alternative power would be acquired, if necessary, from a 115-kilovolt (kV) tie-in to the existing 

PacificCorp utility grid, stepped down to 13.8 kV. The PacifiCorp connection would be 

provided by tapping an overhead 115-kV distribution line, just north of the South Dunes 

Substation. The 115-kV feeder would be routed across the LNG terminal site to the electric 

substation, where the current would be stepped down through oil-filled power transformers to 

13.8 kV. 

Most of the facility’s electrical load is composed of motors, with the largest motor rated at 

approximately 5,000 hp. The total maximum operating load of the LNG terminal would be 

approximately 25 MW. However, this electrical load would only be experienced during peak 

demand conditions when NGL extraction is required and LNG carriers are being unloaded. The 

facility would export surplus power to the local utility grid whenever the facility electrical load is 

less than the power produced by the generator. 

A standby emergency generator would provide back-up power for critical loads. This generator 

would be driven by a diesel engine, with an output rating of 2,000 kilowatt (kW) at 4,160 volts, 

three-phase, 60 hertz, and 0.8 power factor (pf). Critical loads served by this generator would 

include running the instrument air compressors, emergency lighting, and the berthing substation. 

The emergency generator would be connected to the 4,160-volt bus to be used if the power 

supply fails. 
2-32 2.0 – Description of the Proposed Action 

A 40-kilovolt amperes (kVa) uninterruptible power system (UPS) would be installed in the 

control room. This would consist of an inverter, rectifier, static bypass switch, manual bypass 

switch, batteries, and fused load distribution panel. A 10 kVa UPS would be installed on the 

LNG carrier berth platform. 

Lighting Systems 

Lighting would be provided outdoors around the LNG terminal, including at the process area, 

access roadway, tank stairways, storage tank roof, building exteriors, and LNG carrier berth 

platform. Low-glare yellow light bulbs would be used where possible for perimeter lighting. 

The roadway and perimeter lighting would be downward focused. Lights on the LNG carrier 

berth platform would be used primarily during carrier unloading operations. 

A duel aircraft warning light would be placed on the highest point of each storage tank. A 

minimum of two outdoor convenience receptacles would be provided on the top of the tank 

platforms. Emergency outdoor lighting on the storage tanks would be powered from the terminal 

emergency bus. 

Jordan Cove filed a draft lighting plan on November 30, 2007. This conceptual plan indicated 

that lighting levels would be as recommended in API 540, Section 7, table 4, as follows: 

• At the pipe racks, pump rows, and operating areas – 5 foot candle (FC) intensity utilizing 

70-watt and 100-watt high pressure sodium (HPS) type fixtures with globe, guard, and 

either dome or angle reflector; 

• Compressor building – 20 FC intensity utilizing 250-watt HPS type high bay fixtures 

with reflector and glass lens mounted above the bridge crane; 

• Perimeter security lighting – 0.1 FC intensity utilizing two 250-watt HPS type floodlights 

mounted on a 30-foot-tall aluminum pole; 

• Parking lots – 0.1 FC intensity utilizing two 250-watt HPS type fixtures mounted on a 30-

foot-tall aluminum pole; and 

• Plant roadway – 0.4 FC intensity utilizing one 400-watt HPS type fixture mounted on a 

30-foot-tall aluminum pole. 

Instrument and Plant Air System 

A utility air system would be provided, composed of air compressors and receivers, to supply 

compressed air for plant and instrument air requirements. Plant air would be used to power tools 

and equipment. Two rotary screw type, air-cooled compressors would be used as part of the 

utility air compressor package. The air receivers get cool, moist air from the compressors, and 

separate out free water from the plant air. From these receivers, air would flow either to the air 

distribution header or the instrument air system. The air plant would be located on the east side 

of the process area, north of the SCVs. 

Dry instrument air would be used for the instrumentation and control systems at the terminal. 

The source of instrument air would be through the use of dew point control equipment on the 

main plant air supply system. One instrument air receiver would be located near the unloading 

arms, while a second would be in the process area. Air from the receivers would be routed from 

the instrument air pre-filters, to the air driers that would reduce the dew point of the air to –40°F, 

and then to the instrument air after-filters. The filters would remove oil, entrained excess water, 

pipe scales, desiccant, and other particulate matter from the instrument air. 
2-33 2.0 – Description of the Proposed Action 

Nitrogen 

Nitrogen would be used throughout the LNG terminal to purge pipelines and equipment. Liquid 

nitrogen would be trucked to the terminal, stored in a tank within the plant site, and then revaporized in ambient exchangers for use in gaseous form. The nitrogen plant would be situated 

on the east side of the process area, adjacent to the south of the air plant. 

The main use of the nitrogen would be for purging the LNG unloading arms. Following 

unloading, the LNG in the unloading arm rundown piping would be drained to the desuperheater knockout drum using gaseous nitrogen. In the event that any liquid builds up in the 

de-superheater knockout drum, gaseous nitrogen would be used to push the liquids directly into 

the keep cool loop and to the LNG storage tanks through the 36-inch-diameter transfer line, or 

drain the liquids to the blow down drum. 

Process Control System 

Operators would control and monitor the facility through a distributed control system (DCS). 

Vendor-supplied packaged units with local control panels and numerous field mounted 

instruments would be connected to remote input/output (I/O) cabinets located in the facility. 

Overall plant process control and monitoring would be performed at consoles located in the 

control room with monitoring capabilities from the jetty control room. 

Service Water Systems 

The LNG terminal would be designed to provide potable water during construction and 

operation, to handle stormwater, and to dispose of wastewater. Water would also be needed 

during construction for making concrete and other purposes, hydrostatic testing of the storage 

tanks and terminal piping, and the initial filling of the SCVs. During operation, excess water 

generated by the SCVs would need to be discharged, and the firewater system would need 

periodic testing. Potable water would be used during terminal operations for equipment 

maintenance, wash-down, minor cooling applications, and domestic purposes. The source of the 

potable water would be a tie-in to the existing 12-inch-diameter water line operated by the Coos 

Bay North Bend Water Board (CBNBWB), the local water utility district. Additional 

information about water resources is provided in section 4.3 of this EIS. 

About 10 million gallons would be withdrawn from the CBNBWB pipeline to fill the firewater 

pond at the LNG terminal. During hydrostatic testing of the LNG storage tanks, about 28.25 

million gallons of water would be used, obtained from the CBNBWB through its pipeline and 

Jordan Cove’s firewater pond. The two tanks would be tested sequentially, using water from one 

to fill the other. The hydrostatic test water would be discharged from the storage tanks back into 

the firewater pond. Through an overflow, this water would be disposed of through the existing 

industrial wastewater pipeline owned by the Port that discharges into the ocean. 

Sanitary waste from the control room, administrative office, and other sources would be 

collected in a sanitary sump. Removal of solid wastes would be by a sanitary vacuum truck 

operated by an independent qualified waste disposal company hired by Jordan Cove. 

The LNG terminal facility would be designed to provide drainage of surface water to designated 

areas for disposal in accordance with 49 CFR Part 193.2173. Stormwater collected in areas that 

have no potential for contamination would be allowed to flow or be pumped directly to a system 

of stormwater ditches, which ultimately drain to the slip. Wash down and stormwater collected 
2-34 2.0 – Description of the Proposed Action 

from non-LNG containing paved and curbed areas would be collected into an oily water 

collection sump. From there it would flow through plate-type separators to remove oil and 

grease from the water. The recovered oil and grease would be held in the sump and periodically 

pumped to storage drums for disposal. The treated water would be released into the ocean 

through the Port’s industrial wastewater pipeline. Stormwater that collects within the LNG spill 

sumps would also be passed through the oil water separators, then pumped to the firewater pond 

and released into the ocean through the Port’s industrial wastewater pipeline. 

Spill Containment 

The main platform deck at the LNG carrier berth would be curbed to confine LNG spillage and 

its surface would be sloped to a collection point. Drainage from this point would be via the LNG 

spill collecting trough to the marine area impoundment basin. This basin is designed to handle a 

full guillotine rupture of the unloading arm at a rate of 12,000 m3/hr. This would result in a spill 

of 528,000 gallons in 10 minutes. 

Any accidental leakage from the LNG transfer line would be collected in a sloped 3-foot-wide, 

3-foot-deep trench, constructed of insulated perlite concrete, located below the line, which would 

drain to the marine area independent basin. This basin would be situated north of the slip, within 

the process area, on the west side of the transfer pipeline, south of the SCVs. Both impoundment 

basins would have dimensions of 65 feet by 65 feet with a depth of 20 feet, constructed of 

impregnated perlite concrete, and sized to contain a full guillotine rupture of the LNG unloading 

line. The independent basins would have available capacity to hold 622,000 gallons. 

The area around the LNG pump platform would be curbed to contain and direct any LNG spills 

to a downcomer drain on the side of the storage tanks. Spill protection would also be provided 

on the roof of the storage tanks. The storm surge barrier around the LNG storage tanks are sized 

to hold over 110 percent of the volume contained by each storage tank. Any LNG spills within 

the storm surge barrier would be directed to the process area impoundment basin, located on the 

west side of the storage tanks. 

The process area would be graded and curbed, so that any spill would flow to the process area 

impoundment basin. 

Hazard Detection and Response 

The Jordan Cove LNG terminal would contain passive and active hazard prevention and 

mitigation systems and controls. Passive systems would generally include those that do not 

require human intervention, such as spill drainage and collection systems, ignition source 

control, and fireproofing. Active systems normally are either automatic or require some action 

by an operator. 

Process instruments would routinely monitor conditions such as pressure, flow, and temperature, 

which can give an early indication of a potentially hazardous condition. In addition, specialized 

automatic hazard detection and alarm notification devices would be installed to provide an early 

warning. These detectors would sense a variety of conditions including combustible gas, low 

temperatures, smoke, heat, and flame. Each of these systems would trigger visual and audible 

alarms at specific site locations and in the control room areas to facilitate effective and 

immediate response. The Safety Instrumented System controller would allow for the sequential 

shutdown and isolation of portions of the terminal in emergency situations. Emergency 
2-35 2.0 – Description of the Proposed Action 

shutdowns would be installed at the LNG unloading area, natural gas sendout area, and on other 

equipment. 

Fire protection for the terminal would include several independent systems, based on water, 

foam, and chemical agents. The fire protection system would include: 

• pre-aimed, auto oscillating, remotely operated monitors strategically located to protect 

plant equipment; 

• remotely operated hydrant mounted firewater monitors on each LNG storage tank; 

• 18 firewater hydrants and 32 hydrant mounted firewater monitors; 

• nitrogen snuffing at the tailpipe of each LNG storage tank pressure relief valve; 

• a dry chemical system as backup at the tank relief valve tailpipe; 

• high expansion foam injection systems at each impoundment basin; 

• two elevated firewater monitors at the berth; 

• two dry chemical systems at the berth, including one fixed and one hose reel system; 

• internal suppression or standpipe systems at all buildings; 

• 16 wheeled fire extinguishers; and 

• 40 handheld portable fire extinguishers. 

2.1.4.4 Dredged and Excavated Material Disposal 

During the Port’s construction of the access channel and slip for Jordan Cove’s proposed LNG 

import terminal, about 5.6 mcy of material would be excavated or dredged. Of this, about 

1.8 mcy of material would be hydraulically dredged from the bay or below the salt water table, 

and about 2.3 mcy would be dry excavated or dredged from uplands. Additionally, up to 

1.5 mcy of material would be hydraulically dredged from the freshwater pocket in current 

uplands behind the berm that Jordan Cove/Port would use to separate this pocket from the bay. 

The Port’s estimates of excavated and dredged material volumes, by location and phase of 

dredging, are listed in table 2.1.4.4-1. 

Jordan Cove and the Port have identified several preferred locations to place the excavated and 

dredged materials. These areas include the Port Commercial Sand Stockpile site, Weyerhaeuser 

Linerboard sites, and the JCE Placement site. These sites are further described below. 

TABLE 2.1.4.4-1 

Estimated Excavated and Dredged Material Volumes

Facility Construction Phase Volume (mcy) Placement Location 

Slip Land-based excavation 1.0 Jordan Cove site and Linerboard East and West sites 

Slip Dredging in pocket behind berm 1.3 Linerboard East and West sites 

Fresh Water Phase 

Slip Dredging in pocket behind berm Up to 1.5 Port site 

Salt Water Phase 

Slip Dredging from Bay Remaining of 

1.5 Port site 

Slip Dredging to remove berm 0.5 Port site 

Access Channel Dredging from Bay 1.3 Port site 
2-36 2.0 – Description of the Proposed Action 

The dredged materials placed at these locations would be contained within earthen berms. 

Double layers of silt fencing at the toe of the dikes would restrict movement of materials. The 

exterior of the berms would be covered in erosion control matting and seeded with native 

grasses. 

During operation of the LNG terminal, it has been estimated that about 0.35 mcy of material 

would need to be dredged every 2 years for maintenance of the access channel and slip. Jordan 

Cove and the Port have indicated that their preferred location for the disposal of maintenance 

dredging materials would in the Pacific Ocean at the existing Coos Bay Site F, located about 1.7 

miles north of the Coos Bay entrance jetty. See additional discussion of Site F below. 

Alternative locations for dredged material disposal are discussed in section 3.1.6. 

In order to conduct these dredging activities, the Port would need approvals from the COE and 

ODSL, after review of its JPA, as discussed in section 1.5.2.2. The Port may also need approvals 

from ODEQ for disposal of dredged materials. The characteristics of the excavated and dredged 

sediments are discussed in section 4.2.2.2, as are the potential for encountering existing 

contaminated sediments at the disposal locations. The potential impacts of dredging activities on 

water quality and aquatic resources are discussed in sections 4.3 and 4.5. The results of wetland 

delineations at the disposal sites are discussed in section 4.3, the results of biological surveys are 

summarized in section 4.4 and 4.5, and the results of cultural resources surveys are covered in 

section 4.10. Potential noise impacts from dredging activities, potential impacts on air quality 

from trucks hauling excavated materials to disposal areas, and measures to be implemented to 

control dust from the disposal piles are discussed in section 4.11. 

Port Commercial Sand Stockpile Site 

The Port Commercial Sand Stockpile site (Port site) would be located on about 68 acres of Portowned land on the bay side of the North Spit of Coos Bay, about 1.5 miles southwest of the 

proposed Jordan Cove LNG import terminal (figure 2.1-6). It is relatively flat, vacant open land, 

with sand dunes, and minimal vegetation. This parcel is situated between the bay on the east and 

the Trans-Pacific Parkway on the west, with Southport Forest Products (Southport) to the north 

and D.B. Western manufacturing facility to the south. The site is roughly rectangular, measuring 

about 1,500 feet wide by 2,500 feet long. 

This Port site could take in about 3.3 mcy of material hydraulically dredged during the 

construction of the access channel and slip. This dredged material would be stockpiled at this 

location temporarily, until it is sold for commercial purposes and removed from the site by 

barge. There are existing docks at both Southport and D.B. Western, adjacent to the Port site. 

Potential markets for the stockpiled sand include use as fine aggregate in the production of 

Portland cement, with a potential buyer in the San Francisco Bay area. However, the amount of 

sand to be stockpiled exceeds market needs. Jordan Cove estimated that it could sell about 0.5 

mcy of sand per year, requiring about 7 years to dispose of the entire 3.3 mcy to be stored at this 

location. 

The existing surface materials at the Port site would be used for the construction of containment 

berm. The containment berm would have a crest height of 40 feet above the existing grade, and 

a crest width of 12 feet, with 3 feet vertical: 1 foot horizontal side slopes. The volume of the 

berm would be about 1.15 mcy of material. Material would be stockpiled within the berm to a 

height of about 35 feet. In the northeast corner of the Port site would be a pond retained by a 
2-37 2.0 – Description of the Proposed Action 

rock berm for return water. Heavier sands from the slurry would settle to the bottom of the 

stockpile site, while transport water would be recovered from the top surface. During initial 

freshwater dredging, overflow from the water recovery pond would be returned to the dredge 

pocket. During the saltwater dredging phase, overflow would be discharged into the bay at the 

existing barge slip serving Southport that is adjacent to the northeast corner of the placement site. 

Jordan Cove and/or the Port have developed a two-phase scenario for dredging the slip and 

transporting material from the LNG terminal to the Port site. Up to 1.5 mcy of material intended 

for the Port Commercial Sand Stockpile site would be hydraulically dredged from the upland 

portion of the slip, below the freshwater groundwater level, behind the berm separating this 

pocket from the bay. Slurry and return water from this freshwater phase of slip construction 

would be transported to and from the terminal and the Port site via overland pipelines. Materials 

hydraulically dredged from the remainder of the slip and the access channel within saltwater 

portions of the bay would be transported to the Port site by a slurry pipeline in the bay. The Port 

estimated that it would take a little more than 8 months to fill this stockpile area with materials 

dredged during creation of the access channel and slip. 

The hydraulic slurry line and return water line for the freshwater phase of slip dredging would 

each be 3 miles in length (figure 2.1-13). Both the slurry and return water lines would consist of 

SDR 32.5 20-inch-diameter high-density polyethylene heat fusible pipe, greater than 0.492 inch 

in thickness. These pipelines would be laid on the ground surface adjacent to the Trans-Pacific 

Parkway and the existing railroad. These pipelines would cross over the parkway and railroad on 

temporary structures designed to provide clearance for trucks and rail cars. These temporary 

structures would be constructed within the Jordan Cove terminal parcel and transported by truck 

to the crossing locations for assembly. The plastic pipe would be laid out in sections along the 

route, and then fused together, with sandbags used to hold the lines in place. A flatbed truck and 

fork lift loader would be needed for construction and disassembly after use. Once this phase of 

dredging is completed, the lines would be cut apart, loaded onto trucks for removal, together 

with crossing structures and sandbags, and disturbed areas restored and revegetated. 

The hydraulic slurry line to the Port site to be used during the saltwater phase of the slip 

construction would be about 1.3 miles in length. It would consist of 20-inch-diameter highdensity polyethylene pipe, laid within Coos Bay, to the west of the navigation channel. Sections 

of the slurry pipeline would be fused onshore, and towed out into the bay with a work boat where 

floatation would be attached. Alternatively, the pipeline would be assembled on the dredge. In 

order to maintain the pipeline out of the way of traffic in the bay, it would have lines attached 

and anchored approximately 50 feet from the shoreline by anchor lines spaced at approximately 

300-foot intervals, with anchor points on shore. Other than the workboat, a flat bed truck and 

fork lift loader would be necessary during construction and removal of the slurry pipeline. Upon 

completion of the dredging activities, the pipeline would be towed to shore, or back to dredge, 

floatation removed, and the pipe cut and loaded on the flatbed truck for disposal. 
2-38 2.0 – Description of the Proposed Action 

Figure 2.1-13 Location of Port Site Dredged Slurry Pipelines 
2-39 2.0 – Description of the Proposed Action 

Weyerhaeuser Linerboard Sites 

The Weyerhaeuser Linerboard sites, occupying a former industrial area totaling about 110 acres, 

are located on the bay side of the North Spit of Coos Bay, north and east of the geographic 

indentation of the bay known as Jordan Cove (figure 2.1-6). The Linerboard sites are on 

property currently owned by Weyerhaeuser that the Port has an agreement to purchase. This is 

relatively flat, currently vacant, sparsely vegetated open land. The Menasha Corporation built a 

paperboard mill at this location in 1961. The mill was sold to Weyerhaeuser in 1983, and was 

closed in 2003. Most of the mill buildings have been demolished, but there is still an existing 

concrete slab within the area for the Linerboard East site that would be broken up in place. Also 

within the Linerboard East site is an existing Pacific Power and Light Company (PP&L) 

electrical substation that would need to be relocated. There are two existing industrial 

wastewater ponds located adjacent outside to the east of the Linerboard West site. The 

Linerboard West site overlies an actively permitted solid waste disposal facility, and use of this 

site for dredged material disposal would require coordination with ODEQ to permanently close 

the permitted solid waste disposal facility. 

The Weyerhaeuser Linerboard sites combined could accommodate a total of about 1.8 mcy, of 

which 0.49 mcy of dry excavated material would be used to construct the berms at the placement 

areas, and 1.31 mcy would be deposited via a slurry pipeline transporting hydraulically dredged 

materials from the Port’s access channel and slip at the LNG terminal. This material would be 

excavated and dredged from current uplands, to create the slip in the freshwater portion of the 

pocket behind the berm separating it from the bay during construction. 

The Linerboard West site would include 14 acres within the containment berm of 3,000 linear 

feet. It would hold a total of 0.36 mcy of material, of which about 0.14 mcy would be dry 

excavated material used to create the berm, and could receive an additional 0.22 mcy of 

excavated or dredged material. The Linerboard East site would include 52 acres within a 7,500 

linear foot long containment berm, with a total capacity of 1.44 mcy. About 0.35 mcy of 

excavated dry material would be used to construct the berm, with the interior cell able to receive 

an additional 1.09 mcy of excavated and dredged material. The berms would be about 19 feet 

high above current grade, and 10 feet wide at the top, with slopes of 3 feet vertical: 1 foot 

horizontal. 

On the west side of the Linerboard East site would be a primary settlement basin with an 18-

foot-high sump dike, to hold water for the return pipeline. Water used in the slurry for the 

hydraulic dredged material would be returned to the LNG terminal slip area, after the dredge 

sands settle out in the cells at the placement areas. This return water would help float the dredge 

in the pocket behind the berm. 

The dry material excavated from upland portions of the slip, to be used to construct the berms at 

the Weyerhaeuser Linerboard sites, would be transported there from the LNG terminal slip by 

dump trucks on existing roads. The total length of the truck haul roads would be 2.4 miles, 

within a transportation and utilities corridor on land either owned by the Port or leased by Jordan 

Cove from Roseburg. The Port anticipates that it would take almost 7 months to build the berms, 

and another almost 4 months to complete dredging of the freshwater portion of the slip. The Port 

estimates it would require two trucks, making as many trips as possible on a daily basis, for the 7 

months. 
2-40 2.0 – Description of the Proposed Action 

The hydraulically dredged material slurry and return water would be transported in temporary 

pipelines, about 1.7 miles long between the Jordan Cove LNG terminal and the Linerboard 

disposal sites. The pipelines would be constructed of 20-inch-diameter high-density heat fusible 

polypropylene pipe sections laid on the ground surface following the excavated material trunk 

route across the Roseburg industrial property. Jordan Cove Road would be bored for the Pacific 

Connector pipeline exiting the LNG terminal, and the slurry and return water lines would be colocated with the Pacific Connector pipeline bore under the road. The slurry and return water 

lines would be strung out using a flatbed truck and fork lift, and held in place, once fused, with 

sandbags. After the slip is constructed, the slurry and return water lines would be removed, and 

disturbed areas restored and revegetated. 

JCE Placement Site 

The JCE Placement site would be located within the parcel to be acquired from the Port by 

Jordan Cove (figure 2.1-6). Up to about 0.5 mcy of dry material excavated by the Port during 

construction of the LNG terminal slip would be stored at the JCE Placement site. Scrapers and 

excavators would be used to remove the material from the slip, and it would be transported to the 

placement area by dump trucks on roads within the Jordan Cove LNG terminal tract. The Port 

estimated it would take less than 3 months to complete this stockpile while excavating the slip. 

Use of this site would require consultation with ODEQ because of use in the past for ash disposal 

by Weyerhaeuser. 

The Port would actually move this material twice within the northern portion of Jordan Cove 

LNG terminal tract. Temporarily, the material excavated from the slip would first be stockpiled 

on the east edge of Henderson Marsh, south of the Trans-Pacific Parkway and railroad. This socalled grubbing stockpile, on the west side of the terminal access road extending from the TransPacific Parkway to the slip, would be surrounded by temporary berm consisting of a single layer 

of hay bales sandwiched between two layers of silt fence, for erosion control. 

Once use of the concrete batch plant is finished, and it is removed from the area directly north of 

the LNG storage tanks, on the east side of the terminal access road to the slip, this would be the 

permanent location for the JCE Placement site. The permanent placement site would be within a 

10-acre area, that is currently relatively flat, open vacant land, vegetated by grasses and brush. 

The JCE Placement site would cover an area roughly 800 feet by 750 feet in dimension. The 

stockpile of dry excavated material would be about 30 feet high, with slide slopes of 1.5 feet 

horizontal: 1.0 foot vertical. The permanent placement site would be an extension of the 

existing sand dune on the east side of the property, but would be outside of a wetland area at the 

northeast corner of the Jordan Cove terminal tract. The material would be contoured and 

stabilized, and would not require a berm. The permanent placement site would be revegetated 

with native grasses to achieve conditions that would not be attractive as nesting habitat for 

snowy plovers. 

Coos Bay Site F 

Coos Bay Site F is located in the Pacific Ocean, about 1.75 miles north-northwest of the north 

jetty at the mouth of Coos Bay (figure 2.1-14). The site is owned by the State of Oregon out to 
2.0 – Descr

2-41

Figure 2.1-14. Location of Coos Bay Entrance Site F Dredged Material Disposal 
2-42 2.0 – Description of the Proposed Action 

the 3-mile territorial limit, and the remainder by the COE. This is an existing EPA-approved 

offshore placement site, used by the COE since 1986 to disposal of materials dredged during 

maintenance of the Coos Bay navigation channel, in accordance with section 103 of the Marine 

Protection, Research, and Sanctuary Act (MPRSA). The site was expanded in 1989, 1995, and 

2006, so that it now encompasses about 3,075 acres, with water depths ranging from 20 to 160 

feet. 

The Port intends to use a clamshell dredge for maintenance dredging of the access channel and 

slip at the LNG terminal. The clamshell dredge would place materials onto an adjacent scow 

anchored in the bay. The scow would then be towed by ocean-going tugs to Site F, a distance of 

about 9 nautical miles from the LNG terminal. Dumping of the Jordan Cove LNG terminal 

maintenance dredge material would occur during in-water work windows established by the 

ODFW. The COE has indicated to the Port that this site has the capacity to take in the 

operational maintenance dredging of the LNG terminal access channel and slip, which over 20 

years would be a total of about 3.5 mcy of material. 

2.1.5 Pacific Connector Pipeline and Associated Aboveground Facilities 

Pacific Connector proposes to construct and operate a high-pressure underground welded steel 

natural gas pipeline, and associated aboveground facilities. The pipeline would begin at Jordan 

Cove’s proposed LNG terminal, and traverse parts of Coos, Douglas, Jackson, and Klamath 

Counties, Oregon, to its end point near Malin, Oregon at the Oregon-California border. These 

facilities are shown on detailed maps included in Appendix D and described below. 

All facilities would be designed, constructed, tested, operated, and maintained to conform with 

or exceed DOT requirements found in 49 CFR Part 192, Transportation of Natural and Other 

Gas by Pipeline: Minimum Safety Standards; the FERC requirements at 18 CFR 380.15, Site and 

Maintenance Requirements; and other applicable federal and state regulations. 

2.1.5.1 Pipeline 

Pacific Connector proposes to construct and operate a 234-mile-long, 36-inch-diameter high 

pressure, welded steel underground natural gas pipeline. The maximum allowable operating 

pressure (MAOP) of the pipeline would be 1,440 psig. Because it would be an interstate natural 

gas pipeline, federal law does not require that Pacific Connector odorize the gas transported 

through the proposed pipeline. Pacific Connector would odorize the gas only where it would be 

delivered into local distribution pipeline systems at the Clarks Branch, Shady Cove, and Tule 

Lake/Russell Canyon/Buck Butte Meter Stations. The pipeline would be adjacent to existing 

powerline, road, and other pipeline rights-of-way for approximately 90 miles (39 percent of its 

length), with the remaining distance being newly created “green-field” right-of-way. Table E-1 

in Appendix E lists locations where the Pacific Connector pipeline would be adjacent to existing 

rights-of-way. 

Since publication of the draft EIS, Pacific Connector has changed its proposed route at 18 

locations in response to staff recommendations made in the draft EIS. These route modifications 

are discussed in more detail in section 3.4.2. 

The pipeline would originate at MP 0.0 at the Jordan Cove Receipt Meter Station located within 

the proposed Jordan Cove LNG terminal, on the North Spit of Coos Bay in Coos County, 

Oregon. The first 11.4 miles of the proposed route has changed since publication of the draft 
2-43 2.0 – Description of the Proposed Action 

EIS. The pipeline would extend east from the LNG terminal, passing through the Weyerhaeuser 

Linerboard site, and entering Haynes Inlet at about MP 1.7. The pipeline would be installed for 

about 2.4 miles in Coos Bay, existing to the north of the Glasgow peninsula at about MP 4.1. It 

would then turn southeast over hilly terrain, using a conventional bore to cross Kentuck Slough 

at about MP 6.3, and proceeding to Graveyard Point, where it would rejoin the September 2007 

proposed route at MP 11.4/7.6. The pipeline would cross under the Coos River at about MP 8.1 

using a horizontal directional drill (HDD; see section 2.4.2.2 of this EIS). 

Between about MPs 12.8 and 26.1, the pipeline would generally follow the existing Bonneville 

Power Administration (BPA) powerline. The alignment deviates slightly from the BPA corridor 

at about MP 21.6 to avoid side slopes and an electrical substation, and to provide a better 

crossing of the North Fork of the Coquille River. Pacific Connector made a slight pipeline 

adjustment from its September 2007 application route for the crossing of the East Fork of the 

Coquille River near MP 29.8, to avoid marbled murrelet (MAMU) habitat and an occupied stand. 

The pipeline would then proceed for approximately 19 miles in a southeasterly direction along 

ridgelines within the Coast Range (over which the pipeline would traverse to about MP 67) and 

follow existing logging roads, where feasible, before entering into the Camas Valley at about MP 

49.5. The pipeline would cross into Douglas County at MP 45.7. 

This segment of pipeline would cross parcels of BLM-administered land within the Coos Bay 

District, Umpqua and Myrtlewood Resource Area between MPs 17.0 and 27.5, and 28.4 and 

45.7. The pipeline would cross tracts of BLM-administered land within the Roseburg District, 

South River Resource Area between MPs 46.8 and102.3. 

Between MPs 23.5 and 47.0 the pipeline was routed to avoid geologically unstable areas with 

landslide potential. Near MPs 30.3, 31.7, 36.1, and 45.2 Pacific Connector made slight pipeline 

adjustments from its September 2007 application route to avoid MAMU stands. The initial 

route, proposed in May 2006 during Pre-filing review, was modified by Pacific Connector 

between MPs 31.4 and 32.2 to avoid an Oregon State University Red Alder Test Plot on BLM 

land. Between MPs 43.0 and 44.7 the pipeline was sited to avoid the BLM’s Coos Bay District’s 

Rock Creek Area of Critical Environmental Concern (ACEC). The initial May 2006 route was 

changed between MPs 47.6 and 49.5 to avoid multiple crossings of Deep and Wildcat Creeks. 

Between MPs 51.5 and 52.1 Pacific Connector revised its September 2007 route in response to 

staff recommendation 23 in the draft EIS to avoid MAMU stands. Near MP 57.8 the route was 

modified to avoid a population of Kincaide’s lupine, in accordance with staff recommendation 

39 in the draft EIS. 

The proposed pipeline would continue east across the Camas Valley, crossing Highway 42 at MP 

51.7 south of Camas Mountain State Park, and then along ridgelines parallel and south of 

Highway 42 and Shields Creek to the Olalla Valley at about MP 56.0. Based on landowner 

concerns, the pipeline route between MPs 59.6 and 67.0 was aligned to minimize potential 

easement encumbrances by traversing primarily timberlands along ridgelines and away from 

residential areas. The alignment in this area attempted to minimize impacts on agricultural lands, 

shallow ground water, domestic water supplies, and a subdivision (see discussion of 

Olalla/Dillard Alternative in section 3.4.2.6). 

The pipeline would make its first crossing of the South Umpqua River near MP 69.0, then cross 

under I-5, and proceed mostly along ridges. Between North Myrtle Creek, which the pipeline 

would cross at about MP 79.2, and Days Creek, which would be crossed at about MP 88.6, 
2-44 2.0 – Description of the Proposed Action 

Pacific Connector moved its pipeline from its original May 2006 route to avoid rural residences, 

pasture, and waterbodies in the Days Creek valley (see Woods Cree/Days Creek Route Variation 

in section 3.4.2.10). Near the community of Milo, the pipeline would make its second crossing 

of the South Umpqua River at about MP 94.7, and west of Callahan Ridge it would enter into the 

Tiller Ranger District of the Umpqua National Forest near MP 99.3. The alignment would cross 

over Green Butte near MP 100.4, then over Neauman Gap at MP 105.4, before following 

Wildcat Ridge offset from Forest Road 32, and passing south of Drew Lake near MP 108.7, and 

exiting the Umpqua National Forest at about MP 113.2. Pacific Connector changed its 

September 2007 route between MPs 108.5 and 110.9 in accordance with staff recommended 

condition 26 in the draft EIS, to avoid the Peavine Quarry and northern spotted owl (NSO) nest 

patches (see section 3.4.2.12). 

The pipeline would enter into Jackson County at about MP 109.7. The route would cross parcels 

of BLM-administered land within the Medford District, Ashland, and Butte Falls Resource Areas 

between MPs 115.1 and 141.9 and MPs 148.7 and 153.8. 

Near the community of Trail, the pipeline would cross under Highway 62 and the Rogue River at 

about MP 122.6 using an HDD. The pipeline would then proceed in a southeasterly direction, 

passing south of Indian Lake Reservoir near MP 128.0. Between about MPs 128.4 and 130.6, 

Pacific Connector sited the proposed pipeline to minimize impacts on wetland pastures along 

Indian Creek, and to avoid a private airfield south of Mucky Flat that may be expanded in the 

future by the landowner. 

The pipeline would cross the Butte Falls Highway at about MP 132.5. Between about MPs 

132.6 and 133.0 the initial May 2006 route was modified to avoid a future home site on the 

Mitchell Creek Ranch. At about MP 133.4 the pipeline would cross the Medford Aqueducts, and 

between about MPs 135 and 137, on the west side of Obenchain Mountain, the pipeline was sited 

to avoid a drainage, springs, and wet pasture lands. 

The proposed pipeline would pass east of Star Lake Reservoir at about MP 141.0, be east of 

Meyers Hill in the vicinity of MP 144.0, and cross Highway 140 and the North Fork of Little 

Butte Creek at about MP 146. Between about MPs 143.7 and 147.5 the pipeline would cross the 

C2 Ranch, on which there are numerous irregularly shaped conservation easements held by the 

Southern Oregon Land Conservancy. Pacific Connector changed its September 2007 route 

across the C-2 Ranch to avoid impacts on conservation easements and irrigated pastures in 

accordance our recommended condition 27 in the draft EIS (see section 3.4.2.14). 

The pipeline would continue easterly over Heppsie Mountain near MP 152.0. At the request of 

the BLM Medford District, Pacific Connector modified its proposed route between about MPs 

150.4 and 150.7 to minimize impacts on the existing Heppsie Mountain rock quarry. 

Between about MPs 153.8 and 167.9, the pipeline would be within the Ashland Ranger District 

of the Rogue River-Siskiyou National Forest, and from about MP 167.9 to 175.4 it would cross 

through the Klamath Ranger District of the Fremont-Winema National Forest. The pipeline 

would be routed south of Robinson Butte near MP 159.0, past Big Elk Meadow between MPs 

161.0 and 162.0, cross the South Fork of Little Butte Creek at about MP 162.4, skirt the north 

side of Cox Butte, go through Daley Prairie between MPs 164 and 166, and cross Dead Indian 

Highway at about MP 168.9. As requested by the USFS, Pacific Connector changed its 
2-45 2.0 – Description of the Proposed Action 

September 2007 route between about MPs 161.1 and 161.6 to avoid the Big Elk NSO patch, in 

accordance with our recommended condition 36 in the draft EIS (see section 3.4.2.15). 

The pipeline would enter Klamath County at about MP 166.4. In accordance with our 

recommended condition 28 in the draft EIS, Pacific Connector changed the September 2007 

pipeline route between MPs 167.6 and 168.2 to reduce visual impact at the crossing of the 

Pacific Crest Trail (PCT) on NFS land (see section 3.4.2.16). 

The pipeline route would cross parcels of BLM-administered land within the Lakeview District 

Klamath Falls Resource Area between about MPs 176.0 and MP 216.7. At about MP 200.5 the 

pipeline would cross a parcel of BOR land. Between MPs 169.5 and 188.9 the pipeline would 

generally follow Clover Creek Road. In accordance with our condition 29, Pacific Connector 

modified its September 2007 route between MPs 171.1 and 187.4 to reduce impacts on steep 

slopes along Clover Creek Road (see section 3.4.2.17). 

The proposed pipeline would avoid the community of Keno by being adjacent to the existing 

PP&L powerline at MP 189.9, then follow a ridgeline to about MP 192. Between about MPs 

192.5 to 197.0 the pipeline would parallel a road on the north side and the existing GTN pipeline. 

Pacific Connector changed the September 2007 pipeline route between about MPs 195.4 and 

196.5 to avoid a population of Applegate milk-vetch, in accordance with staff recommended 

condition 37 in the draft EIS. The pipeline would skirt an industrial facility formerly owned by 

Weyerhaeuser between about MPs 197.0 and 199.0. It would then cross under the Klamath 

River, Highway 97, and the Southern Pacific Railroad using an HDD with an exit at about MP 

199.7. Between about MPs 200 and 211, the pipeline would mostly follow an existing BPA 

powerline. The pipeline would cross about 27 irrigation facilities under BOR jurisdiction 

between MPs 200.5 and 214.2 and would cross the Lost River at about MP 212.0, and then rejoin 

the BPA powerline at about MP 215.0. Pacific Connector decided to deviate from the powerline 

corridor between MPs 211.6 and 215.0 because of geotechnical concerns. 

The pipeline would continue east adjacent to the powerline for about 10.5 miles to MP 225.5, 

where it would turn south, and at MP 228.2 would begin to parallel the existing GTN pipeline. It 

would follow the GTN right-of-way for about 3 miles to its terminus and interconnections with 

GTN, Tuscarora, and PG&E adjacent to the Oregon/California state line. 

2.1.5.2 Aboveground Facilities 

The new aboveground facilities proposed by Pacific Connector include one compressor station, 

six meter stations (three co-located at one site), five pig launcher/receiver assemblies (four colocated with compressor or meter stations), and 16 MLVs (four co-located with compressor or 

meter stations). Examples of aboveground facilities are shown in figures 2.1-15 and 2.1-16. 

Butte Falls Compressor Station 

The Butte Falls Compressor Station would be at MP 132.1 along the Pacific Connector pipeline, 

in Jackson County, Oregon, about 6.4 miles west of the community of Butte Falls. The 

compressor station would occupy about 7.39 acres of privately owned land that is currently 

forest and range, at an elevation of about 1,783 feet above MSL. There is an existing barn 

located adjacent to the proposed meter station on the east. An existing two-track dirt road 

leading to the barn would be improved for about 1,476 feet by 25 feet wide, to serve as a 

permanent access road from Butte Falls Road to the station. A 5-foot-wide corridor next to the 
2-46 2.0 – Description of the Proposed Action 

Figure 2.1-15. Example Compressor Station and Meter Station 
2-47 2.0 – Description of the Proposed Action 

Figure 2.1-16. Example Pig Launcher and Mainline Valve 
2-48 2.0 – Description of the Proposed Action 

access road would be used to provide phone service and commercial three-phase power to the 

station. The entire station would be surrounded by a 7-foot-high fence, and the ground would be 

covered by gravel. 

The Butte Falls Compressor Station would consist of two new Solar Taurus 70-10302S turbinedriven Solar C452 centrifugal compressor units. Maximum site rating of the Taurus 70 turbine is 

11,834 hp at 1,800 feet of elevation and a temperature of 0°F. The compression units would be 

installed in a new building, and each unit would include an inlet filter/separator, lube oil cooler, 

inlet air silencer/cleaner, and exhaust system. The compressor building would also include skidmounted fuel gas conditioning, measuring, and regulation equipment. Related suction and 

discharge piping headers would be installed between the pipeline and the compressor units. 

Other structures to be constructed within the compressor station would include a new 

office/control/ancillary equipment building, and two unit valve skid buildings. The ancillary 

equipment building would contain an air compressor system, hot water boiler, and back-up 

generator. The station would also include a high pressure vent system with silencer in case of a 

blow-down event. A pig launcher and receivers would be located in the northeast corner of the 

station, next to the pipeline. Proposed aboveground facilities are listed in table 2.1.5.2-1 and 

described below. 

The office building would include phone and computer access. The station would be utilized as 

a maintenance base for the proposed pipeline facilities. Adjacent on the east side of the office 

building would be a 160-foot-high self-supporting communication tower, without guy wires. 

The station would not be manned 24 hours per day, but would have emergency line pipe, spare 

parts, portable equipment such as blow-down silencers, and small hand tools stored on site. The 

station would also be equipped with exterior lighting; however, except for short periods during 

the winter when day-light hours are shorter, the lights would be infrequently used for 

unscheduled night-time work or maintenance. 

There are approximately 70 structures that can be considered noise-sensitive areas (NSA) within 

a 1-mile radius of the Butte Falls Compressor Station. The nearest house is approximately 1,900 

feet from the center of the station, but this dwelling is currently unoccupied. The next two 

closest other residences are over 2,000 feet from the center of the station. 

Jordan Cove Receipt Meter Station 

The Jordan Cove Receipt Meter Station would be within the Jordan Cove LNG terminal tract, in 

Coos County, Oregon, at MP 0.0 for the Pacific Connector pipeline. The meter station would 

cover about 2.25 acres of currently open, sparsely vegetated land, north of the existing Roseburg 

industrial facility. Access to the site would be from the existing Jordan Cove Road. Pacific 

Connector would install two buildings within the meter station. One building within the meter 

station would be used to house the gas and sulfur chromatographs, while another building would 

contain the control valves and ultrasonic equipment. A pig launcher and block valve would also 

be located within the meter station facilities. A 140-foot tall, self-supporting steel tower would 

be erected at the meter station to provide a communications link with the gas control monitoring 

system operated by Pacific Connector’s managing company out of Salt Lake City, Utah (see gas 

control communication system below). The ground at the meter station would be covered by 

gravel, and the site would be enclosed by a 7-foot-high chain-link fence. Existing power and 

phone service is available. 
2-49 2.0 – Description of the Proposed Action 

TABLE 2.1.5.2-1 

Pacific Connector’s Proposed Aboveground Facilities 

Facility MP County 

Ownership/ 

Jurisdiction 

Jordan Cove Receipt Meter Station, MLV #1, Launcher & Communications 

Tower 0.00 Coos Private 

MLV #2 (Coos River Highway) 7.70 Coos Private 

MLV #3 (South Sumner Road) 17.25 Coos BLM 

MLV #4 (Dora Ridge Road) 28.42 Coos BLM 

MLV #5 (Upper Camas Road) 49.72 Douglas Private 

MLV #6 (South of Olalla Creek) 59.58 Douglas Private 

Clarks Branch Meter Station, MLV #7, Launcher/Receiver & Communications 

Tower 69.70 Douglas Private 

MLV #8 (BLM Road 30-3-34.1) 94.60 Douglas Private 

MLV #9 (BLM Road 30-1-5.0) 115.39 Jackson BLM (O&C)/Private 

Shady Cove Meter Station & Communications Tower 122.10 Jackson Private 

Butte Falls Compressor Station, MLV #10 & Launcher/Receiver & 

Communications Tower 132.10 Jackson Private 

MLV #11 (Gardener/Salt Creek Road) 145.19 Jackson Private 

MLV #12 (Clover Creek Road) 169.48 Klamath Private 

MLV #13 & Launcher/Receiver site 187.43 Klamath Private 

MLV #14 (Midland Highway Crossing) 199.70 Klamath Private/BOR 

MLV #15 (Hill Road) 214.35 Klamath Private 

Tule Lake, Russell Canyon and Buck Butte Delivery Meter Stations, MLV 

#16, Receiver & Communications Tower 230.90 Klamath Private 

Clarks Branch Delivery Meter Station 

The Clarks Branch Delivery Meter Station would be at MP 69.7 along the Pacific Connector 

pipeline, in Douglas County, Oregon. At this location, Pacific Connector would interconnect to 

the existing Williams Northwest’s Grants Pass Lateral. The meter station would cover about 

1.02 acres of privately owned land that is currently pasture, adjacent to Dole Road to the east and 

Weigle Road on the north. Access to the station would be from Weigle Road. Existing power 

and phone service is available to serve the meter station. Pacific Connector would erect two 

buildings within the meter station, one to house BTU chromatograph, communications 

equipment, and a flow computer; and another to contain control valves, meters, odorizing 

facilities, and a pig launcher and receiver. A 26-foot-tall, self-supporting steel communications 

tower would also be installed. The station would be graveled, enclosed by a 7-foot-high chainlink fence, and would be equipped with exterior lighting for use when the station is manned. 

However, most of the time the facility would be remotely operated, and would not require a fulltime operator. 

Shady Cove Delivery Meter Station 

The Shady Cove Delivery Meter Station would be at MP 122.1 along the Pacific Connector 

pipeline, in Jackson County, Oregon, on the west side of the Rogue River, south of the 

community of Trail, and about 1.5 miles north of the town of Shady Cove. The meter station 

would deliver gas to Avista’s local distribution system. The meter station would occupy a site of 

approximately 3.08 acres, which is currently pasture, north of Old Highway 62. Existing power 

and phone service is available at the location, and access would be by way of Old Highway 62. 

The station would be enclosed by a 7-foot-high chain-link fence, and the entire site would be 

graveled. Pacific Connector would erect two buildings within the meter station, one to house 
2-50 2.0 – Description of the Proposed Action 

BTU chromatograph, communications equipment, and a flow computer; and another to contain 

control valves and meters, to reduce noise from the station. Odorizing facilities would also be 

located at the meter station. A 26-foot-tall, self-supporting steel communications tower would 

be installed. The station would be equipped with outside lighting; however, these lights would 

only be utilized when the station is manned. 

Tule Lake, Russell Canyon, and Buck Butte Meter Stations 

The Tule Lake, Russell Canyon, and Buck Butte delivery meter stations would be co-located 

together at the terminus of the Pacific Connector pipeline at MP 230.9 in Klamath County, 

Oregon, approximately 2.7 miles southeast of Malin. The meter stations would be situated 

within a 6.6 acre tract of agricultural land, currently planted in alfalfa, immediately north of 

County Road 108A, which lies on the Oregon/California state line, and just east of Old Alturas 

Highway (Highway 114). Existing power and phone service is located along County Road 

108A. Access would also be from County Road 108A. The entire tract would be surrounded by 

a 7-foot-high fence, and the ground would be covered by gravel. 

Pacific Connector would construct several buildings within the tract. There would be an office 

with phone and computer access in one of the buildings. Another building would be required for 

control valves and meters. A gas separator would be installed to ensure that the gas is free of 

oils, condensates, and other liquids. The site would have a pig receiver and odorizing facilities. 

A 26-foot tall self-supporting steel communications tower would be erected within the station. 

The station would be equipped with outside lighting for infrequent night-time operations; 

however, these lights would only be utilized when the station is manned. 

The Buck Butte Delivery Meter Station would provide natural gas to the existing GTN system, 

with the interconnection within the station. The Russell Canyon Delivery Meter Station would 

provide natural gas to the existing Tuscarora system, with the interconnection within the station. 

The Tule Lake Meter Station would provide natural gas to the existing PG&E system. However, 

PG&E would need to construct and operate the interconnection (see discussion in section 2.2.3). 

Mainline Block Valves 

MLVs would be located along the Pacific Connector pipeline according to DOT’s spacing 

requirements (CFR 192.179). There would be a total of 16 MLVs along the proposed pipeline 

route, of which 4 would be co-located at meter stations and the compressor station. The MLVs 

along the pipeline would occupy a 50-foot by 50- foot (0.06 acre) area within the right-of-way, 

which would be covered by gravel and enclosed by a 7-foot-high chain-link fence. Pacific 

Connector attempted to locate the MLVs adjacent to existing roads to minimize the length of 

new permanent access roads. Pacific Connector would paint the aboveground piping at the 

MLVs green unless otherwise dictated by permit conditions. Generally, MLVs would be 

manually operated. 

Pig Launchers/Receivers 

Pig launchers and receivers would allow Pacific Connector to maintain the interior of its pipeline 

using remotely operated pipe inspection and cleaning tools (known as “pigs”). Pacific Connector 

proposes to install four pig launchers, at the Jordan Cove Receipt Meter Station, Clarks Branch 

Delivery Meter Station, Butte Falls Compressor Station, and MLV #13 at MP 187.43. At the 

latter location, the pig launcher and receiver assembly combined would occupy an area 100 feet 

by 200 feet (0.46 acre) in size. There would be four pig receivers located at the Clarks Branch 
2-51 2.0 – Description of the Proposed Action 

Delivery Meter Station, Butte Falls Compressor Station, MLV #13, and the Tule Lake/Russell 

Canyon/Buck Butte Deliver Meter Station complex. 

Gas Control Communications 

Pacific Connector entered into agreements with Williams Pacific Connector Gas Operator, LLC 

(Williams Pacific Operator) to design, construct, operate, maintain, and manage the everyday 

business affairs of the pipeline. This includes general communications, and remote operations of 

meter stations and other related facilities (including MLVs). Pacific Connector would need to 

use a total of 13 radio communication towers to link the pipeline with Williams Pacific Operator 

control in Salt Lake City, Utah. Five new communication towers would be erected at the Jordan 

Cove Receipt Meter Station, Clarks Branch Delivery Meter Station, Shady Cove Delivery Meter 

Station, Butte Falls Compressor Station, and the combined Tule Lake/Russell Canyon/Buck 

Butte Deliver Meter Station complex. In addition, Pacific Connector would utilize the existing 

communication tower on Harness Mountain, in Douglas County, Oregon, that currently serves 

the Williams Northwest Grants Pass Lateral. To complete its communication system, Pacific 

Connector expects to be able to lease space on seven existing towers operated by other entities. 

Locations of proposed new towers, and existing towers that Pacific Connector assumes would be 

available for leasing space are listed in table 2.1.5.2-2 and shown on figure 2.1-17. 

TABLE 2.1.5.2-2 

Proposed and Existing Gas Control Communication Towers

Site Name County Tower Height (feet) Ownership/ Jurisdiction 

Proposed New Towers 

Jordan Cove Meter Station Coos 140 Private 

Clarks Branch Meter Station Douglas 26 Private 

Shady Cove Meter Station Jackson 26 Private 

Butte Falls Compressor Station Jackson 160 Private 

Tule Lake, Russell Canyon, Buck Butte 

Meter Stations Klamath 26 Private 

Williams Northwest Existing Communication Tower Site 

Harness Mountain Douglas 150 Private 

Blue Ridge Coos 170 BLM 

Kenyon Mountain Coos 120 BLM 

Winston Douglas 250 Private 

Starvout Creek Jackson 60 Private 

Flounce Rock Jackson 120 BLM 

Robinson Butte Jackson 125 USFS 

Stukel Mountain Klamath 100 BLM 

The BLM has indicated that co-location of communication facilities at the Blue Ridge 

communication tower site on BLM-administered land might not be possible due to the current 

right-of-way holder’s policy. Pacific Connector would need to negotiate with the right-of-way 

holder to determine if it could add additional communication equipment at this existing tower. 

In the case of the existing tower at Robinson Butte, on NFS land, the USFS may require the 

modification of the current special use permit in order to allow the addition of new 

communication equipment. 

2.2 NON-JURISDICTIONAL FACILITIES AND INTERELATED ACTIVITIES 

In addition to the facilities discussed in section 2.1, the JCE & PCGP Project would require 

construction of facilities that do not fall under the Commission’s jurisdiction. These include 

facilities at the proposed LNG terminal, activities conducted by the Port, facilities constructed to 
2-52 2.0 – Description of the Proposed Action 

Figure 2.1-17. General Location Map of Proposed and Existing Gas Control Communication Towers 
2-53 2.0 – Description of the Proposed Action 

provide utility service to various jurisdictional facilities, and natural gas delivery facilities that 

would be constructed by one local distribution company that would receive natural gas from the 

Pacific Connector pipeline. Although these facilities are not regulated by the FERC, they are 

related to the Project and their potential environmental impacts are considered in this EIS. 

2.2.1 Natural Gas Liquids Recovery at the Jordan Cove LNG Terminal 

Jordan Cove’s proposed LNG terminal would include a Btu control system that would have the 

ability to generate NGL as a byproduct of the regasification of the LNG. Jordan Cove has stated 

that it would only recover NGL if it is economically viable, and if the NGL can be transported by 

railroad to another processing plant. Rail service is currently not available because the existing 

Coos Bay rail line to the site is inactive. However, the Port planning on acquiring the rail line 

from Central Oregon & Pacific Railroad (COPR), rehabilitating the railroad, and putting it back 

into service by 2010. The Port intends to apply for a Railroad Rehabilitation and Improvement 

Financing Loan from the Federal Railroad Administration to be used as a line of credit to cover 

the costs of the railroad rehabilitation project (Oregon International Port of Coos Bay webpage). 

Recovery, storage, sale, and transport of NGL is not regulated by the FERC. However, the 

separation of the NGL would occur in the process area that is part of the jurisdictional LNG 

terminal. The removal of the NGL occurs in the de-ethanizer column and de-ethanizer boiler. 

The NGL would be maintained in these two process units and then NGL product pumps would 

move the NGL through about 1,200 feet of pipeline on a sleeper rack to a custody transfer 

metering skid that would be located adjacent to the existing Roseburg facility. 

The NGL would not be stored within the Jordan Cove terminal, but rather at a NGL storage and 

loadout facility that would be owned and operated by an as-yet unspecific future third-party 

purchaser. While Jordan Cove has had discussions with a potential third-party NGL purchaser, 

no decision has made about the precise sale arrangements. Jordan Cove has, however, identified 

a site for the NGL storage and sendout facility on industrial land within the existing Roseburg 

facility, and holds an option to purchase the site property from Roseburg. This is an area that is 

currently graded and graveled and used as a parking lot for the wood chip trucks. It is served by 

an existing but inactive rail spur and a paved road that handles the delivery of approximately 200 

wood chip semi-trailer loads per day. The total size of the NGL storage and sendout facility 

would be about 4.3 acres, including 0.8 acre for the NGL storage area, 0.5 acre for the NGL 

pipeline sleeper rack, and 3.0 acres for the rail spur and NGL rail car loading rack. The location 

of the facility is shown on figure 2.2-1. 

The NGL storage facility would contain from three to five 1,500-barrel horizontal storage tanks, 

referred to as bullets. These bullets would be similar to those used for the storage of propane at 

retail locations around the country and specifically at the two existing propane distribution 

terminals located within the North Bend city limits. The NGL storage facility would also include 

a load-out facility that would contain a rail loading rack with from one to three loading stations. 

From here the NGL would be loaded into 112J34OW-type DOT-certified railcars, typically with 

a capacity of 33,700 gallons. 

The NGLs would then be transported away from the Roseburg facility on the Port’s rehabilitated 

rail line and delivered to a rail yard in Eugene/Springfield. Because there are no fractionator 

facilities in the Pacific Northwest, the NGL would have to be shipped by rail from the 
2-54 2.0 – Description of the Proposed Action 

Figure 2.2-1. Nonjurisdictional Natural Gas Liquids Recovery at the Proposed Jordan Cove LNG 

Terminal 
2-55 2.0 – Description of the Proposed Action 

Eugene/Springfield yard to processing facilities in the central United States. Two of the largest 

existing fractionation facilities are located at Conway, Kansas and Mont Belvieu, Texas. 

At these facilities, the NGL could be separated out into ethane, propane, n-butane, and i-butane. 

Jordan Cove states there is a well-established and transparent market for these products. 

Potential environmental impacts from the construction and operation of the NGL extraction 

facilities within the Jordan Cove LNG terminal, and the NGL storage and sendout facility within 

the Roseburg property, are addressed in this EIS. However, this EIS does not further discuss the 

transportation of the NGL via the railroad network or any upgrades to that network that are 

currently contemplated by the Port independent of the proposed Project, or the fractionation 

activities that may take place at existing facilities located in Kansas and Texas. We deem the 

non-jurisdictional transportation of the NGL and its processing at existing facilities to be not 

directly related or directly interconnected to the construction and operation of the LNG terminal, 

and we have little information about these unspecified future activities at far distant locations. 

Also, there are other agencies that would regulate the transportation and processing of the NGL. 

2.2.2 Port Activities 

No facilities other than those directly related to the proposed LNG terminal are currently 

proposed by the Port at the LNG terminal site. In earlier filings with the FERC, and in its initial 

joint application to the COE, the Port identified a general cargo berth, dock, and staging area that 

would be constructed on the western side of the slip. However, in its April 23, 2008, revised 

application to the COE, the Port states that these facilities are not currently part of the proposed 

Project, and identifies them only as potential future facilities. These facilities are therefore not 

addressed in this EIS except for the discussion of potential future projects in cumulative effects 

(section 4.13). The only Port facility that is currently proposed at the western shoreline of the 

slip following construction, and that is addressed in this EIS, is a narrow gravel area covering 

about 1.7 acres. 

The potential future cargo dock, together with the Port’s proposed actions that are directly 

related to the Jordan Cove LNG terminal (slip, access channel, dredged material disposal, LNG 

carrier berth, and tug dock), make up a portion of the Port’s proposed Oregon Gateway Project. 

The Port uses the designator “Oregon Gateway” to refer to a series of phased marine and 

industrial projects that the Port is promoting on land it owns or controls on the North Spit. The 

initial phase of the project is the access channel to the LNG terminal and slip, for which the Port 

has applied for permits through its JPA. The Port has stated that if the LNG terminal is not 

authorized, or not built, the access channel and slip could still be used by some other unspecified 

customer for general cargo unloading. 

A separate future phase in the long-term development of the Oregon Gateway Project would be a 

proposed intermodal container terminal that would be located west of the Jordan Cove LNG 

terminal. The container terminal would be designed for the newest class of container ships 

entering service in the Trans-Pacific trade. The Port has been communicating with APM 

Terminals about the container terminal proposal (Oregon International Port of Coos Bay 

webpage). 

To accommodate the larger container ships that may use the proposed facilities of the Oregon 

Gateway project, the Coos Bay navigation channel would need to be widened and deepened. 

The Port is pursing the required deep draft channel modifications to support this future phase of 
2-56 2.0 – Description of the Proposed Action 

the Oregon Gateway Project through a Section 203 process with the COE, and is partnering with 

the State of Oregon to share the non-federal costs associated with the channel improvements. 

The COE would be the lead federal agency under section 203 of the Water Resources 

Development Act of 1986. On June 11, 2007, the Port received authorization from the Assistant 

Secretary of the Army-Civil Works to conduct studies necessary to determine whether such a 

project should be recommended to the U.S. Congress for authorization. Elements of the project 

include: 

• deepening the federal navigation channel in Coos Bay from its existing depth of -37 feet 

to -51 feet MLLW from the ocean entrance to the railroad bridge; 

• widening the channel from its existing width of 300 feet to 600 feet; 

• disposing of dredge materials; 

• modifying the ocean entrance jetty; and 

• restoring the bay ecosystem. 

The COE would be overseeing the production of the combined feasibility study and EIS for the 

proposed channel modifications (Oregon International Port of Coos Bay webpage). There is no 

direct connection between the Port’s planned channel improvement project and the Jordan Cove 

LNG project. However, the proposed future components of the Oregon Gateway project are 

further considered in this EIS under Cumulative Effects in section 4.13. 

2.2.3 Natural Gas Connection and Distribution Facilities 

Non-jurisdictional facilities would be constructed and operated by the companies that would 

receive natural gas from Pacific Connector. This includes facilities to be constructed by PG&E 

and Avista, which is an LDC not regulated by the FERC because its system serves customers 

inside of one state. 

2.2.3.1 Avista 

Avista is an LDC that provides natural gas service to approximately 92,400 residential, 

commercial, and industrial customers in Oregon, with the largest percentage of these customers 

located in the I-5 corridor in or near the communities of Roseburg, Grants Pass, Medford, and 

Ashland. As a provider of intrastate service, Avista is regulated by the State of Oregon Public 

Utilities Commission, not the FERC. The Pacific Connector pipeline would interconnect with 

Avista at the Shady Cove Delivery Meter Station at MP 122.1, in Jackson County, Oregon. To 

distribute natural gas it receives from Pacific Connector to its customers, Avista would need to 

construct and operate the following facilities: 

• a regulator station, line heater, and appurtenant facilities adjacent to the meter station; 

• approximately 4 miles of 12-inch-diameter high pressure natural gas distribution pipeline; 

and 

• two distribution regulator stations. 

Avista has not yet designed the facilities it would need to construct to transport the gas it would 

receive from Pacific Connector, so we do not yet know the route of the Avista pipeline. Its 

regulation stations would be located within plots approximately 10 by 20 feet in size while the 

Avista pipeline would be installed within a 30-foot-wide right-of-way easement. It is estimated 

that the facilities would temporarily impact about 14.5 acres during installation of the pipeline, 
2-57 2.0 – Description of the Proposed Action 

and permanently impact a total of about 0.01 acre for the three new regulator stations. Although 

Avista has not yet designed the pipeline, LDC pipelines are commonly installed within or 

immediately adjacent to roadways. 

The facilities constructed by Avista that would cross federal lands would be subject to review by 

the BLM and/or the FWS. At the state and local level, the Avista facilities may also be reviewed 

by the OPUC, ODSL, ODOT, ODEQ, ODWR, SHPO, and the Jackson County Parks and 

Recreation Department. Pacific Connector has stated that Avista has not yet generated any of the 

permit/approval applications or requests, and the construction period has not yet been 

determined. Because details of the Avista facilities are not known, they are addressed in section 

4.13 of this EIS under cumulative impacts. 

2.2.3.2 PG&E 

PG&E would design and build standard interconnection facilities adjacent to its existing Line 

400/401 pipeline where it would interconnect with the Pacific Connector pipeline at the Tule 

Lake Delivery Meter Station. PG&E’s new facilities would consist of: 

• new pipe to connect the Tule Lake Meter Station piping at the California/Oregon border; 

• block valves; 

• over-pressure protection; 

• check valves, if determined to be needed; 

• metering to measure actual flow on line 400 and line 401; and 

• a radio and antenna for equipment communication purposes. 

The metering and communications equipment would require a cabinet to protect equipment from 

the weather. All equipment and the protective cabinet would be contained within a fenced area 

adjacent to the Tule Lake Meter Station. Pacific Connector has stated that, other than the 

interconnection facilities described above, no expansion of the existing PG&E system would be 

necessary to handle the additional volumes of gas that would be delivered to PG&E by Pacific 

Connector. 

2.2.4 Utility Connections 

Electrical power and phone service would also be required for each of the meter and compressor 

stations. Installation of the utility connections is not regulated by the FERC. Because the meter 

stations would either be installed within the proposed Jordan Cove LNG terminal or adjacent to 

existing roads and utility service, no additional disturbance beyond what is evaluated for 

construction of the meter stations themselves would result from the utility connections. For the 

Butte Falls Compressor Station, commercial three phase power and phone lines would be 

installed immediately adjacent to Pacific Connector’s proposed 1,476-foot-long access road to 

the compressor station site. Construction and operation of these utility connections would 

require an additional 5-foot-wide corridor immediately adjacent to the road, or about 0.17 acre of 

disturbance. This additional area of disturbance falls within the area covered by Pacific 

Connector’s environmental surveys, and by agency consultations conducted for the compressor 

station site. The potential environmental impacts of this additional disturbance is evaluated in 

this EIS. 
2-58 2.0 – Description of the Proposed Action 

2.2.5 Conclusions on Nonjurisdictional Facilities 

We do not know all of the details about the nonjurisdictional facilities that may be constructed 

because of the JCE & PCGP Project, nor do we know all of the potential environmental impacts 

associated with those nonjurisdictional facilities. To ensure that potential issues are adequately 

addressed, we recommend that: 

• Prior to pipeline construction, Pacific Connector should file with the Secretary the 

following information on nonjurisdictional facilities that would be constructed as a 

result of its Project: 

a. final placement or routing and design information, including maps depicting the 

location of the facilities; 

b. documentation of consultations with the appropriate agencies and the status of 

federal, state, or local permits or approvals required for their construction and 

operation; and 

c. status and copies of agency clearances (or copies of any surveys and reports 

prepared) for wetlands, threatened and endangered species, and cultural 

resources. 

2.3 LAND REQUIREMENTS 

Tables 2.3-1 and 2.3-2 summarize the land requirements for the facilities proposed as part of the 

JCE & PCGP Project. Land requirements for each component of the Project are described 

below. Land use is further discussed in section 4.7. 

2.3.1 Waterway for LNG Marine Traffic 

The existing Coos Bay navigation channel extends from the mouth of Coos Bay to the Coos Bay 

City Docks at about CM 15.1. The channel width at the entrance mark is 1,000 feet, reducing to 

700 feet at CM 0 and 300 feet to CM 1. From CM 1 to the proposed LNG terminal site (at about 

CM 7.5, at the confluence between the Jarvis Turn and the Upper Jarvis Range) the authorized 

channel width is 300 feet. The Coos Bay navigation channel from CM 0 to the Jordan Cove 

LNG import terminal would encompass about 321 acres. About 21,120 acres would be 

overlapped within the outer limits of Zone 3 of the Zones of Concern for LNG marine traffic in 

the waterway in Coos Bay. 

The Port and Jordan Cove are not proposing to make any modifications to the existing navigation 

channel, with the exception of facilities proposed at the LNG terminal site as described below. 

The waterway is managed by the Port and regulated by the ODSL and COE, with ship traffic on 

the waterway regulated by the Coast Guard. 

Currently the navigation channel is used by about 50 commercial ships per year. More details 

about ship traffic in the navigation channel are provided in section 4.9. 

2.3.2 LNG Terminal Facilities 

Jordan Cove would locate its proposed LNG import terminal within a 159-acre parcel of open 

land that is zoned for industrial use, overlapping, in part, with the existing industrial facilities 

operated by Roseburg. Jordan Cove plans to purchase 149 acres from the Port, and has entered 
2-59 2.0 – Description of the Proposed Action 

TABLE 2.3-1 

Land Use at the Proposed Jordan Cove LNG Import Terminal

 Land Area (acres) 

Acres Affected During 

Construction 

Acres Affected 

During Operation 

LNG TERMINAL FACILITES 

Batch Plant and Roof Assembly Area (1) 13.9 4.0 13.9 a/

Access/Administration (2) 18.1 6.2 6.2 

Marine Access/Pipeway (3) 15.7 14.7 12.4 

Process Area (4) 20.3 20.3 17.6 

LNG Tank Area (5) 19.3 19.3 9.4 

Firewater Pond (6) 3.7 3.7 1.8 

Wetland Area (E1) 28.4 0.0 0.0 

Sand Dune Area (E2) 20.2 0.0 0.0 

LNG Unloading Berth Dune (E4) 13.2 2.0 0.0 

Sand Dune Area (E5) 6.0 0.0 0.0

Total LNG Terminal Property 158.8 70.2 61.3 

EASEMENT AREA 

Wetland Area (E3) 14.4 0.0 0.0 

Access Road (R1) 6.4 6.4 6.4

Total Easement Area 20.8 6.4 6.4 

CONSTRUCTION AREAS 

Construction Staging Area 31.7 31.7 0.0 

Temporary Roseburg Parking Area b/ 11.0 11.0 0.0

Total Construction Areas 42.7 42.7 0.0 

PORT FACILITIES 

Slip 47 47 47 

Access Channel 25 25 25

Total Port Facilities 72 72 72 

DREDGED MATERIAL FACILITIES 

Weyerhaeuser Site 

Haul Road and Dredge Slurry Pipeline 

Corridor to Linerboard Stockpile Areas c/ 6.3 6.3 0.0 

Weyerhaeuser Linerboard Excavated and 

Dredged Material Stockpile Area 110 66 66 

Port Site 

Dredge Slurry Pipeline to Port Sand 

Stockpile Area d/ 3 3 0 

Port Commercial Sand Stockpile Area e/ 68 68 0 f/

Total Dredged Materials Facilities 187.3 165.3 66 

NONJURISDICTIONAL FACILITIES 

NGL Storage and Rail Load Out Facility 0.5 0.5 0.5

Total Nonjurisdictional Facilities 0.5 0.5 0.5 

Grand Total: 482.1 335.1 206.2 

a/ After the Batch Plant is removed, up to 500,000 cy of dredged material from the port facilities would be placed in this site. It 

would be contoured to match surround sand dunes and vegetated with native grasses to discourage use of the site by snowy 

plovers. 

b/ Parking area located on gravel/cemented area on the adjacent Roseburg Forest Products Site. 

c/ Access Road (R1) acreage excluded to avoid double-counting affected area. Pipeline to be laid on two access roads shoulder. 

Only 0.97 acres off of access roads. 

d/ Approximate 10 foot right-of-way; pipe would be laid on the ground and stabilized with sandbags to prevent pipe movement; 

post-construction area would be revegetated as necessary. 

e/ Dredged material to be sold from site over seven years. 

f/ After dredged material is removed, Port would determine future use of site. Applicant is prepared to rehabilitate/revegetate site 

to pre-construction conditions. 
2-60 2.0 – Description of the Proposed Action 

TABLE 2.3-2 

Summary of Land Requirements for the Pacific Connector Pipeline

Facility 

Length or 

Number of 

Sites 

Land Affected 

During Construction 

(acres) 

Land Affected 

During Operation 

(acres) 

Pacific Connector Pipeline 

 Pipeline right-of-way 234.2 a/ 2,724.8 1,414.0 c/ 848.9 d/

 Hydrostatic discharge locations outside the right-of-way 7 1.3 e/ 0 

 TEWAs 1,396 1,319.3 (95.8) f/

 UCSAs 310 778.5 0 

 Rock source and disposal sites 43 55.3 (55.3 ) f/

 Contractor and pipe storage yards 38 1,312.7 0 

 Existing roads needing improvements in limited locations 

g/ 60 15.8 0 

 Temporary access roads 18 6.1 0 

 Permanent access roads 16 2.8 h/ 2.8 h/

 Aboveground facilities 17 N/A i/ 21.5 i/

Total ----- 6,216.5 1,438.3 j/

a/ Because of changes in the centerline and associated MP equations, the ending MP no longer represents the actual centerline 

length. 

c/ Assumes 75 feet (private lands), 60 feet (commercial timberlands), and 53 feet (federal lands) of new permanent easement. 

d/ Acreage affected by the 30-foot corridor where brush control would be performed during operation of the pipeline. 

e/ Small brush or trees may be cleared by a rubber-tired rotary or flail motor (brush hog) or by hand with machetes/chainsaws. No 

soil disturbance would occur. 

f/ Includes TEWAs, existing quarries, and rock source and disposal sites that may be used as permanent storage areas. The 

acreages are not included in the overall operational total because the storage areas would not be used during operation of the 

Project. 

g/ Includes those existing roads requiring widening in specific locations; does not include limbing/brush clearing or blading/grading 

for potholes. 

h/ Includes only those portions of the permanent access roads that would be outside of the construction right-of-way and permanent 

easement for the pipeline. 

i/ Construction impacts for the aboveground facilities are included in the construction impacts for the pipeline right-of-way. 

j/ Includes only those portions of aboveground facilities that would not be included within the pipeline operational right-of-way. 

into an agreement with Roseburg to purchase 10 contiguous acres. Within the 159-acre tract to 

be acquired by Jordan Cove for its LNG terminal, about 70 acres would be needed during 

construction, and about 61 acres would be used during operation. 

An additional 6.4-acre easement would be obtained from Roseburg for the access road to the 

LNG terminal, and a 14.4-acre easement would be obtained by Jordan Cove from the Port for 

thermal radiation and vapor exclusion zones. Jordan Cove would temporarily lease an additional 

area of 32 acres from Roseburg outside of the LNG terminal, to be used for temporary 

construction areas (office, laydown, fabrication, craft break/lunchroom, and parking). In 

addition, Jordan Cove would temporarily use an 11-acre parcel within the Roseburg property for 

a construction worker parking lot during construction of the terminal. Based on a revised traffic 

study completed since publication of the draft EIS, Jordan Cove no longer proposes to use a 117-

acre parcel on the south side of the McCullough Bridge for temporary construction parking. The 

Port’s actions to build and own the access channel and slip at the LNG terminal, and store 

excavated and dredged materials, and associated activities, would affect a total of about 237 

acres during construction, with 138 acres retained during operation of the Jordan Cove facility. 

The Port is proposing to construct an access channel from the existing Coos Bay navigation 

channel at about CM 7.5 to the LNG terminal, and a slip at the terminal. This access channel 

would be about 1,700 feet wide, and about 800 feet long between the navigation channel and 

shoreline. The access channel would affect about 25 acres within Coos Bay, and would require 

dredging of about 1.3 mcy of sediment from the bottom of Coos Bay. The slip and associated 
2-61 2.0 – Description of the Proposed Action 

berth facilities would be about 1,100 by 1,500 feet and affect about 47 acres. Construction of the 

slip would result in the excavation and dredging of about 4.3 mcy of material. Dredging 

activities are described in more detail in section 2.1.4. 

The Port has proposed to use three onshore areas on land it owns or controls on the North Spit to 

store materials that would dredged and excavated during construction of the access channel and 

slip. This would include the Port site, covering about 68 acres of open land; the Weyerhaeuser 

Linerboard sites, with materials stockpiled at two locations totaling 66 acres within a 110-acre 

parcel of former industrial land; and the JCE Placement site, covering about 10 acres of open 

land within the Jordan Cove terminal parcel. The sand temporarily stockpiled at the Port site 

would eventually be removed by barge, over a 7-year period, and transported elsewhere for 

commercial use. The Linerboard and JCE Placement sites would be permanent locations for 

material storage. Dry excavated materials would be transported by trucks from the slip to the 

Linerboard and JCE Placement sites. The haul route to the Linerboard storage sites would be 

about 2.4 miles long, using existing roads across industrial land owned by Roseburg and the Port, 

and temporarily affect about 6.3 acres. The slurry and return water lines between the slip and the 

Linerboard sites would be co-located with the haul road. The onshore slurry and return water 

lines between the slip and the Port Site would be about 3 miles long, laid on the ground adjacent 

to the Trans-Pacific Parkway and railroad, temporarily affecting about 3 acres. 

2.3.3 Pipeline and Associated Aboveground Facilities 

2.3.3.1 Pipeline 

Construction Right-of-Way 

Pacific Connector proposes to use a 95-foot-wide standard construction right-of-way for the 

pipeline. The construction right-of-way would provide the space required to accommodate a safe 

working surface for pipeline construction activities, the pipeline trench and spoil materials, the 

staging of the pipeline and, and a passing lane during construction for movement of equipment 

and construction crews up and down the right-of-way. Typical right-of-way cross sections are 

shown in figure 2.3-1. Approximately 90 miles (39 percent) would be constructed adjacent to, or 

partially overlapping, existing utility and transportation rights-of-way (powerlines, pipelines, and 

roads). Table E-1 in Appendix E lists locations where the pipeline would be adjacent to existing 

rights-of-ways. The amount of overlap of existing rights-of-way would depend on the right-ofway, but would be about 25 to 30 feet in most cases (table 2.3-2). At some locations, Pacific 

Connector would reduce the construction right-of-way width to 75 feet at the crossing of forested 

and scrub-shrub wetlands to minimize impacts to these resources. See additional discussion in 

section 4.4.1 of this EIS. 

Approximately 2,725 acres would be required for the construction right-of-way for the pipeline. 

Of this, about 470 acres would be on BLM land, 351 acres would be NFS lands, 7 acres would 

be BOR lands, 90 acres would be non-federal public lands, and 1,807 acres would be privately 

owned lands (see section 4.7 for more details). 

Temporary Extra Work Areas 

In addition to the standard construction right-of-way, Pacific Connector would use TEWAs 

where site-specific characteristics would require additional space for construction. Most TEWAs 
2.0 – Descr

2-62

Figure 2.3-1. Typical Pipeline Right-of-Way Cross Section 
2-63 2.0 – Description of the Proposed Action 

would be cleared of vegetation, and some would be graded as necessary to create safe work 

space for construction activities. Generally, TEWAs would be required for (but not limited to) 

the following: 

• steep slopes and side sloping areas to accommodate cuts and spoil storage requirements; 

• bore pits and spoil storage at road and railroad crossings; 

• spoil storage, staging, and construction of specialized pipeline drag sections such as at 

wetland crossings, residential/industrial areas, and road crossings; 

• waterbody and wetland crossings; 

• pipe and equipment staging; 

• areas where tie-ins or factory bends require additional trench widths to allow workers to 

enter the trench and perform welds and to ensure Occupational Safety and Health 

Administration (OSHA) trench safety requirements; 

• sharp angles or points of intersection (PIs) where additional area is required to account 

for the wide turning radius of pipe stringing trucks (which are more than 100 feet in 

length); 

• topsoil segregation areas to ensure stockpiled topsoil and subsoils are not mixed; 

• off right-of-way dewatering areas; and 

• timber staging/decking during right-of-way clearing. 

Along the portion of the pipeline route in Coos Bay, between about MPs 1.7 and 4.1, Pacific 

Connector indicated it would use a 250-foot-wide construction right-of-way. The extra width of 

construction right-of-way would be necessary to accommodate work boats needed to support the 

pipeline lay barge. 

Road and stream crossings and other locations that require shorter segments of pipeline to be 

installed separately (tie-in locations) are typically conducted with a separate construction crew to 

fabricate and install the pipeline across these features. To conduct these crossings, additional 

work area is required to stage or accommodate the equipment, crew vehicles, pipeline materials, 

dig the trench, store the spoil, and safely install the pipeline. Consequently, additional TEWAs 

are required at these locations. 

About 1,319 acres of TEWAs would be required during construction of the pipeline. Proposed 

TEWAs are listed in table 8A-2 included in Appendix A to environmental Resource Report 8 

and shown on alignment sheet maps filed with the FERC as part of Pacific Connector’s 

application. All of these areas would be temporary disturbance and would be restored upon 

completion of construction. During right-of-way cleanup and restoration TEWAs would be 

restored in a similar manner as other areas disturbed during pipeline construction. The areas 

would be regraded and a seedbed prepared as necessary, then seeded with a seedmix developed 

in consultation with affected landowners. In forested areas, all areas of the pipeline construction 

right-of-way and TEWAs beyond 15 feet from the pipeline centerline that were forested prior to 

construction would be planted with trees. See section 4.3 for discussions of TEWAs near 

waterbody and wetland crossings. 

Uncleared Storage Areas 

During design of the construction area requirements for the pipeline, Pacific Connector identified 

the need for additional work areas in various locations such as forested areas; in areas of steep 

slopes; and in areas where the route follows narrow ridgelines. In an attempt to minimize forest 
2-64 2.0 – Description of the Proposed Action 

clearing, especially in areas of older forest, Pacific Connector proposes to use some of these 

temporary work areas as UCSAs rather than TEWAs. Unlike TEWAs, UCSAs would not be 

cleared of trees during construction. UCSAs would be used to store forest slash, stumps, dead 

and downed log materials that would be removed from the construction work area before 

construction, and then scattered back across the right-of-way after construction. Pacific 

Connector anticipates that the amount of this type of material encountered within the 

construction right-of-way would be large enough to hinder construction activities if it were 

stored on the right-of-way. 

In some locations, the UCSAs may be used to store spoil or to temporarily park equipment 

between the mature trees. However, storage and temporary parking of equipment/vehicles would 

not occur immediately adjacent to any trees so as to minimize impacts (soil compaction or tree 

damage). In extremely steep and side sloping topography, the UCSAs may be required as a 

contingency location to contain rock, which rolls beyond the construction limits. Along 

extremely steep and narrow ridgeline areas, logs, slash, and dead and downed material may be 

used as cribbing to contain excavated materials during construction (right-of-way grading and 

trenching activities). During restoration, some of the materials that are pulled out of the cribbing 

may roll beyond the construction limits. Where feasible, Pacific Connector would retrieve 

materials that have rolled downhill using cables and chokers attached to standard on-site 

restoration equipment (i.e., bulldozers and trackhoes) to winch the material back to the right-ofway. There may be some cases where retrieval of the lost cribbing material may cause more 

harm to resources than allowing it to remain where it settled. 

Pacific Connector has identified 778 acres of UCSAs that would be adjacent to the construction 

right-of-way. The amount of spoil or woody debris that would be stored within UCSAs, or 

which pieces of equipment may be temporarily parked within UCSAs is not possible to estimate 

at this time, but would be determined as construction progresses. Locations of UCSAs are listed 

in table 8A-3 in Appendix 8A to Pacific Connector’s environmental Resource Report 8 and are 

shown on the alignment sheet maps that Pacific Connector filed with the Commission as part of 

its application. 

Hydrostatic Test Water Discharge Sites 

Pacific Connector has identified 74 locations along the proposed route where hydrostatic test 

water would be released within the construction right-of-way during testing of the pipeline. At 

these locations, the hydrostatic test water would be discharged into temporary erosion control 

basins, typically constructed of hale bales and silt fence, in upland areas (see section 4.3 for a full 

discussion of hydrostatic testing). 

Pacific Connector identified seven hydrostatic test water discharge locations that would be 

outside of the construction right-of-way, TEWAs, or UCSAs. In these seven locations, small 

brush or trees may be cleared by a rubber-tired rotary or flail motor (brush hog) or by hand with 

machetes or chainsaws. A rubber-tired or track hoe would be utilized to lay the discharge line 

and to remove the saturated hay bales or filter bags upon completion of hydrostatic discharge. 

The seven hydrostatic test water discharge locations would affect about 1.3 acres. 

Permanent Operational Pipeline Right-of-Way 

A permanent right-of-way or easement would be required for long-term operation and 

maintenance of the pipeline. On federally managed lands, Pacific Connector proposes to acquire 
2-65 2.0 – Description of the Proposed Action 

a 53-foot-wide permanent easement, centered over the pipe. On private timber lands, Pacific 

Connector proposes to acquire a 60-foot-wide permanent easement, which would have a 

configuration of 25-foot and 35-foot offsets from the pipeline centerline. On all other private 

lands, Pacific Connector proposes to acquire a 75-foot-wide permanent easement with a 

configuration of 50-foot and 25-foot offsets from the pipeline centerline. 

For the pipeline crossing of private lands, Pacific Connector would negotiate perpetual nonexclusive operational easements with landowners. Pacific Connector would make a one-time 

payment to the landowner based on the impact of the easement on the functional utility of the 

property. The easement agreement would specify activities within the defined easement. 

Subject to Pacific Connector’s safety, maintenance, and operation requirements, the easement 

may be crossed by roads, fences, utilities, etc., and the easement would allow for the growing of 

trees within 15 feet of the pipeline centerline. The easement would include one pipeline and 

associated aboveground facilities, would be assignable to successors in interest, and would 

provide for ingress and egress. The landowner would have the right to cultivate, work, plow, 

harvest and use the land so long as it does not hinder, conflict, or interfere with Pacific 

Connector’s surface or subsurface rights, or disturb Pacific Connector’s ability to operate, 

maintain, and protect its facilities. No excavations that results in a change in surface grade, 

reservoirs, obstruction, or structure would be allowed to be constructed, created, or maintained 

within the described easement area. 

For the pipeline crossings of lands administered by the BLM, USFS, and BOR, Pacific 

Connector would use the fee schedule according to the standard federal Right-of-Way Grant 

permit. Pacific Connector would need to show in its permit application for a Right-of-Way 

Grant on federal lands the need for an operational right-of-way wider than 50 feet. Section 4.7 

further discusses the acquisition of a permanent easement for the pipeline on both federal and 

non-federal lands. 

Pacific Connector claims it needs a wider permanent right-of-way on small tracts of private land 

(75 feet) than on large parcels held by timber companies (60 feet) because private individuals 

may be more likely to develop their properties and place improvements too close to the pipeline, 

while timber companies are less likely to develop their lands and place improvements close to 

the pipeline, and have a history of working in a cooperative manner with pipeline companies. 

We find this argument unconvincing. We believe Pacific Connector’s philosophy puts an unfair 

and undue burden of pipeline easement encumbrances on small private landowners in 

comparison to large landowners. 

Pacific Connector is free to negotiate and enter into agreements with private individuals and 

companies that convey an easement for the pipeline of whatever width of permanent right-ofway is mutually agreed upon. However, in situations where Pacific Connector and the nonfederal landowner cannot agree on an easement, or the width of the permanent right-of-way, and 

the FERC issues a Certificate to Pacific Connector, Pacific Connector should not be able to use 

the power of eminent domain available through section 7h of the NGA to acquire a permanent 

right-of-way of different widths for different private landowners. For other pipeline projects 

regulated by the FERC, typical permanent rights-of-way on non-federal lands are 50 feet wide.7

 

Over the course of 234 miles, a 50-foot-wide permanent operational easement would impact 

 

7

 In the recently authorized Western Phase of the Rockies Express Pipeline (CP06-354-000) the permanent right-of-way was 50 

feet for a 42-inch-diameter pipeline. 
2-66 2.0 – Description of the Proposed Action 

about 709 fewer acres than a 75-foot-wide permanent operational easement. In addition, the 

FERC typically does not allow the permanent easement to be used for any purpose other than the 

interstate transportation of natural gas. 

Therefore, we recommend that: 

• Pacific Connector’s exercise of eminent domain authority granted under section 

7(h) of the NGA in any condemnation proceeding related to the Order for the 

pipeline must be consistent with the authorized facilities and locations. Pacific 

Connector’s right of eminent domain granted under section 7(h) of the NGA does 

not authorize it to increase the size of its natural gas pipeline to accommodate future 

needs or to acquire a right-of-way for a pipeline to transport a commodity other 

than natural gas. 

In situations where Pacific Connector would use the power of eminent domain 

under section 7(h) of the NGA to acquire a permanent right-of-way, the width of 

that easement may not exceed 50 feet. 

Existing Construction Access Roads 

Pacific Connector would use existing roads to the extent possible to access the construction right-ofway. About 710 existing roads would be used for access to the pipeline right-of-way during 

construction. Existing roads that would be used for construction access are listed in table E-2 in 

Appendix E. Construction access roads are also shown on the pipeline facility maps in Appendix D. 

The use and crossing of access roads are more fully discussed in sections 4.7 and 4.9. 

Pacific Connector would obtain the necessary permits or approvals from appropriate federal, state, 

and county government agencies prior to use of the roads, and would obtain landowner permission 

for the use of existing private roads. As part if its application to the FERC, Pacific Connector filed a 

draft Transportation Management Plan for the POD for federal lands. On December 12, 2007, 

Pacific Connector filed a draft Transportation Management Plan for roads on non-federal lands. 

Revised transportation plans were filed on December 4, 2008. Transportation is discussed in section 

4.9. 

Pacific Connector may need to widen or improve portions of some existing access roads in order to 

accommodate construction equipment. Pacific Connector has estimated that modifications of 62 

existing access roads may be required outside of the existing road bed (e.g. widening corners to allow 

for the longer turning radius of larger vehicles), resulting in about 16 acres of disturbance. 

During use of existing roads for construction, paved surfaces would be kept clear of large 

accumulations of mud and other debris. Dirt roads may be maintained by grading, or covered by 

gravel. Appropriate sediment and erosion control devices would be installed along dirt roads used 

during wet weather or the rainy season to contain potential impacts to the road surface. 

New Temporary Construction Access Roads 

Pacific Connector has identified 18 locations where it would be necessary to construct new 

temporary access roads, totaling almost 3 miles in distance (table 2.3.3.1-1). Construction of the 

new temporary access roads would impact a total of about 6.1 acres. Following construction, 

temporary access roads would be removed and the affected areas restored to pre-construction 

conditions. 
2-67 2.0 – Description of the Proposed Action 

TABLE 2.3.3.1-1 

New Temporary and Permanent Access Roads Required for the Pacific Connector Pipeline and Associated Facilities

Access Road 

(TAR/PAR-MP) 

Dimension 

(feet) 

Impact 

(acres) a/ Ownership/ Jurisdiction Purpose 

TAR-8.28 25x2,053 0.56 Private Access to Coos River HDD 

TAR-8.31 20x1,228 0.18 Private Access to Coos River HDD 

TAR-61.53 14x632 0.20 Private/BLM-Roseburg Access to Hoover Hill 

TAR-76.58 14x644 0.21 Private Access to Jaros 

TAR-76.83 14x3,737 1.20 Private Access to Jaros 

TAR-81.34 20x654 0.30 Private Access to TEWA-81.22-W 

TAR-81.49 20x862 0.40 Private Access to TEWA 81.21-N 

TAR-88.63 20x771 0.35 Private Access between TEWA 88.52-W&88.62-W 

TAR-88.67 20x232 0.11 Private Access to TEWA 88.62-N 

TAR-93.00 20x500 0.24 BLM-Roseburg Access to St. Johns 

TAR-94.81 20x114 0.05 Private Access to S. Umpqua River 

TAR-128.69 25x756 0.43 Private Access to ROW 

TAR-141.10 25x471 0.27 Private Access to TEWA-140.98 

TAR-204.32 20x922 0.42 Private – BOR Access to road on levee 

TAR-208.72 20x287 0.13 Private Access to TEWA-208.67-W 

TAR-212.50 14x2,267 0.73 Private Access to Lost River 

TAR-215.72 14x714 0.23 Private Access from Taylor Road 

TAR-225.46 20x128 0.05 Private Access to ROW 

Total TAR 6.06 

PAR-7.70 25x154 0.09 Private Access to MLV #2 

PAR-28.40 25x285 0.16 Private/BLM-Coos Bay Access to MLV #4 

PAR-49.70 25x128 0.07 Private Access to MLV #5 

PAR-59.60 25x89 0.05 Private Access to MLV #6 

PAR-69.70 25x165 0.09 Private Access to MLV #7 

PAR-94.60 25x136 0.08 Private Access to MLV #8 

PAR-115.39 25x147 0.08 BLM-Medford Access to MLV #9 

PAR-122.10 25x1,116 0.65 Private Access to Shady Cove Meter Station 

PAR-132.10 25x1,476 0.85 Private Access to Butte Falls Compressor Station 

PAR-145.19 25x244 0.14 Private Access to MLV #11 

PAR-169.50 25x343 0.20 Private Access to MLV #12 

PAR-187.46 25x105 0.06 Private Access to MLV #13 

PAR-199.70 25x141 0.09 Private – BOR Access to MLV #14 

PAR-214.35 25x205 0.12 Private Access to MLV #15 

PAR-230.90S 25x58 0.03 Private Access to Tule Lake Meter Station 

PAR-230.90W 25x73 0.03 Private Access to Tule Lake Meter Station 

Total PAR 2.79 

Total 8.85 

a/ All or portions of the PARs are located within the permanent pipeline easement. 

New Permanent Access Roads 

Pacific Connector proposes to construct 16 new permanent access roads for access to the pipeline 

right-of-way and aboveground facilities (see table 2.3.3.1-1). These roads, totaling about one 

mile in distance, would provide access during construction as well as during operations and 

maintenance activities. Most of the new permanent access roads would be within Pacific 

Connector’s permanent pipeline easement. Construction and operation of the permanent access 

roads would impact a total of about 3 acres. 

Contractor and Pipe Storage Yards 

Pacific Connector has identified 38 potential sites for yards and rail ports that may be used 

during construction to off-load and store pipe and stage contractor equipment in the pipeline 

project area (see table 2.3.3.1-2). These sites are generally not along or immediately adjacent to 
2-68 2.0 – Description of the Proposed Action 

TABLE 2.3.3.1-2 

Privately Owned Contractor and Pipe Storage Yards that may be used during Construction of the Pacific Connector 

Pipeline and Associated Facilities 

Name County 

Size 

(acres) Description 

North Spit Dock Yard Coos 4.79 Old industrial dock; gravel and grassy surface 

Roseburg Dock a/ Coos N/A a/ Old industrial log yard; grassy surface a/

Weyerhaeuser Cove b/ Coos N/A b/ Old industrial; half is paved b/

Coquille Sawmill Yard Coos 7.47 Old industrial; abandoned sawmill; previously utilized 

as a contractor’s yard 

Fairview Yard Coos 2.24 Old industrial; graveled and dirt surfaces 

Coquille Yard Coos 21.84 Old industrial, vacant lot 

Georgia Pacific-Coos Bay Coos 107.08 Active sawmill & lumber yard 

Glendale#1 Douglas 4.43 Vacant lot/old industrial 

Glendale#2 Douglas 6.80 Vacant lot/old industrial 

Old Highway 99 Yard Douglas 8.76 Gravel-surfaced vacant lot 

Sutherlin John Murphy Yard Douglas 85.48 Old industrial, formerly John Murphy Plywood Mill; a 

portion has an asphalt surface 

Sutherlin Central Avenue Douglas 0.18 Old industrial; formerly Gerretsen Building Supply 

Co. 

Gravel Pit South Winston Douglas 128.93 Active gravel pit 

Green #1 Yard Douglas 9.37 Old industrial, vacant lot 

Green District Yard Douglas 7.05 Old industrial log yard, gravel-surfaced parking lot 

Days Creek Yard Douglas 176.67 Pasture 

Riddle Pasture Douglas 22.69 Crop/pasture 

Riddle Main Street Douglas 8.78 Old industrial; vacant lot 

Green Diamond Pipe Douglas 67.28 Abandoned mining operation 

Milo Yard c/ Douglas N/A 3 Former quarry c/

Highway 99 Hayfield Yard Douglas 96.36 Agriculture (hayfield) 

Weaver Road Yard Douglas 7.75 Old industrial log storage yard 

Hult Chip Yard (Pipe) Douglas 13.31 Old industrial; paved 

Hult Chip Yard (Parking) Douglas 2.65 Old industrial; gravel surface 

Hult Chip Yard (Roll) Douglas 8.90 Old industrial; paved 

Burrill Lumber Jackson 64.11 Old lumber mill/log yard 

Burrill Real Estate – Medford Industrial Park Jackson 92.05 Existing industrial park 

Avenue F and 11th Street Jackson 26.16 Industrial business and vacant leveled lot 

Oregon Opportunities Jackson 5.18 Undeveloped/vacant lot in industrial park 

Rogue Aggregates Jackson 111.02 Active aggregate quarry and processing facility and 

undeveloped land 

Collins Pacific d/ Klamath N/A4 Active wood products plant d/

Klamath Falls Amuchastegui Building Klamath 25.43 Existing commercial site 

Klamath Falls Industrial Oil Klamath 39.47 Undeveloped site 

Klamath Falls Memorial Drive Klamath 48.01 Undeveloped site 

Klamath Falls Memorial Drive Pipe Yard Klamath 24.72 Old industrial/vacant lot 

Klamath Falls North of Cross Road East Klamath 30.56 Farmland 

Klamath Falls North of Cross Road West Klamath 37.38 Farmland 

Merrill Siding Klamath 9.78 Railroad siding 

Total 1,312.68 

a/ This yard is incorporated in the construction footprint as TEWA 0.00-W and TEWA 0.00-N. The area (acres) of this yard is 

included in the TEWA impacts for the pipeline. 

b/ This yard is incorporated in the construction footprint as TEWA 1.19-W. The area (acres) of this yard is included in the TEWA 

impacts for the pipeline. 

c/ This yard is incorporated in the construction footprint as TEWA 94.53-W. The area (acres) of this yard is included in the 

TEWA impacts for the pipeline. 

d/ This yard is incorporated in the construction footprint as TEWA 197.66-N and TEWA 197.64-W. The area (acres) of this yard 

is included in TEWA impacts for the pipeline. 

the proposed pipeline. Criteria for identification of potential contractor and pipe yards were 

existing industrial sites that have been previously graded and graveled, are near the proposed 

pipeline, and which have rail service to the yard. All of the sites are privately owned. Pacific 
2-69 2.0 – Description of the Proposed Action 

Connector would secure the pipe storage yards and rail ports that would be used for construction 

during the easement acquisition phase, which Pacific Connector anticipates would begin in early 

2009. Use of all of the identified sites would affect 1,313 acres. Actual use of the potential sites 

would depend on the availability of these sites at the time of easement negotiations. 

Rock Source and Permanent Disposal Sites 

Pacific Connector identified 43 potential rock source/disposal sites, of which 24 are existing 

quarries/gravel pits or abandoned quarries/gravel pits. Although some of the existing/abandoned 

sites appear to have land use types other than quarries/gravel pits, it is not Pacific Connector’s 

intent to expand these sites beyond the existing or previously disturbed footprints. The 43 

identified sites total about 55 acres. 

Cathodic Protection System 

Pacific Connector would protect its pipeline from corrosion over time through a cathodic 

protection system. This system would input a low voltage electrical charge into the pipeline 

underground. The cathodic protection system would be installed about one year after the 

pipeline would be constructed, to allow for collection of post-construction data on 

electroconductivity soil potentials, which is required before the system can be designed and 

installed. Pacific Connector indicated that it would need to install up to 12 rectifiers for the 

cathodic protection at separate locations along the 230-mile length of the pipeline, spaced about 

20 miles apart. However, the exact locations of the rectifiers is not known at this time because 

the system would be designed after the pipeline is completed. If a deepwell would be installed, it 

would require a truck-mounted drill rig to drill up to 300 feet deep within a 10-inch diameter 

area. A horizontal anode bed would require the use of a standard backhoe for installation within 

an area up to 300 feet long by 2 feet wide and 5 feet deep. We estimate that a maximum of about 

1.4 acres of ground surface total would be disturbed during the installation of the cathodic 

protection system, within the permanent easement for the pipeline. Pacific Connector would 

attempt to use existing roads to reach the pipeline right-of-way during installation of the cathodic 

protection system. 

2.3.3.2 Aboveground Facilities 

Land required for operation of the proposed aboveground facilities is listed by facility in table 2.3.3.2-1. 

Construction and operation of the proposed aboveground facilities would require 21.5 acres. 

TABLE 2.3.3.2-1 

Land Requirements for Operation of Pacific Connector’s Proposed Aboveground Facilities 

Facility MP Area (acres) a/, c/ Ownership/ Jurisdiction 

Jordan Cove Receipt MS b/, MLV #1, Launcher & 

Communications Tower d/

0.00 2.25 Private 

 MLV #2 (Coos River Hwy) 7.70 0.06 Private 

 MLV #3 (South Sumner Road) 17.25 0.06 BLM 

 MLV #4 (Dora Ridge Road) 28.42 0.06 BLM 

 MLV #5 (Upper Camas Road) 49.72 0.06 Private 

 MLV #6 (South of Olalla Creek) 59.58 0.06 Private 

Clarks Branch Meter Station, MLV #7, Launcher/Receiver 

& Communications Tower d/

69.70 1.02 Private 

 MLV #8 (BLM Road 30-3-34.1) 94.60 0.06 Private 

 MLV #9 (BLM Road 30-1-5.0) 115.39 0.06 BLM (O&C)/Private 

Shady Cove Meter Station & Communications Tower d/ 122.10 3.08 Private 
2-70 2.0 – Description of the Proposed Action 

TABLE 2.3.3.2-1 

Land Requirements for Operation of Pacific Connector’s Proposed Aboveground Facilities 

Facility MP Area (acres) a/, c/ Ownership/ Jurisdiction 

Butte Falls Compressor Station, MLV #10 & 

Launcher/Receiver & Communications Tower d/

132.10 7.39 Private 

 MLV #11 (Gardener/Salt Creek Road) 145.19 0.06 Private 

 MLV #12 (Clover Creek Road) 169.48 0.06 Private 

 MLV #13 & Launcher/Receiver site 187.43 0.46 Private 

 MLV #14 (Midland Highway Crossing) 199.70 0.06 Private 

 MLV #15 (Hill Road) 214.35 0.06 Private 

Tule Lake, Russell Canyon and Buck Butte Delivery Meter 

Stations, MLV #16, Receiver & Communications Tower d/

230.90 6.60 Private 

Total 21.46 

a/ Permanent operational land requirement. Construction disturbance for aboveground facilities is included within the disturbance

calculated for the pipeline construction right-of-way. 

b/ The Jordan Cove Receipt Meter Station would be located entirely within the proposed Jordan Cove LNG terminal. 

c/ Mainline block valves (BVAs) would be entirely within the operational pipeline right-of-way or other aboveground facilities. Land 

area listed is area that would graveled and fenced. 

d/ All new communication facilities would be within meter station and compressor station facilities.

2.3.4 Pipeline Facilities on Federal Lands 

Tables 2.3.4-1, 2.3.4-2, and 2.3.4-3 lists land requirements for those portions of the Pacific 

Connector pipeline and associated facilities that would be within or would affect lands 

administered by the BLM, USFS, and BOR, respectively. 

TABLE 2.3.4-1 

Summary of Land Requirements for Portions of the Pacific Connector Pipeline and Associated Facilities 

Within or Affecting Lands Administered by the BLM a/

Facility 

Length or 

Number of 

Sites 

Land Affected 

During Construction 

(acres) 

Land Affected During 

Operation (acres) 

 Pipeline right-of-way 41.19 mi 469.83 249.43/149.68 b/ 

 Hydrostatic discharge locations outside the right-of-way 1 0.12 0 

 TEWAs 269 179.52 0 

 UCSAs 117 211.52 0 

 Rock source and disposal sites 3 8.1 0 

 Contractor and pipe storage yards 0 0 0 

 Existing roads needing improvements in limited locations 10 6.07 6.07 

 Temporary access roads 3 0.42 0 

 Permanent access roads 2 0.10 0.10 

 Aboveground facilities 2 0 0.17 

Pacific Connector TOTAL ----- 875.58 255.77 

a/ No lands administered by the BLM would be affected by construction and operation of the facilities proposed by Jordan Cove or

the Port. 

b/ The first figure is area within permanent operational right-of-way. The second figure is area that would be affected by the 30-

foot corridor where brush control would be performed during operation of the pipeline. 
2-71 2.0 – Description of the Proposed Action 

TABLE 2.3.4-2 

Summary of Land Requirements for Portions of the Pacific Connector Pipeline and Associated Facilities 

Within or Affecting Lands Administered by the USFS a/

Facility 

Length or 

Number of 

Sites 

Land Affected 

During Construction 

(acres) 

Land Affected During 

Operation (acres) 

 Pipeline right-of-way 30.58 mi 351.43 185.19/111.2 b/ 

 Hydrostatic discharge locations outside the right-of-way 0 0 0 

 TEWAs 177 103.68 0 

 UCSAs 74 131.73 0 

 Rock source and disposal sites 1 2.33 0 

 Contractor and pipe storage yards 0 0 0 

 Existing roads needing improvements in limited locations 10 2.6 2.6 

 Temporary access roads 0 0 0 

 Permanent access roads 0 0 0 

 Aboveground facilities 0 0 0 

Pacific Connector Total ----- 591.78 185.19 

a/ No lands administered by the USFS would be affected by construction and operation of the facilities proposed by Jordan Cove 

or the Port. 

b/ The first figure is area within permanent operational right-of-way. The second figure is area that would be affected by the 30-

foot corridor where brush control would be performed during operation of the pipeline. 

TABLE 2.3.4-3 

Summary of Land Requirements for Portions of the Pacific Connector Pipeline and Associated Facilities 

Within or Affecting Lands Administered by the BOR a/

Facility 

Length or 

Number of 

Sites 

Land Affected 

During Construction 

(acres) 

Land Affected During 

Operation (acres) 

 Pipeline right-of-way 0.65 mi 7.1 3.9/2.4 b/ 

 Hydrostatic discharge locations outside the right-of-way 0 0 0 

 TEWAs 3 0.5 0 

 UCSAs 0 0 0 

 Rock source and disposal sites 0 0 0 

 Contractor and pipe storage yards 0 0 0 

 Existing roads needing improvements in limited locations 0 0 0 

 Temporary access roads 1 0.1 0 

 Permanent access roads 0 0 0 

 Aboveground facilities 0 0 0 

Pacific Connector Total --- 7.7 3.9 

a/ No lands administered by the BOR would be affected by construction and operation of the facilities proposed by Jordan Cove or

the Port. 

b/ The first figure is area within permanent operational right-of-way. The second figure is area that would be affected by the 30-

foot corridor where brush control would be performed during operation of the pipeline. 

2.3.4.1 Pacific Connector Pipeline 

The Pacific Connector pipeline would cross about 41 miles of BLM-administered lands, 31 miles 

of NFS lands administered by the USFS, and about 0.65 mile of land administered by the BOR. 

However, between MPs 200.5 and 214.2 the pipeline would cross 27 irrigation facilities under 

BOR’s jurisdiction. We estimate that the nominal pipeline construction right-of-way of 95 feet 

would affect about 470 acres of BLM lands, 351 acres of NFS lands, and 7 acres of BOR lands, 

not including the irrigation facilities under the BOR’s jurisdiction. Assuming a permanent right-
2-72 2.0 – Description of the Proposed Action 

of-way of 53 feet on federal lands, about 249 acres of BLM lands, 185 acres of NFS lands, and 4 

acres of BOR lands would become part of the pipeline’s operational easement. All of the 

proposed action and facilities on federal lands would be addressed in the POD prepared by 

Pacific Connector in consultation with the land-managing agencies, in support of its federal 

Right-of-Way Grant application. 

We identified 269 TEWAs located on BLM lands, affecting a total of about 180 acres; 177 

TEWAs on NFS lands, affecting about 104 acres administered by the USFS; and 3 TEWAs on 

BOR lands, affecting a total of about 0.5 acre. We counted 117 UCSAs located on BLM lands, 

affecting about 211 acres; and 74 UCSAs on NFS lands, affecting about 132 acres administered 

by the USFS. No UCSAs would be located on BOR lands. 

Nineteen of the discharge locations for hydrostatic test water would be on BLM lands, and 8 

would be on NFS lands. Of the hydrostatic test water release areas outside of the pipeline 

construction right-of-way, one location would be on BLM land affecting about 0.1 acre. No 

hydrostatic test water discharge locations outside of the construction right-of-way have been 

identified on USFS or BOR lands. 

All or portions of 120 existing roads that would be used to access the pipeline right-of-way are 

on BLM lands, and 104 roads are on NFS lands. Pacific Connector would make modifications to 

10 existing roads on BLM lands, affecting about 6 acres, and disturb an additional 3 acres along 

10 existing roads crossing NFS lands. The USFS has stated that a number of additional existing 

roads across NFS lands that Pacific Connector would use for access would also require 

modifications, such as clearing, grading, widening, and drainage improvements. Pacific 

Connector has begun to identify this impact, but much of the specific road improvement 

requirements would not be identified until closer to construction. See additional discussion of 

access roads in section 4.9. 

Pacific Connector proposes to construct two new temporary access roads across BLM lands, and 

another temporary road across BOR land, affecting a total of about 0.4 acre. Two new 

permanent roads would be constructed across BLM lands and one new road would cross BOR 

land, permanently affecting a total of about 0.1 acre. 

Three of the rock source or disposal areas proposed for use by Pacific Connector during pipeline 

construction are located on BLM land, covering a total of about 8 acres. There is one rock 

source or disposal location on NFS lands, totaling about 2 acres. 

2.3.4.2 Aboveground Facilities 

Three MLV locations would be on BLM lands, affecting a total of about 0.2 acre. This includes 

MLVs #3 and #4 within the Coos Bay District, and MLV #9 within the Medford District. Pacific 

Connector evaluated using an existing BOR levee road along the Lost River Diversion Canal to 

access MLV #14; however, it is not proposing to use this road. 

2.4 CONSTRUCTION PROCEDURES 

This section describes the general procedures proposed by Jordan Cove and Pacific Connector 

for construction of the LNG terminal and pipeline facilities. Refer to section 4 of this EIS for 

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

additional measures that we are recommending to mitigate environmental impacts. 
2-73 2.0 – Description of the Proposed Action 

Under the provisions of the Natural Gas Pipeline Safety Act of 1968, as amended, Jordan Cove 

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

DOT’s Liquefied Natural Gas Facilities: Federal Safety Standards (49 CFR 193). The facilities 

would also be required to meet NFPA 59A. These standards specify siting, design, construction, 

equipment, and fire protection requirements for new LNG facilities. The ship unloading 

facilities and any appurtenances located between the LNG carriers and the last valve 

immediately before the LNG storage tank would be required to comply with applicable sections 

of the Coast Guard regulations in Waterfront Facilities Handling Liquefied Natural Gas (33 CFR 

127) and EO 10173. 

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

accordance with DOT regulations in Transportation of Natural and Other Gas by Pipeline: 

Minimum Federal Safety Standards (49 CFR 192). Among other design standards, these 

regulations specify pipeline material selection; minimum design requirements; protection from 

internal, external, and atmospheric corrosion; and qualification procedures for welders and 

operations personnel. In addition, Pacific Connector would comply with the siting and 

maintenance requirements of the FERC’s regulations at 18 CFR 380.15, and other applicable 

federal and state regulations. 

Jordan Cove would construct the terminal facilities in accordance with its Upland Erosion 

Control, Revegetation, and Maintenance Plan (Jordan Cove’s Plan) and Wetland and Waterbody 

Construction and Mitigation Procedures (Jordan Cove’s Procedures).8

 Jordan Cove’s Plan and 

Procedures are modified from the FERC staff’s Upland Erosion Control, Revegetation, and 

Maintenance Plan (FERC staff’s Plan, January 17, 2003 Version), and our Wetland and 

Waterbody Construction and Mitigation Procedures (FERC staff’s Procedures, January 17, 2003 

Version). The intent of the FERC staff’s Plan and Procedures is to assist applicants by 

identifying baseline mitigation measures for minimizing the extent and duration of disturbances 

on soils, wetlands, and waterbodies associated with projects under the FERC’s jurisdiction 

throughout the country. As general guidelines, the FERC staff’s Plan and Procedures may be 

less stringent than state and local guidelines that are based on state or local concerns, issues, 

and/or regulations. Most of Jordan Cove’s modifications to the FERC staff’s Plan and 

Procedures relate to measures that apply to linear pipeline construction that would not be 

applicable to the project- and site-specific conditions at the LNG terminal. Table 2.4-1 

summarizes the major differences between Jordan Cove’s Plan and Procedures and FERC staff’s 

Plan and Procedures. We believe all modifications would provide for an equal level of 

environmental protection as the FERC staff’s Plan and Procedures. 

TABLE 2.4-1 

Major Differences Between Jordan Cove’s Plan and Procedures and the FERC Staff’s Plan and Procedures

Section 

Number Topic Change or Alternative Measure Accepted Reason 

Plan 

I.A. Applicability of Plan Revisions to wording to make specific 

to JCE and proposed LNG terminal site 

Yes Would provide equal 

environmental protection 

II.A & B Environmental 

Inspection and 

Responsibilities 

Revisions to wording to make specific 

to JCE and proposed LNG terminal site 

Yes Would provide equal 

environmental protection 

 

8

 Jordan Cove’s Plan and Procedures, and Pacific Connector’s ECRP were filed with the FERC as part of their respective 

applications on September 4, 2007. 
2-74 2.0 – Description of the Proposed Action 

TABLE 2.4-1 

Major Differences Between Jordan Cove’s Plan and Procedures and the FERC Staff’s Plan and Procedures

Section 

Number Topic Change or Alternative Measure Accepted Reason 

III.A, D-G Preconstruction Planning Revisions to wording to make specific 

to JCE and proposed LNG terminal site 

Yes Would provide equal 

environmental protection 

III.B & C Preconstruction Planning Deletion of items not applicable to LNG 

terminal site (drain tiles, irrigation, 

grazing) 

Yes Not applicable to proposed LNG 

terminal 

IV.A, B, 

F 

Installation/ Construction Revisions to wording to make specific 

to JCE and proposed LNG terminal site 

Yes Would provide equal 

environmental protection 

IV.C & D Installation/ Construction Deletion of items not applicable to LNG 

terminal site (drain tiles & irrigation) 

Yes Not applicable to proposed LNG 

terminal 

V.A, B Restoration – Cleanup, 

Trench Breakers 

Deletion of items standard to pipeline 

rights-of-way and not applicable to 

LNG terminal site (travel lanes, 

agricultural restoration, trench 

breakers) 

Yes Not applicable to proposed LNG 

terminal 

V.C, D Restoration – 

Compaction Mitigation & 

Revegetation 

Revisions to wording to make specific 

to JCE and proposed LNG terminal site 

Yes Would provide equal 

environmental protection 

VI ORV Control Deleted measures for ORV control on 

pipeline rights-of-way 

Yes Not applicable to proposed LNG 

terminal 

VII Post Construction – 

Monitoring and 

Reporting 

Revisions to wording to make specific 

to JCE and proposed LNG terminal site 

Yes We have included numerous 

project-specific post construction 

recommendations in this EIS. 

Procedures

I.A. Applicability of 

Procedures 

Revisions to wording to make specific 

to JCE and proposed LNG terminal site 

Yes Would provide equal 

environmental protection 

II, III, IV Preconstruction, 

Environmental 

Inspectors 

Revisions to wording to make specific 

to JCE and proposed LNG terminal site 

Yes Would provide equal 

environmental protection 

V.A Waterbody Crossings – 

Notifications 

Revisions to wording to make specific 

to JCE and proposed LNG terminal site 

Yes Would provide equal 

environmental protection 

V.B Waterbody Crossings - 

Installation 

Deleted measures specific to 

perpendicular pipeline crossings 

(bridges, crossing techniques, trench 

dewatering), revisions to make specific 

to LNG site 

Yes Linear pipeline crossing measures 

not applicable to proposed LNG 

terminal, modifications would 

provide equal environmental 

protection 

VI Wetland Crossings Deleted, as no construction activity in 

wetlands is proposed at LNG terminal 

site 

Yes Not applicable, and sediment and 

erosion control measures in Plan 

would protect off-site wetlands 

VII Hydrostatic Testing Revisions to wording to make specific 

to JCE and proposed LNG terminal 

site, deletion of some standard 

measures for linear pipelines (pipeline 

testing, withdrawal from surface 

waters) 

Yes Would provide equal 

environmental protection, test 

water source would be municipal 

water 

Jordan Cove submitted a preliminary draft Spill Prevention, Control, and Countermeasure Plan 

(SPCCP) with its application to the FERC. Also included with its application to the FERC was a 

preliminary Erosion and Sediment Control Plan (ESCP) that was part of Jordan Cove’s 

application for a stormwater general permit from the ODEQ. We have reviewed these 

preliminary plans and find them acceptable. The plans could be revised if requested by the 

ODEQ. 

Pacific Connector would construct the pipeline facilities and restore areas disturbed during 

construction in accordance with its Erosion Control and Revegetation Plan (ECRP), which 

incorporates most of the elements of the FERC staff’s Plan and Procedures. Pacific Connector 

provided a list of locations where it proposes site-specific modifications to standard measures in 

the FERC staff’s Plan and Procedures, as well as its rationale for project-wide modifications. 
2-75 2.0 – Description of the Proposed Action 

We evaluated each of these proposed modifications to determine if they would provide what we 

believe would be an equal level of environmental protection in comparison to the Plan and 

Procedures. Pacific Connector’s modifications and our assessment are include in Appendix I. 

We also discuss those individual modifications where applicable in sections 4.3 and 4.4 of this 

EIS. 

Pacific Connector would also prepare and submit a Stormwater Pollution Prevention Plan

(SWPPP) to authorize stormwater discharge under the ODEQ General Stormwater Discharge 

Permit (Permit No. 1200-C). ODEQ has recommended this permit application be submitted six 

months to one year prior to the start of construction, therefore Pacific Connector has not yet 

provided a draft SWPPP for our review. Also, per the FERC staff’s Procedures, Pacific 

Connector has prepared a SPCCP for its pipeline, and included that plan with its application to 

the FERC filed in September 2007. We have reviewed Pacific Connector’s SPCCP and find it 

acceptable. 

Jordan Cove’s proposed LNG terminal and Pacific Connector’s proposed pipeline and associated 

aboveground facilities would be constructed in various phases. A description of the primary 

construction phases is provided below. 

2.4.1 LNG Terminal 

2.4.1.1 Access Channel and Slip 

The Port and Jordan Cove propose to construct the access channel and slip in several phases, to 

reduce turbidity and impacts on aquatic resources in Coos Bay. The first phase would be to 

excavate and dredge the portion of the slip in the upland behind a berm that would be retained 

along the shoreline, so such that this construction would be isolated from Coos Bay. This work 

could be done year-round. The second phase would remove the berm and conduct dredging in 

the bay to create the access channel. This work would be done between October 1 and February 

15, or during the in-water windows required by the appropriate regulatory agencies. 

Phase 1 Construction Details 

The upland portion of the slip currently consists of a forested sand dune, and level area created 

from dredged material placed on the site by the COE during 1972 and 1973 that is covered with 

low shrubs and grasses. The merchantable timber would be logged and sold, while the 

unmerchantable timber and brush would be pulverized and stockpiled as mulch. The mulch 

would be saved for future erosion control on site. Only surfaces that need to be recontoured to 

accommodate the slip or supporting structures would be grubbed and cleared. 

The existing natural ground surface is at an elevation of approximately +20 feet NAVD88, while 

the water table across the slip area occurs at an elevation of approximately +10 feet NAVD88. 

Excavated material above the water table would be removed by conventional earthmoving 

equipment such as scrapers, bulldozers, and front-end loaders. Materials excavated in uplands 

would be conveyed to the disposal areas (Weyerhaeuser Linerboard site and JCE Placement site) 

using dump trucks. About 1.0 mcy of material would be dry excavated in the slip area. 

Once the upper layer has been removed by dry excavation, material at or below the water table 

would be removed by hydraulic dredging. Several wide-tread excavators would be used to 

create a dredge launch pond within a 300-foot by 200-foot area dug to about 0.0 feet NAVD88. 
2-76 2.0 – Description of the Proposed Action 

One or more hydraulic dredge plants would be transported to the Jordan Cove terminal by truck, 

assembled on site, and lifted by crane into the dredge launch pond pocket. The hydraulic dredge 

plants would be between 18 inches and 24 inches in size, and would be capable of transporting a 

slurry of 30 percent solids by weight at a flow rate of about 6,000 gpm. Dredging for the slip 

would be to a depth of - 45 feet NAVD88, while creating side slopes for the slip at a ratio of 3 

feet horizontal: 1 foot vertical. The dredge slurry would be transported by pipelines to the 

disposal areas (Port Commercial Sand Storage site and the Weyerhaeuser Linerboard sites). 

Other pipelines would return slurry water decanted from the dredged material storage areas back 

to the slip area to help float the dredges in the pond. About 2.8 mcy of material would be 

dredged from the pocket behind the berm. 

A 40-foot-wide, 1,200 foot long berm, covering a total of about 6 upland acres, would be 

retained at the waterline along the current location of the abandoned Jordan Cove Road, to 

prevent excavated or dredged materials from entering the bay during this construction phase. 

The berm would be sloped at an angle of 3 feet horizontal: to 1 foot vertical on its north face to 

maintain its structural integrity during excavation and dredging activities for the slip. 

After the upland portion of the slip has been dredged, but before the berm is removed, modular 

pontoon barges would be lifted into the slip by cranes and pile driving equipment moved onto the 

barges. The majority of the in-water structure construction, including pile driving, would then be 

conducted in the dredge pond while the slip pocket remains isolated from Coos Bay by the berm. 

During this phase, the northern, eastern, and western slip faces would be armored. Also, the 

existing wastewater pipeline and other utilities currently located below the abandoned Jordan 

Cove Road, where the berm would be situated, would need to be removed and relocated. 

Phase 2 Construction Details 

The second phase of construction of the slip and access channel would begin with the removal of 

the berm, which would be accomplished by dredging from both the bay and upland sides. 

Removal of the berm would result in the hydraulic dredging of about 0.4 mcy of material. This 

work, together with the hydraulic dredging of the access channel, would be done during the 

period consistent with ODFW in-water work window guidelines (October to February). The 

remaining southern portion of the slip would be armored, and any additional in-water structures 

(between 48 and 214 piles) would be installed. 

The access channel would connect the existing Coos Bay navigation channel with the slip at the 

proposed LNG terminal. The access channel would be about 1,200 feet wide at the navigation 

channel, about 800 feet wide at the entrance to the slip, and about 800 feet long. It would be 

dredged to a depth of – 45 feet NAVD88, plus 2 feet of overdredge allowance, and sloped with 

contours at 3 feet horizontal: to 1 foot vertical. The dredging would be conducted with a 

hydraulic pipeline dredges operating from uplands and an in-water barge. About 1.3 mcy of 

material would be dredged to create the access channel in the bay. The dredged material would 

be transported by pipeline to upland disposal areas (Weyerhaeuser Linerboard sites and Port 

Sand Storage site). Additional discussion of dredging techniques and dredged material disposal 

is included above in section 2.1.4. 

2.4.1.2 Berth Facilities 

Installation of the berth structure would begin during excavation of the slip. The berth structure, 

consisting of the unloading platform and breasting and mooring dolphins, would be constructed 
2-77 2.0 – Description of the Proposed Action 

with land-based equipment, using conventional “over-the-top” techniques. Working from a 

temporary deck, a large capacity crawler crane would be used to support the pile driving 

hammer, and pick up and set structural elements. Piles would be driven, and capped with precast concrete or fabricated steel. Beams, of either standard pre-cast/pre-stressed concrete or 

fabricated steel girders would be placed on top of the caps to support the deck. The unloading 

platform and dolphins would likely consist of a cast-in-place or pre-cast/pre-stressed concrete 

deck with pre-cast concrete pile foundations. Prefabricated steel jackets could also be used. 

Large diameter mono pile steel pipe dolphins may also be used in place of steel dolphins. Once 

the unloading platform deck is completed, all of the piping and other facilities would be installed 

in pipe trestle. 

A separate roadway trestle would be built, using similar construction techniques, between 

landside abutment and the unloading platform. Jordan Cove estimates that the LNG unloading 

platform, pipe trestle, roadway trestle, dolphins and emergency walkways would require 

approximately 136 concrete piles. The deck of the platform and trestles would require 

approximately 1,000 cubic yards (cy) of concrete. 

2.4.1.3 LNG Storage and Support Facilities 

Site Preparation 

Site preparation for the land-based LNG storage and support facilities would require clearing and 

grading activities. During clearing, the ground would be stripped of vegetation; with the organic 

materials stockpiled for later use during restoration. The majority of the subgrade would consist 

of natural or structural fill sand that would be covered by a 6-inch thick pad of clean crushed 

rock as a working surface for equipment. During grading and cut-and-fill activities, the ground 

elevation would be raised to about +20 feet NAVD88 for the LNG storage tank area and +55 feet 

NAVAD88 for the process area. The LNG storage tank and process areas, including the storm 

surge barrier, would require approximately 1.2 mcy of cut and fill. Temporary ditches and 

sediment fences would be installed as necessary, in accordance with Jordan Cove’s ESCP and 

SPCCP. 

Site preparation would include removal of the existing Roseburg water tanks on the dune to the 

west of its wood chip facility, which is currently used to provide the facility with fire water, at 

the location where Jordan Cove proposes to locate its terminal firewater pond. Prior to removal 

of these tanks, a 12-inch-diameter tap from the existing CBNBWB water line would be made and 

connected to the Roseburg firewater system. Once all connections have been made and the 

firewater system tested, the water from the tanks would be drained and used for compaction 

activities or for dust control during the initial LNG terminal grading activity. In the event that 

the timing of construction activities precludes this use, any remaining water would be discharged 

through sedimentation and erosion control structures and allowed to flow onto the unused and 

graveled northern portion of the Roseburg site. The tanks would then be dismantled and the steel 

plate material recycled as scrap. Concrete pads would be removed and crushed for nonstructural fill or disposed of in a permitted solid waste landfill. 

Buildings, process equipment, and pipe rack foundations would be supported with drilled pier 

foundations or spread footings and mats. Following completion of foundations, the site would be 

filled, compacted, and brought up to final grade. Final grading and landscaping would consist of 
2-78 2.0 – Description of the Proposed Action 

gravel surfaced areas, asphalt surfaced areas, concrete paved surfaces, grass areas, and 

construction of the storm surge barrier. 

Construction materials would be brought to the terminal by road, rail, or barge. There is an 

existing road (Trans-Pacific Highway) and railroad to the northern side of the terminal parcel. 

Jordan Cove indicated that it may use an existing dock located about 2 miles from the terminal 

(Southport) for materials brought in by barge. Jordan Cove has drafted a transportation plan 

(further discussed in section 4.9.3) that addresses construction worker and equipment traffic, and 

material deliveries to the terminal. Where practical, skid mounted equipment would be used to 

minimize materials to be delivered to the terminal. Temporary fabrication shops would be set up 

on-site to fabricate pipe spool pieces and other pre-fabricated units of equipment. 

LNG Storage Tank Construction 

Construction of the LNG storage tanks would be the most time consuming element in the 

development of the LNG terminal. General steps taken during construction of each LNG storage 

tank would include installation of the foundations and tank bottom slab, construction of the outer 

concrete container wall, insertion of the bottom carbon steel vapor liner, construction of the steel 

dome roof and suspended deck, installation of the 9 percent nickel steel inner tank, installation of 

the internal tank accessories (pump columns, instrumentation, and piping), installation of 

external tank accessories, installation of insulation, and installation of LNG pumps. Following a 

successful inner container hydrotest (see below), the tank would be washed down and cleaned. 

After installation of the LNG pumps, the tank would be closed and purged with nitrogen to a 

positive gauge pressure. At this point in the construction process, the tank would be ready for 

cooldown with LNG. 

Support Facilities 

Construction of foundations for buildings and installation of major mechanical equipment would 

occur once LNG storage tank construction is underway. Large equipment items would be set on 

their foundations upon delivery. After the pipe racks are completed, work would commence on 

the installation of the process and utility piping. The installation of mechanical equipment would 

be followed by electrical and instrumentation installation. Once the piping is completed and 

tested, piping insulation would be installed. As the construction of the process portion of the 

LNG terminal progresses, work would commence on the pre-commissioning activities, so that 

these activities would be completed concurrent with the completion of the LNG storage tanks 

and be ready for nitrogen purging. 

2.4.1.4 Testing 

Jordan Cove would conduct testing of the LNG storage tanks and other terminal facilities in 

accordance with applicable codes and requirements. The storage tanks would be tested in 

accordance with API 620, while piping would be tested in accordance with the ASME B31.3. 

Some of the tests to be carried out are described below. 

Testing of the LNG Storage Tanks 

The inner contain or each LNG storage tank would be hydraulically tested by filling the tank 

with water, and then pressurizing the tank. The hydrotest water source would be potable water 

from the existing CBNBWB water line. The existing 12-inch line has the necessary pressure and 

capacity to deliver 20 million gallons over a two to three week period if hydrostatic testing were 
2-79 2.0 – Description of the Proposed Action 

done during the months of September through May, and over a 3- to 4-week period if hydrostatic 

testing were done during the months of June through August. 

An on-site firewater pond would be one of the first facilities to be completed on site. Upon 

completion, the 10 million gallon firewater pond would be filled with water from the CBNBWB 

line. At the start of hydrotesting, which would be done near the end of the construction schedule, 

(see section 2.5), approximately 350 gpm would be withdrawn from the firewater pond and 700 

gpm from the CBNBWB line so as not to put undue strain on the CBNBWB line. In advance of 

filling the tanks, the hydrotest water source would be tested to ensure that the water would meet 

all applicable code requirements. No biocides or chemicals would be added to the hydrostatic 

test water, since it is essentially potable water that has already been treated by the CBNBWB. 

About 28.5 million gallons would be required for the hydrotest. To minimize water usage, the 

two tanks would be hydrotested with the same water by transferring the water at the conclusion 

of the hydrotesting of one tank to the other tank. Water would be introduced into the inner tank 

container through a manhole in the outer container concrete roof. The duration that the water 

remains in the tanks would be strictly controlled; therefore, it is not expected that any 

contamination or discoloration would be present on discharge, even after being passed through 

both LNG storage tanks. However, the water would be tested to confirm composition prior to 

the water being transferred between each individual tank and before the water is discharged from 

the last tank. In each case the small amount of water that remains in the tank after the bulk 

transfer/emptying operation has taken place, estimated to be about 0.25 million gallons, would be 

treated as appropriate to meet discharge water quality criteria prior to discharge. Jordan Cove 

estimates the total duration of the hydrotest of the first tank from start of filling to emptying 

would be approximately 34 days, with the second tank taking approximately 21 days. 

On completion of hydrotesting the final tank, the water would be pumped from the tank to the 

firewater pond. The rate of discharge is expected to be approximately 1.8 million gallons per 

day (mgd) for the bulk pumping operation with substantially lower rates being achieved when 

removing the final amounts of water from the tank bottom. From the firewater pond, the 

hydrotest water would be discharged into the industrial wastewater pipeline via an overflow, 

which connects to a previously existing, permitted ocean discharge. Water would be sampled 

and tested for suitability prior to discharge. If treatment is found to be required, treatment 

procedures would be developed prior to discharge. Jordan Cove would retain about 10 million 

gallons in the firewater pond to support operation of the terminal facilities. Therefore, 18.5 

million gallons would be discharged as a result of hydrotesting the LNG storage tanks. Jordan 

Cove would use a pneumatic test on the outer container for each LNG storage tank. During that 

test, the outer container would be held at 1.25 times design pressure for one hour. 

Testing of Pipework 

Piping within the LNG terminal facility would be tested using hydrostatic or pneumatic methods. 

In general, cryogenic piping (piping that would transfer LNG) would be pneumatically tested 

with dry air or nitrogen at 1.1 times design pressure. Non-cryogenic piping (e.g., piping that 

would transfer natural gas) would be hydrotested using clean water at 1.5 times design pressure. 

2.4.2 Pipeline and Associated Aboveground Facilities 

Construction of the proposed pipeline would primarily involve standard cross-country pipeline 

construction techniques as described in section 2.4.2.1. Special construction techniques would 
2-80 2.0 – Description of the Proposed Action 

also be used when constructing the pipelines across wetlands; waterbodies; roads and railroads; 

foreign pipelines; and agricultural, residential, commercial, and industrial areas. Steep side 

slopes and rugged terrain also may require special construction techniques. These special 

construction techniques are described in section 2.4.2.2. Construction of the aboveground 

facilities associated with the pipeline is discussed in section 2.4.2.3. 

2.4.2.1 General Pipeline Construction Techniques 

Figure 2.4-1 shows the typical steps of cross-country pipeline construction. Standard pipeline 

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

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

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

and coating, lowering-in and backfilling, hydrostatic testing, right-of-way cleanup, and 

restoration. 

Pacific Connector has determined that to efficiently construct the pipeline, construction would be 

divided into at least five separate construction spreads. Each spread would consist of all 

construction activities necessary to construct the pipeline in the area designated for that spread. 

Preliminary locations of construction spreads identified by Pacific Connector include the 

following: 

• Spread 1 - MPs 0.0-49.7 

• Spread 2 – MPs 49.7-94.7 

• Spread 3 – MPs 94.7-132.1 

• Spread 4 – MPs 132.1-188.0 

• Spread 5 – MPs 188.0-230.9 

Surveying and Staking 

Prior to the start of construction, the exterior limits of the approved construction right-of-way 

and boundaries of TEWAs would be civil surveyed and clearly staked. The survey stakes would 

be maintained throughout construction, and monitored by Pacific Connector’s environmental 

inspectors (EIs). Any pre-existing property line or survey monuments that occur within the 

construction right-of-way would be protected where possible, and if damage occurs during 

construction, these monuments would be replaced according to state and federal standards. Civil 

surveys on federal lands would adhere to guidelines established by the BLM, BOR, and USFS 

that were provided to Pacific Connector during the pre-filing review period. Civil survey is 

generally performed on foot or using all-terrain vehicles (ATVs) or off-highway vehicles 

(OHVs) from existing access points to the pipeline right-of-way. 
2.0 – Descr

2-81

Figure 2.4-1. Typical Pipeline Construction Sequence 
2-82 2.0 – Description of the Proposed Action 

Access to the Construction Right-of-Way 

Access roads that would be used for access during construction are discussed above in section 

2.3.3. Equipment involved in pipeline construction would be moved onto the right-of-way using 

approved access roads, and once on the right-of-way would then generally proceed down the 

right-of-way performing their job tasks. Pacific Connector has submitted to the FERC drafts of 

Transportation Management Plans for both federal and non-federal lands. See additional 

discussion in section 4.9 of this EIS. 

Clearing and Grading 

The construction right-of-way and TEWAs would be cleared of brush and trees. On lands 

vegetated with tall shrub cover, such as sagebrush communities, Pacific Connector would clear 

the right-of-way by mowing or scalping off the tops of the shrubs with a motor-grader or a 

bulldozer. This material would be stockpiled during construction along the edge of the 

construction right-of-way or within UCSAs, and scattered across the right-of-way after seeding 

during final cleanup. Hayfields, pastures, and grassy areas would not be cleared except in areas 

directly over the trench or where grading would be required to create a level working surface. 

In forested areas, timber would be cut and cleared from the right-of-way and TEWAs using 

standard logging techniques, in accordance with landowner and land management agency 

requirements including time-of year-restrictions. Pacific Connector indicated that specific 

logging methods may not be fully determined until a contractor has been selected for 

construction of its pipeline. However, Pacific Connector’s draft ECRP, provided in Appendix 

1B to environmental Resource Report 1 in its application, did outline some typical best 

management practices (BMPs) for timber harvesting. On federal lands, the BMPs would be 

designed and implemented to meet the requirements of the CWA, LRMPs, and National Forest 

Plan Water Quality and Soils Standards and Guidelines on NFS lands. In January 2009, Pacific 

Connector submitted to the USFS and BLM a draft Timber Extraction Plan for federal lands that 

provides more details for right-of-way clearing methods. See section 4.4.2. 

Logging would be done according to approved and proven methods currently used within each 

unique logging area. The methods selected would be based on site-specific information at the 

time of actual harvest. Minimal log removal by air is anticipated. Actual logging methods to be 

used by location and acreage would not be known until timber contractors evaluate site-specific 

and then-current acreages. The logging contractors would be solicited by a request for proposal 

in which these proposals are evaluated by Pacific Connector, and contracts awarded to the most 

qualified bidder(s). The exact timber harvest and decking requirement locations would be 

determined by the contractor within the access roads and staging areas already identified by 

Pacific Connector, subject to applicable agency approvals. 

Merchantable timber would be removed and sold according to landowner or agency stipulations. 

For federal lands, logging methods would be determined through consultations with the BLM, 

BOR, and USFS, and as required in the Timber Sale Agreements. In order to comply with ORS 

527.670(3), Pacific Connector would be required to provide a written timber harvest plan to the 

ODF State Forester for each state forest region that would be crossed. Pacific Connector 

indicated that it would file its final logging plans for both federal and non-federal lands after 

completion of timber cruises and the selection of its construction contractor. The plan for nonfederal lands would include a stewardship plan and agreements with landowners to comply with 
2-83 2.0 – Description of the Proposed Action 

the Oregon Forest Practices Act (OAR-629-606-0010). ODF regulations for burning of slash are 

outlined in OAR 629-615-300. 

Pacific Connector would conduct timber cruises to verify volumes and species composition on 

forested lands and determine values. Timber cruises would be completed according to industry 

and/or federal agency standards. The timber cruises would also support development of Pacific 

Connector’s timber extraction plans, which would identify the logging systems that would be 

practical along the route based on the pipeline alignment, construction right-of-way 

configuration, topographic conditions, existing access, timber types and volumes to be removed, 

and the various logging system limitations. 

Pacific Connector estimates that about 17,379 thousand board feet (MBF) of lumber may be 

cleared on federal lands crossed by the pipeline route, including about 8,839 MBF on BLM lands 

and 8,540 MBF on NFS lands. The expected volumes of harvested timber, tree types cleared, 

and their values are further discussed in section 4.8 of this EIS. 

According to 36 CFR 223.12, permission to cut, damage, or destroy trees without advertisement, 

the USFS, under the issuance of a Right-of-Way Grant or Special Use authorization, may sell the 

timber directly to Pacific Connector at the current appraised value. The intent would be to 

negotiate one contract covering the three National Forests crossed by the proposed pipeline. 

The BLM may sell the right-of-way timber by competitive bidding or through negotiated sale 

where it is impracticable to obtain competitive bids, in accordance with 43 CFR 5400. Right-ofway timber would be sold under lump sum timber sale contract(s) at not less than the appraised 

value as determined by the BLM. Timber sale contracts would be prepared, offered, and 

administered by each BLM office involved. 

The BLM and USFS would use a Tree Measurement Timber Sale Contract with the standard 

provisions for payment and log accountability. Many of the operational requirements typically 

detailed in such a timber sale contract, such as erosion control, road maintenance, and slash 

disposal, are expected to be contained in the Right-of-Way Grant and would be incorporated by 

reference into the timber sale contract. Performance bonding typically required in such a timber 

sale, if included in the grant and considered adequate, would be used to cover operations 

performed under the timber sale contract(s). Agency sale administrators would oversee timber 

disposal operations to ensure they are carried out following any site-specific requirements as 

well as to ensure proper log accounting for specially designated revenues. 

Timber sale boundary designation, volume estimation, appraisal, and contract preparation would 

be accomplished by the federal land-managing agencies in cooperation with Pacific Connector as 

negotiated. Pacific Connector would be responsible for logging and marketing of the timber. 

Any timber sold must be processed domestically and not exported. Such items as tree-marking 

paint would be agency tracer paint used under the supervision and accountability of the 

respective agency. The USFS contract would only cover the sale of merchantable timber cleared 

for the pipeline crossings of the three affected National Forests. 

Prior to clearing operations, Pacific Connector would flag existing snags in forested areas on the 

edges of the construction right-of-way or TEWAs, to protect those snags from removal during 

timber cutting, where feasible. These snags would be saved to benefit primary and secondary 

cavity nesting birds, mammals, reptiles, and amphibians. During this process, other large 
2-84 2.0 – Description of the Proposed Action 

diameter trees (e.g. potential suitable habitat for northern spotted owl) on the edges of the 

construction right-of-way and TEWAs would also be flagged and saved as green recruitment or 

habitat trees, where possible. Some of these trees would be girdled to create snags to benefit 

wildlife. Snags and habitat trees would be retained if they do not pose a safety hazard to 

construction activities, as per the regulations outlined by OSHA. A more detailed discussion of 

snags and large down wood retention for wildlife habitat, including recruitment in LSRs and 

riparian reserves, can be found in section 4.5.3. 

Because the proposed construction right-of-way is not wide enough to accommodate timber 

clearing simultaneously with other pipeline construction activities, Pacific Connector proposes to 

clear forested areas during the year prior to the start of other pipeline construction activities. 

Pacific Connector would implement the measures outlined in its ECRP to prevent erosion of 

exposed soils along the right-of-way between clearing and final restoration. Some of the BMPs 

that would be implemented during timber clearing operations to minimize the potential for 

erosion and sedimentation would include: 

• scarification of compacted soils to promote infiltration and reduce runoff; 

• use of slash/brush piles at appropriate locations to limit water from running off the rightof-way; 

• installation of temporary slope breakers on steep slopes; 

• installation of silt fences or straw bales as sediment barriers; 

• seasonal seeding using quick-germinating species such as annual ryegrass on non-federal 

lands (assuming the permission of the landowners); and 

• selective mulching of areas without effective surface cover. 

Most of the pipeline route in forested areas is expected to be logged by mechanical cutting and 

ground skidding equipment. Hand-felling would likely occur on steep slopes; and skidding 

patterns would be laid out to minimize erosion. The USFS recommends that no tractor logging 

occur on slopes exceeding 35 percent on federal lands, and that other yarding methods including 

cable systems and helicopter logging be used instead in those areas. Cable and helicopter 

logging would minimize impacts on soils. Where log skidding would be done using mechanical 

methods, Pacific Connector proposes to employ the following methods where feasible to reduce 

the potential for soil compaction: 

• low-ground weight (pressure) vehicles would be used as much as possible; 

• removal of duff would be avoided, if possible, so that it remains as a cushion between 

equipment, felled logs, and soils; 

• designated skid trails, preferably over the proposed pipeline trench location, would be 

used as much as possible to limit the footprint of logging disturbance on soils within the 

construction right-of-way; and 

• landings, yarding, and load-out areas used for timber harvesting (TEWAs) would be 

scarified after use and prior to the rainy season where the potential for sediment deliver to 

waterbodies is possible. Scarification would promote infiltration, and minimize runoff. 

Pacific Connector indicated that it may use helicopters for logging and pipe stringing within the 

following locations where there are steep slopes and limited access to the right-of-way: 

• MPs 37.3 to 38.3 
2-85 2.0 – Description of the Proposed Action 

• MPs 78.0 to 83.0 

• MPs 88.5 to MPs 105.0 

• MPs 108.5 to 109.8 

• MPs 134.0 to 136.0. 

During forest clearing, all operations and tree falling would occur within the authorized 

construction work areas. Some TEWAs, that are already vacant areas adjacent to existing roads, 

have been identified for log storage and decking. In addition, some slash and other debris from 

clearing activities may be temporarily stored in UCSAs. 

Trees would be felled or sheared in a manner that would not impact adjacent forest or structures 

outside of the right-of-way. Trees would also be felled away from wetlands, waterbodies, and 

riparian reserves. Pacific Connector would not remove stumps or root systems from wetlands, 

except along the trench line, unless necessary for safety reasons during construction. In upland 

forest, Pacific Connector would also limit stump removal to the trench line and areas where 

grading would be necessary to create a level working surface. Any debris as a result of tree 

cutting that falls into a waterbody would be removed, if practical. Logs and slash would not be 

yarded across perennial streams unless fully suspended. Existing logs firmly embedded into the 

bed or banks of streams would not be disturbed, unless their removal is necessary for clearing the 

right-of-way, trenching, or fluming or other waterbody crossing methods. Any existing logs 

removed from waterbodies during installation of the pipeline would be returned during 

restoration. Landings for clearing operations would not be located in wetlands or riparian 

reserves. Where feasible, logs yarded out of wetlands or riparian zones would be skidded with at 

least one end suspended from the ground so as to minimize soil disturbance. Any cut timber 

designated for in-stream or upland wildlife habitant enhancements would be stored at the edge of 

the right-of-way or in TEWAs for later use during restoration activities. The use of timber cut 

from the right-of-way as in-stream large woody debris (LWD) is discussed in section 4.3.4.1 of 

this EIS. 

The typical size of trees to be cleared in forested areas along the pipeline route are considered 

too large by Pacific Connector to be taken whole for yarding. Therefore, trees would be cut, 

topped, limbed, and bucked on site where they have fallen. Generally, only the logs would be 

yarded to a landing for decking, loadout, and transport. So, the remainder of the wood debris 

from clearing (i.e., tree tops and limbs) would remain on the ground within the construction 

right-of-way where the trees were cut. During logging, tree tops and limbs would be broken or 

crushed creating a volume of small slash that would be impractical to remove from the right-ofway. Some of the slash on the ground would act as erosion control between the time the rightof-way is cleared and the pipeline is installed. 

Slash from timber clearing would be stockpiled on or at the edge of the right-of-way or TEWAs or within 

UCSAs, and scattered/redistributed across the right-of-way during final cleanup and restoration, after 

seeding, according to BLM and USFS fuel loading specifications to minimize fire hazard risks. 

Scattering the slash across the right-of-way would hinder off-highway vehicle traffic on the right-of-way 

and would act as a natural mulch to minimize erosion. The USFS has asked for additional details on 

equipment and methods that would be use for slash pull back and spreading on the right-of-way. In 

general, equipment would be that used for pipeline construction, and could include track hoes and bull 

dozers. Specific equipment and methods can be determined through ongoing consultation between 

Pacific Connector and USFS, and specified in the POD for each National Forest. 
2-86 2.0 – Description of the Proposed Action 

Pacific Connector proposed a modification from the FERC staff’s Plan to allow more than 1 ton 

per acre of woody material (logs, slash, and chips) to be scattered across the right-of-way during 

final cleanup. Pacific Connector would use the fuel loading standards of the BLM and the USFS 

as the limit for the quantity of woody debris that would be distributed across the right-of-way. 

The FERC staff’s Plan states that if wood chips are used as mulch, not more than 1 ton per acre 

of chips should be used, and the equivalent of 11 pounds of available nitrogen should be added 

where chips are used as mulch. The purpose of section IV.F.3.e. of the FERC staff’s Plan is to 

ensure that revegetation efforts are not hindered due to the decaying process of large amounts of 

wood chips, which can bind up soil nitrogen and impede revegetation. Pacific Connector 

believes it would be impractical and infeasible to remove this material from the right-of-way and 

stated that it is a typical silvicultural practice in the area to leave forest slash in logged areas. 

Furthermore, Pacific Connector thinks that the woody slash material would not deplete soil 

nitrogen in the short-term, during revegetation establishment, because the size of the woody 

material that would be scattered on the right-of-way would be large and would not readily decay 

in the short term. However, Pacific Connector also proposes to apply a standard fertilization rate 

of 200 pounds per acre bulk triple-16 fertilizer (16:16:16 - nitrogen, potassium and phosphorus) 

on all disturbed areas to be reseeded, except in wetlands and in federally designated Riparian 

Reserves (Section 10.8 of Pacific Connector’s ECRP). This fertilization rate would apply 32 

pounds per acre of elemental nitrogen, potassium, and phosphorus. The elemental nitrogen rate 

would also satisfy the FERC’s requirement to add nitrogen where wood chips are used as mulch. 

We find this project-specific modification to the FERC staff’s Plan acceptable. 

On NFS lands, the maximum amount of slash that would be scattered across the right-of-way 

would be 12 tons per acre, and on BLM and private lands the maximum would be 15 tons per 

acre. Table 2.4.2.1-1 lists maximum slash allowed by fuel loading size classes. 

As provided by the USFS, dead and downed woody debris greater than 16 inches in diameter 

does not contribute to fire hazard and would be maintained on site. Slash may be chipped and 

scattered across the right-of-way provided that the average depth of wood chips covering the area 

does not exceed 1 inch following application. This chip depth would be sufficient to stabilize the 

soil surface from erosion while allowing grass seed to germinate and seedlings to develop. It is 

not expected to significantly increase fuel hazards as long as the maximum tonnage for fuel 

loading does not exceed 12 tons per acre. 

TABLE 2.4.2.1-1 

Fuel Loading Specification by Size Class

Size Class (diameter) Tons/Acre 

NFS lands 

 0 to 1/4 inch < 1 

 1/4 to 3 inches 4-8 

 3 to 8 inches 7-12 

 Maximum 12 

BLM and Private Lands 

 0 to 1/4 inch < 1 a/

 1/4 to 8 inches 5-8 1 

 >8 inches 10-15 

a/ Adapted from USFS Fuel Loading Standards 
2-87 2.0 – Description of the Proposed Action 

In areas where the fuel loading exceeds these standards, Pacific Connector would machine or 

hand pile and burn the excess material depending on the site location, according to the 

requirement of the landowner. Burning would occur during the appropriate burning season and 

according to the conditions permitted by the BLM, USFS, and the ODF. A prescribed burning 

plan would be developed and submitted to the appropriate agencies for the necessary permits. 

The burning plan would describe the measures to be implemented by Pacific Connector, to 

conduct this activity in a safe manner and reduce the potential for a wildfire, including: 

• Slash piles to be burned would be located within the construction right-of-way but 

separated away from surrounding vegetation to prevent potential ignition; 

• The slash burn pile would be limited in height and size so the burn can be controlled; 

• The area surround the slash burn pile would be kept free of flammable debris; 

• Pacific Connector would have fire suppression tools available at the site of the prescribed 

burns; 

• Pacific Connector would use fire watchmen, as appropriate, during burning operations; 

and 

• Pacific Connector would not conduct slash burning within one-quarter mile of an 

occupied marbled murrulet stand or occupied northern spotted owl next patch during the 

critical breeding season (see section 4.6.1.2). 

On federal lands, larger slash pieces (more than 8 inches in diameter), may be removed from the 

right-of-way and decked in designated storage sites or at road crossings, as stipulated by the 

land-managing agencies. This material would be made available to the public through the 

agencies’ firewood programs. Some large wood debris would be left on the right-of-way, as 

determined by the BLM and USFS, as retained down wood for wildlife habitat and to aid in soil 

productivity. 

During clearing operations, existing fences crossed by the pipeline right-of-way would be cut 

and braced, and temporary gates installed to control livestock and limit public access to the rightof-way. Temporary erosion controls would be installed immediately after vegetation clearing 

and would be maintained throughout construction, and reinstalled as necessary until replaced by 

permanent erosion controls or until restoration is complete. Pacific Connector’s ECRP outlines 

proposed erosion control methods for the proposed Pacific Connector facilities, and these 

measures are more fully discussed under section 4.2 of this EIS. Following clearing, the rightof-way would be graded where necessary to create a reasonably level working surface to allow 

safe passage of construction equipment and materials. 

Also during grading activities, topsoils would be separated from subsoils, and each would be 

stored in segregated piles within the construction right-of-way and TEWAs. The FERC staff’s 

Plan requires topsoil segregation in residential areas, agricultural lands, pastures and hayfields, 

and in other areas as required by the landowner. The topsoil should be stripped either across the 

entire construction right-of-way, or over the trench line and soil storage areas. In wetlands, the 

FERC staff’s Procedures require that the top foot of soil over the trench line be salvaged, except 

in areas of standing water or saturated soils. The USFS has stipulated that topsoil should be 

stripped where the pipeline would cross NFS lands, but Pacific Connector has balked at this 

request. We further discuss this issue under section 4.2. 
2-88 2.0 – Description of the Proposed Action 

Trenching 

A rotary trenching machine, rock trencher, track-mounted backhoe, or similar equipment would 

be used to excavate a trench to a sufficient depth to provide the necessary minimum depth of 

cover. According to the DOT requirements in 49 CFR 192.327, the minimum depth of cover for 

a buried natural gas transportation pipeline must be: 

• 30 inches in normal soil and 18 inches in consolidated (solid) rock for Class 1 locations; 

and 

• 36 inches in normal soil and 24 inches in consolidated rock for Class 2, 3, and 4 

locations, and under drainage ditches, public roads, and railroad crossings. 

Pacific Connector intends to exceed DOT requirements where possible, and bury its pipeline up 

to 36 inches deep in Class 1 areas with normal soils and 24 inches deep in places with 

consolidated rock. 

Spoil material excavated during trenching operations would be temporarily piled to one side of 

the right-of-way adjacent to the trench. In areas where topsoil stripping is required, the topsoil 

and subsoil would be stored in separate windrows or piles on the construction right-of-way and 

would not be allowed to mix. 

In areas with bedrock is found close to the surface within the proposed trench depth, Pacific 

Connector would first attempt to dig the trench with specialized equipment, such as rock saws, or 

ripping using hydraulic hammers. However, if these methods are ineffective, blasting may be 

necessary to achieve the required trench depth. Pacific Connector prepared a Geologic Hazards 

and Mineral Resources Report, filed as part of its application to the FERC, which classifies 

blasting potential along the route based on existing soil and bedrock data. Blasting potential was 

classified as high for about 100 miles of the proposed pipeline route. All blasting would be done 

by licensed contractors under the terms of applicable regulatory requirements. Blasting is further 

discussed in section 4.1.3 of this EIS. 

Stringing, Bending, and Welding 

After trenching is complete, individual sections of pipe would be delivered to the construction right-ofway and strung along the trench. The pipe would be delivered in straight joints, typically 40 feet long. 

Usually, the steel pipe is transported from its place of import (if foreign made) or manufacture site (if 

domestically produced) via railroads to storage yards designated by Pacific Connector. As previously 

discussed in section 2.3.3.1, many of these pipe storage yards are within existing industrial facilities, or 

on agricultural land. The pipe would then be trucked from the storage yards to the construction rightof-way along access roads designated by Pacific Connector. Pacific Connector’s Traffic Management 

Plan would take into account construction equipment traffic, including pipe trucks, on the access roads, 

and its potential impact with existing users of those roads. This EIS addresses the potential 

environmental impacts associated with use of the pipe storage yards and access roads, and we required 

Pacific Connector to conduct appropriate surveys for waterbodies, wetlands, wildlife and vegetation, 

and cultural resources for yards and roads that would be improved as a result of the pipeline project. 

Some bending of the pipe would be required to allow the pipeline to follow natural grade 

changes and direction changes of the right-of-way. Some pre-fabricated pieces of pipe would be 

delivered already bent. Other selected joints would be bent in the field by track-mounted 

hydraulic bending machines, as necessary. 
2-89 2.0 – Description of the Proposed Action 

The ends would be aligned and welded together using multiple passes for a full penetration weld. 

Only qualified welders would be permitted to perform the welding. Welders and welding 

procedures would be qualified according to applicable American National Standards Institute 

(ANSI), American Society of Mechanical Engineers, and API Standards. All welds would be 

visually and radiographically inspected and repaired, if necessary. Welding activities on NFS 

lands would be coordinated with the USFS, who indicated that it may impose limits on welding 

during fire restriction periods from June to October. Details of welding restrictions would be 

determined during ongoing consultations between Pacific Connector and the USFS, and details 

included in the POD prepared for each National Forest. 

Line pipe, normally mill-coated prior to stringing, would require field applied coating at the 

welded joints prior to final inspection. The entire pipeline coating would be inspected and tested 

to locate and repair any faults or voids. 

Lowering-in and Backfilling 

After welding and coating are completed, the pipe would be lowered into the trench by side-boom 

tractors. Before lowering the pipe, the trench would be inspected to ensure that it is free of rocks and 

other debris that could damage the pipe or the coating. In addition, the pipe and trench would be 

inspected to ensure that the configurations of the pipe and trench configurations are compatible. 

To prevent water from the trench from entering wetlands or waterbodies, Pacific Connector 

would install permanent trench plugs, consisting of sandbags, foam, or bentonite, at the base of 

slopes adjacent to wetlands and waterbodies, in accordance with its ERCP, and consistent with 

the requirements of the FERC staff’s Plan. In accordance with the FERC staff’s Procedures, the 

trench would be dewatered in a manner that does not cause erosion and does not allow silt-laden 

water to flow into any adjacent wetland or waterbody. 

Bladed equipment or a specially designed backfilling machine would be used to backfill the 

trench. No foreign substance, including skids, welding rods, containers, brush, trees, or refuse of 

any kind, would be permitted in the backfill. If rocks or other materials that could damage the 

pipe or coating are present in the backfill, a padding machine would be used to separate the rock 

from the backfill. In some instances, clean fill or additional protective coating such as rock 

shield would be placed around the pipe before backfilling. Excess rock from the trench would be 

left on the right-of-way or hauled to off-right-of-way disposal sites. 

Segregated topsoil, where applicable, would be replaced after backfilling the trench with subsoil. 

Following backfilling, a small crown of material would be left to account for any future soil 

settling that might occur. 

Hydrostatic Testing 

After backfilling, the pipeline would be hydrostatically tested in accordance with DOT 

regulations to ensure that the system is capable of operating at the maximum operating pressure. 

Should a leak or break occur during testing, the line would be repaired and retested until the 

specifications are achieved. Approximately 59 million gallons of water would be required to test 

the pipeline. 

Water for hydrostatic testing would be obtained from commercial or municipal sources or from 

surface water right owners. Potential hydrostatic test water sources identified by Pacific 

Connector are listed in table 2.4.2.1-2. If water for hydrostatic testing is acquired from surface 
2-90 2.0 – Description of the Proposed Action 

TABLE 2.4.2.1-2 

Potential Hydrostatic Test Water Source Locations 

County MP Source/Owner Volume (gal) 

Coos 0.00 Coos Bay - North Bend Water Board 12,531,362 

Douglas 50.20 Kinnan Lake – private 2,098,651 

Douglas 55.90 Ben Irving Reservoir – private 1,390,902 

Douglas 58.75 Olalla Creek Crossing - Looking Glass Olalla Water District 2,098,699 

Douglas 69.00 S. Umpqua River Crossing #1 – ODWR 5,572,843 

Jackson 94.73 S. Umpqua River Crossing #2 – ODWR 6,695,648 

Jackson 122.5 Rogue River Crossing – ODWR 8,770,257 

Jackson N. Fork Little Butte Creek Crossing - Medford Irrigation District 

Jackson 146.70 N. Fork Little Butte Creek Crossing - Rogue River Valley Irrigation District 1,883,276 

Jackson 161.40 Fish Lake – USFS/Medford Irrigation District 3,420,951 

Klamath 168.90 Lake Of The Woods – private 4,102,136 

Klamath 184.30 John Boyle Reservoir – private 1,282,231 

Klamath 189.00 Keno Reservoir – private 2,859,703 

Klamath 199.20 Klamath River – ODWR 

Klamath 228.70 Malin High Line Canal – Malin Irrigation District 5,616,269 

Total 58,322,928 

water sources, Pacific Connector would obtain all necessary appropriations and withdrawal 

permits prior to construction, including permits through the ODWR. As part of this process, 

ODWR would have the applications reviewed by ODEQ and ODFW to determine if there are 

concerns about the impact water withdrawals may have on water quality, and fish and wildlife 

and their habitats. Pacific Connector would negotiate water appropriations with private owners 

in the year prior to construction. 

Pumps used to withdraw surface water would be screened according to ODFW standards to 

prevent entrainment of aquatic species. Pacific Connector does not anticipate a need to add 

chemicals to the hydrostatic test water. 

The pipeline would be tested in approximately 74 sections; each with varying lengths and water 

volume requirements. Test sections and discharge locations within the construction right-of-way 

are listed in table E-3 in Appendix E. During the test, it may be necessary to discharge water at 

each of the section breaks; however, Pacific Connector would conserve water as much as 

practical and minimize discharge where feasible by cascading water between test sections. In 

addition to the 74 test header section breaks located within the construction right-of-way or 

TEWAs, Pacific Connector has identified seven potential hydrostatic test water discharge 

locations (table 2.4.2.1-3) outside of the construction right-of-way and TEWAs that were 

previously mentioned in this EIS. 

TABLE 2.4.2.1-3 

Potential Hydrostatic Discharge Locations Outside of the Construction Right-of-Way 

MP Size (acres) 

Corresponding Test 

Section(s) Ownership/ Jurisdiction 

8.40 0.13 1, 2 Private 

57.72 0.13 17, 18 Private 

69.31 0.13 21, 22 Private 

88.09 0.46 33, 34 Private 

127.39 0.13 52, 53 Private/BLM 

190.07 0.17 66, 67 Private 

208.29 0.14 72, 73 Private/BOR 

Total 1.29 
2-91 2.0 – Description of the Proposed Action 

If hydrostatic testing identifies a leak or break within one of the 74 test sections, that section 

would be drained, the leak or break corrected, and the test repeated. The process for the repeat 

test would be the same as the initial test, including cascading test water from, or to, other test 

sections where possible to minimize water usage. 

Permission to discharge the hydrostatic test water would be applied for concurrently with the 

request for coverage under the ODEQ General Stormwater Discharge Permit and permitted 

through a separate letter of approval. Hydrostatic test water would be discharged in upland 

settings, into erosion control devises, to minimize the potential for scour, erosion, and 

sedimentation into nearby wetlands and waterbodies, in accordance with Pacific Connector’s 

ECRP. Straw bale barriers and silt fence would typically be used to retain sediment and reduce 

velocity. Discharge rates would range from several hundred gallons per minute to several 

thousand gallons per minute, depending on the length of the test section, profile, topography, 

vegetation cover, and soil type, as reviewed by the contractor and the EI. Concerns have been 

identified with the proposed hydrostatic testing plan, including the potential transfer of invasive 

species where the intake and discharge points are in different watersheds. See additional 

discussion of hydrostatic testing in section 4.3.2 of this EIS. 

Dust and Fire Control Water 

During pipeline construction, Pacific Connector would need to obtain water for dust and fire 

control purposes. Control of construction generated fugitive dust may be necessary during dry 

periods, such as the summer. The EI would direct dust control efforts to places deemed 

necessary, including residential areas and other locations along the pipeline route where dust is 

considered a safety or public nuisance, including access roads. Typically, water trucks would fill 

up with water at designated sources, and spray selected areas along the construction right-of-way 

and access roads, to keep dust down. The water trucks would spray only enough water to control 

dust or reach an optimum soil moisture content, and not enough to create a problem with water 

runoff, erosion, and sedimentation. The sources of water for dust and fire control are listed in 

table 2.4.2.1-4. Water use during pipeline construction activities and its potential impact on 

water resources and aquatic species is more fully discussed in section 4.3. Dust is further 

discussed under air quality in section 4.11.1. 

TABLE 2.4.2.1-4 

Sources of Dust and Fire Control Water

MP County Source Owner 

16.5 Coos Aqueduct Lake Private 

50.2 Douglas Kinnan Lake Private 

79.0 Douglas Big Lick Reservoir Private 

122.5 Jackson Indian Lake Reservoir Private 

133.4 Jackson Eagle Point Irrigation Canal Private 

145.0 Jackson Gardner Reservoir Private (Medford Irrigation District) 

228.5 Klamath High Line Canal Private (Malin Irrigation District) 

228.7 Klamath Capek Reservoir Private 

229.4 Klamath Low Line Canal Private (Malin Irrigation District) 
2-92 2.0 – Description of the Proposed Action 

Cleanup and Permanent Erosion Control Devices 

Pacific Connector would make every effort to complete final cleanup of an area within 20 days 

after backfilling the trench. Final cleanup would include final grading and installation of 

permanent erosion control structures. In no case would Pacific Connector delay final cleanup 

beyond the end of the next recommended seeding season. During final cleanup, Pacific 

Connector would remove all construction debris and grade disturbed areas to approximate preconstruction contours to the extent practicable. During final cleanup and initial restoration, 

fences, gates, drainage ditches, culverts, and other structures that may have been temporarily 

removed or damaged during construction would be permanently repaired, returned to their preconstruction condition, or replaced. All drain tiles crossed by the pipeline would be checked, 

and if damaged, they would be repaired before backfilling. All areas disturbed by construction 

activities would be re-graded during restoration, with contours matching the surrounding 

landscape, and pre-construction natural drainage patterns re-established. Pacific Connector 

would install erosion control fabric (such as jute or excelsior) to stabilize streambanks during 

restoration. 

Travel Lane 

Because of limited access to the construction right-of-way in several areas, Pacific Connector 

anticipates that it would be necessary to leave a travel lane open within the right-of-way for 

extended lengths of the construction right-of-way. As soon as access is no longer required, the 

travel lane would be closed and the disturbed area reclaimed. To reduce erosion from the travel 

lane, Pacific Connector would install appropriate temporary erosion controls in areas where the 

travel lane is temporarily left open. Temporary waterbody crossings would be left in place 

where necessary along the travel lane. Erosion control would be done in accordance with Pacific 

Connector’s ECRP. Although the travel lane would not be designed for public access, it is 

possible that non-construction personnel could use the right-of-way for travel while pipeline 

construction is underway. The USFS has requested additional detail on locations where a travel 

lane may be left open and estimates of how long. This information could be included in the POD 

prepared in consultation with the USFS prior to construction. 

Excess Rock Removal 

In accordance with its ECRP, Pacific Connector would remove of excess rock from the top 12 

inches of soil in cultivated or rotated croplands, hayfields, pastures, residential areas, and other 

areas at the landowner’s request. In these areas, Pacific Connector would clean up excess rock to 

a condition (size, density, and distribution) similar to lands adjacent to the construction right-ofway. In rangeland, forest, or other non-agricultural or residential lands where shallow bedrock is 

encountered and rock excavation is required, some of the rock would be scattered across the 

right-of-way and TEWAs according to landowner agreements. Large rocks or boulders may be 

used at road crossing and at the edges of the right-of-way in selected areas to form barriers to 

OHVs. In addition, rocks may be placed in specified upland areas to create habitat diversity 

features, according to the direction of the federal land-managing agencies or landowners. Excess 

rock would be hauled to approved landfills, commercial quarries, or other designated off-site 

disposal areas listed in table 8A-4 in Appendix A of Pacific Connector’s environmental Resource 

Report 8 filed with its application to the FERC. 
2-93 2.0 – Description of the Proposed Action 

Permanent Erosion Control Devices 

Pacific Connector would install permanent erosion control devices consistent with the 

requirements as described in its ECRP. The permanent erosion control measures include trench 

breakers, slope breakers or waterbars, and revegetation to stabilize disturbed areas. Pacific 

Connector would consult with the BLM, BOR, and USFS regarding the installation of permanent 

erosion control structures on federal lands, and with the NRCS regarding such structures on nonfederal lands. The permanent erosion control measures developed by Pacific Connector in its 

ECRP are generalized to be consistent with different agency requirements based on slope and 

soil types crossed by the proposed pipeline. Pacific Connector’s ECRP specifies the installation 

of slope breakers as follows: 

Permanent Slope Breaker Spacing 

Slope 

Highly Erodible or 

Grantite Soils 

Soils With Moderate or Low 

Potential for Erosion 

0 to 5 percent None required None required 

5 to 15 percent 100 feet 200 to 300 feet 

15 to 30 percent 50 to 75 feet 75 to 100 feet 

Greater than 30 percent 50 feet 50 feet 

Soil Compaction 

Pacific Connector’s ECRP requires the use of penetrometers or other appropriate devices to test 

for compaction of soils after installation of the pipeline, backfilling, and re-grading in 

agricultural and residential areas disturbed by construction. Pacific Connector indicated that soil 

compaction testing would be conducted by its EIs, and that the results would be compared to 

tests of similar soil types under similar moisture conditions in adjacent undisturbed areas. 

Pacific Connector has agreed to the land managers’ request that soil compaction testing be 

conducted where the pipeline would cross federal lands. The BOR indicated that Pacific 

Connector would need a temporary authorization for right-of-way entry on its lands prior to 

performing this testing. On federal lands, compaction testing would confirm whether detrimental 

compaction resulting from construction exceeds 15 percent in comparison to adjacent 

undisturbed areas. Corrective measures would be implemented in accordance with directions 

from the land-managing agencies. These corrective measures could include localized deep 

scarification or ripping to an average depth of 18 inches. Disking, ripping, or chiseling to loosen 

areas of compacted soils could be done using brush blades, wing-tipped rippers, chisel plows, 

agricultural disks, or other appropriate equipment. Scarification should not be necessary over the 

trench, as backfilling should eliminate compaction of soils and equipment would not be allowed 

to drive over the installed pipeline. More details about mitigation measures for soil compaction 

are provided in section 4.2 of this EIS. 

Revegetation 

All areas disturbed by construction, including the construction right-of-way, TEWAs, UCSAs, 

and contractor yards as necessary, would be restored and revegetated in accordance with Pacific 

Connector’s ECRP. Prior to seeding, the disturbed areas would be prepared as a seedbed 

approximately 3 to 4 inches deep using appropriate equipment, as necessary in certain areas, as 

determined by the EI. This could include chisel plowing or disking. In most areas, typical regrading and contouring during restoration would create a suitable rough, yet firm, seedbed, 

conducive to capturing seeds and retaining soil moisture. In residential and cropland areas, 
2-94 2.0 – Description of the Proposed Action 

additional cleanup activities prior to the preparation of a proper seedbed may include rock 

removal. 

Pacific Connector would work with individual landowners in agricultural areas to determine how 

the right-of-way would be restored where the pipeline would cross cropland, orchards, nurseries, 

or vineyards. Usually, in agricultural areas, the landowner determines whether or not Pacific 

Connector would be responsible for seeding. In some situations, the owner of agricultural land 

may do the final restoration and seeding and Pacific Connector would compensate the landowner 

for those efforts. In residential areas, Pacific Connector would restore disturbed lawns, 

ornamental shrubs, gardens, and other landscape features in accordance with their agreement 

with the landowner. The restoration work in residential areas would be done by a contractor 

familiar with local horticultural or landscape practices, or Pacific Connector may choose to 

compensate a landowner to restore their property. 

Based on Oregon State University Extension Service recommendations for fertilization rates for 

nitrogen fertilizer on new pasture seedlings, Pacific Connector intends to use a standard 

fertilization rate of 200 pounds per acre bulk triple-16 fertilizer on disturbed areas to be seeded. 

The NRCS did not recommend the addition of lime or other soil pH modifiers. Fertilizer would 

not be used in wetlands, unless required by the land-managing agencies, and would not be 

applied within 100 feet of streams. The fertilizer would be stored outside of riparian reserves 

and away from streams, and would not be applied during heavy rains or high wind conditions. It 

could be either broadcast, or incorporated in the slurry for hydroseeding. 

It is expected that seeding would be timed to begin in August and could extend into the winter 

months at lower elevations. Seeding may be done by broadcast methods, drilling, or 

hydroseeding. Broadcast seeding, using a mechanical broadcaster seeder, is the preferred 

method of seeding on steep slopes. After broadcast, the seedbed would be dragged by chains or 

other appropriate harrows to cover the seeds thinly with soil. Hydroseeding would be done in 

accessible upland areas. Hydroseeding equipment would include tanks, pumps, nozzles, and 

other devises for mixing the seed hydraulically with wood fiber mulch and tackifier. A built-in 

agitator would keep the seed, mulch, tackifier, and water mixed together homogeneously until 

pumped from the tank. A drill seeder pulled by a plow may be used in gently sloping areas. 

The seed mixtures, which are further discussed in section 4.4 of this EIS, were determined in 

consultations with the land-managing agencies and the NRCS. The seed mixtures on BLM land 

were developed based on BLM Instruction Memo-2001-014, which specifies the use of native 

species, if possible. During right-of-way easement negotiations, private landowners may select 

their own seed mixtures other than those proposed for elsewhere along the pipeline route. The 

seed mixture seeding rates are based on Pure Live Seed. The seed mixture should be free of 

noxious weeds. 

Mulch would be applied on slopes were necessary to stabilize the right-of-way after seeding. 

Mulch would consist of native wood chips, wood fiber mulch mixed with the hydroseed, bonded 

fiber matrix to be used on slopes steeper than 40 percent grade (greater than 2.5 to 1), and 

certified weed-free straw. 

2.4.2.2 Special Pipeline Construction Techniques 

Construction in rugged topography; across wetlands and waterbodies; through agricultural, 

residential, commercial, and industrial areas; at road and railroad crossings, and across foreign 
2-95 2.0 – Description of the Proposed Action 

pipelines and other utilities may require special construction techniques. Special techniques 

would also be used if blasting is required. These techniques are described below. 

Rugged Topography 

A portion of the proposed pipeline route would cross rugged topography as it traverses over 

various mountain ranges and foothills. Where the pipeline would pass through the Coast Range 

between Coos Bay and Myrtle Creek, Oregon (MPs 0.0 to 48.0), most of the ridgelines run in the 

opposite direction of the proposed pipeline alignment. The orientation of the ridges would 

require the pipeline, in numerous areas, to descend and ascend steep ridge slopes to cross stream 

valleys so that the alignment can proceed in a southeasterly direction. A similar condition also 

occurs between MPs 61 and 127 where the pipeline would cross the Cascade Range. During 

routing of the proposed pipeline, Pacific Connector utilized ridgelines, where feasible, to 

minimize crossing steep slopes, potential geologic hazards, and waterbodies as well as to reduce 

erosion hazards. Areas of steep side slopes were avoided as much as practical to minimize 

construction complications. 

During construction across rugged topography, Pacific Connector would use the following 

measures, as necessary, to minimize construction, geologic and erosion hazards as well as to 

ensure the integrity of the pipeline: 

• utilize appropriate construction techniques to minimize disturbance and to provide a safe 

working plane during construction (i.e., ridge top and two-tone construction); 

• identify adequate TEWAs for spoil storage; 

• use BMPs appropriate for construction on steep slopes, such as temporary cribbing to 

store material on the slope, or hauling material to a more stable area; 

• optimize the construction window during the dry season, as much as practicable; 

• utilize temporary erosion control measures during construction (i.e., slope 

breakers/waterbars); 

• install trench breakers in the pipeline trench to minimize groundwater flow down the 

trench which can cause in-trench erosion; 

• properly backfill the trench according to Pacific Connector’s construction specifications; 

• promptly restore the right-of-way to approximate original contours or to a stable contour 

after pipe installation and backfilling; 

• install properly designed and spaced permanent waterbars; 

• revegetate the slope with appropriate and quickly germinating seed mixtures; 

• provide effective ground cover using slash or mulching, or install erosion control fabric 

on slopes, as necessary; and 

• monitor and maintain the right-of-way as necessary to ensure stability. 

Pacific Connector’s ECRP includes specific procedures for construction techniques in areas of 

rugged topography. 

Waterbody Crossings 

Pacific Connector’s pipeline would cross 218 waterbodies (with several streams crossed multiple 

times). Waterbodies would be crossed in accordance with the FERC staff’s Procedures and 

applicable permits from other agencies. Pacific Connector would use the following methods to 

cross waterbodies: wet open cut, diverted open cut, dry open cut, convention boring, and HDD. 
2-96 2.0 – Description of the Proposed Action 

These are briefly described below. A more detailed discussion of waterbodies is provided in 

section 4.3 of this EIS. 

Waterbodies that are classified as coldwater fisheries would be crossed during the in-water work 

window recommended by the ODFW. Pacific Connector would like to cross intermittent 

flowing streams, and irrigation canals and ditches when they are dry, using standard upland, 

cross-country pipeline construction methods. If water is flowing at the time of the crossing, a 

dry crossing method would be used (i.e., flume or dam and pump, see below). The standard 

depth of cover would be 5 feet below intermittent flowing streams and ditches. 

The BOR would require that the pipeline be installed at least 3 feet below the bed of facilities 

over which it has jurisdiction, and that all work be done during the non-irrigation season 

(between October 15 and March 15) so as to not interfere with Klamath Project operations. Not 

all irrigation canals or ditches completely dewater after the irrigation season, and some facilities 

have been piped. In those situations, Pacific Connector would need to bore under the facilities. 

Pacific Connector would place temporary bridges over the waterbodies, to be used by equipment 

during all phases of construction. Equipment bridges over waterbodies would typically be 

installed during clearing activities, and removed after the pipeline has been installed, and the 

crossing restored. The bridges would be constructed to support the weight of the construction 

equipment, and maintain unrestricted flow of the stream below. Where feasible, bridges would 

span the entire ordinary high water mark (OHWM) of the waterbody. Temporary construction 

bridges would be installed in accordance with the FERC staff’s Procedures and Pacific 

Connector’s ECRP, as well as applicable requirements of the COE, BLM, BOR, USFS, ODSL, 

ODEQ, and ODFW. Additional details of temporary construction bridges used on federal lands 

can be determined during ongoing consultation between Pacific Connector and land management 

agencies, and included in the PODs for each land management unit. However, Pacific Connector 

proposes to install equipment bridges outside the ODFW recommended in-water construction 

windows. 

Flume

The flume method is a dry crossing technique used for small to intermediate width streams (less 

than 100 feet across) that allows water flow and fish passage during pipeline construction. Water 

would be diverted across the trenching area through one or more flume pipes placed in the 

waterbody of suitable diameter to convey the maximum flow. Temporary sandbag and plastic 

sheeting dams would be used to support and seal the ends of the flume and to direct stream flow 

into the flume and over the construction area. These temporary dams at both the upstream (inlet) 

and downstream (outlet) sections of the flume would create a containment area in between where 

turbid water would be confined. Fish would be salvaged from this confined area between the 

dams. Then water would be pumped out, through an upland dewatering structure, to create a dry 

work area for gas pipeline installation. All in-stream work (trenching, pipeline installation, and 

backfilling) would be conducted while the flume is in place, and the flume would be removed 

immediately after backfilling and bottom recontouring is completed. Appropriate-sized gravel 

would be placed in the streambed, and stream banks would be re-established to pre-construction 

conditions, and stabilized using the erosion control measures outlined in Pacific Connector’ 

ECRP. 
2-97 2.0 – Description of the Proposed Action 

Dam and Pump

The dam and pump method is an alternative dry construction technique that can be used to cross 

small or intermediate width waterbodies. It is similar to the flume crossing method except that 

pumps and hoses would be used instead of flumes to move water across the construction work 

area. This method is preferred where the stream bottom is hard bedrock requiring blasting, so 

that in-water blasting could be avoided. The technique involves temporarily damming the 

waterbody with sandbags with plastic liner, steel plates or piling, jersey barrier, aquadams, or 

portadams upstream and downstream of the trench area. Pumps would be set up at the upstream 

dam with the discharge line routed through the construction area to discharge water directly back 

into the waterbody immediately downstream of the construction work area. Pump intakes would 

be screened to prevent the entrainment of aquatic species. An energy-dissipation device would 

be used to prevent scouring of the streambed at the discharge location. Water flow would be 

maintained through all but a short reach of the waterbody at the actual crossing. The dam and 

pump would be set up immediately before the crossing begins, and trenching, pipeline 

installation, and backfill would occur while the dam and pump is in operation. After backfilling, 

the dams would be removed and the banks restored and stabilized. Pacific Connector would 

cross streams using the dam and pump method during the ODFW recommended in-water work 

windows. 

Conventional Boring

Pacific Connector intends to cross at least three waterbodies (Kentuck Slough at MP 6.3, 

Catching Slough at MP 11.1, and Medford Aqueduct at MP 133.4) using conventional bore 

methods. There are different kind of boring methods, including jack and bore, slick bore, and 

hammer bore, and the type of method to be used at these specific locations has not yet been 

determined by Pacific Connector. Boring is typically used for crossing under roads or railroads 

without disturbing those entities (see discussion below on roads and railroads). During a 

standard boring operation, bore pits may be excavated on both ends of the bore, and spoil 

removed from the bore. The walls of the bore pits may have to be supported by trench boxes or 

metal sheet piling. If groundwater seeps in to the bore or bore pits, a dewatering system would 

need to be used. Pipe would be welded in the bore pit, and passed through the bore hole. 

Horizontal Directional Drilling

Pacific Connector proposes to cross three waterbodies (Coos River, MP 8.18; Rogue River, MP 

122.65; and Klamath River, MP 199.38) using the HDD construction method. This technique 

involves drilling a pilot hole under the waterbody, then enlarging that hole through successive 

reamings until the hole is large enough to accommodate the pipe. Throughout the process of 

drilling and enlarging the hole, a slurry made of naturally occurring non-toxic materials, such as 

bentonite clay and water, would be circulated through the drilling tools to lubricate the drill bit, 

remove drill cuttings, and hold the hole open. This slurry is referred to as drilling mud. Pipe 

sections long enough to span the entire crossing would be staged and welded along the 

construction work area on the opposite side of the waterbody, hydrostatically tested, and then 

pulled through the drilled hole. The right-of-way between the entry and exit hole of an HDD 

would generally not need to be cleared or graded, except for the area of the guide wires, and 

direct impacts on the waterbody, adjacent riparian vegetation, and associated aquatic resources 

would be avoided through an HDD. 

However, there are two problems that may occur during the use of an HDD. First, there may be 

an unintentional release of drilling mud, forcing its way to the surface through underground 
2-98 2.0 – Description of the Proposed Action 

fissures. This situation is termed a “frac-out.” Second, the drill may be blocked by unexpected 

substratra soils or geological conditions (such as gravels or boulders). Pacific Connector 

proposed an HDD contingency plan and Failure Procedure, attached as Appendix 2I of its 

application to the FERC, which explains the measures it would implement to clean up and 

mitigate a frac-out situation, and what it would do if the HDD fails at a specific location. 

Wet Open Cut

Pacific Connector proposes to use wet open cut pipeline construction methods within the Coos 

Bay estuary, from about MPs 1.7 to 4.1. During this operation, the pipeline would be installed 

while water flows through the construction work area unimpeded. The in-water work within 

Coos Bay would be done from lay barges. From the barges, a trench would be dredged to 

accommodate a depth of burial of 5 feet to the top of pipe. The pipeline would be laid using a 

combination of the conventional S-Lay method and the “pipe push” method. For the S-lay 

method, a lay barge would advance along the pipeline route as welding of the pipe joints is 

completed and the pipeline is lowered into the trench. For the “pipe push” method, the lay barge 

would remain stationary, pipe joints welded on the barge, and the completed section pushed and 

floated out from the barge and then lowered into the pre-dredged trench. Spoil removed during 

dredging would be placed back into the pipe ditch after the pipe is installed and excess spoils 

would be smoothed over the bottom surface. At each landfall/shoreline approach, the pipeline 

would be installed by excavating the trench and installing the pipeline working from the shore 

and barges. 

Diverted Open Cut Crossing

Pacific Connector proposes to use a diverted open cut at the two crossings of the South Umpqua 

River at about MP 69.0 and MP 94.7, because the river is too wide for a typical dry crossing 

using either dam and pump or flume methods, and geotechnical studies indicated that subsurface 

conditions are not suitable for an HDD. At the first crossing location the river is divided by an 

existing gravel bar. Pacific Connector intends to block downriver flow of the main channel 

using a dam across to the bar, and divert that flow into the other channel. This dam may consist 

of imported riprap, concrete jersey barriers, water bladder portadams, or sand bags. At the 

second crossing the channel is not divided but is sufficiently wide and shallow to allow flow to 

be diverted to one side of the river while working in the other side. Because equipment would 

need to be in the river during installation of the diversion structures at both crossings, this work 

would be conducted during ODFW’s recommended in-water work window for the South 

Umpqua River, which is between July 1 and August 31. Fish would be salvaged from the area 

behind the dam, and pumps would dewater seepage into the work area to upland discharge 

structures. Then the pipeline would be installed and backfilled in the working area when it is 

dry. Trench spoil would be stored in the stream channel behind the diversion structure. The dam 

would then be moved to block the minor channel, and flow would be diverted to the main 

channel, so that the portion across the minor channel could be installed when it is dry. The two 

sections would be joined on the bar (first crossing) or in the center of the river (second crossing), 

probably within a trench box. 

Wetland Crossings 

Pacific Connector conducted wetland delineation surveys for about 90 percent of its pipeline 

route, and identified about 550 wetlands that would crossed. Pacific Connector would construct 

its pipeline across wetlands in accordance with the FERC staff’s Procedures, and the conditions 
2-99 2.0 – Description of the Proposed Action 

of the COE and other applicable permits. Pacific Connector would limit the width of the 

construction right-of-way through jurisdictional wetlands to 75 feet or less, where possible. 

TEWAs would be located at least 50 feet away from wetlands, except where topographic 

constraints prevent this, and Pacific Connector has proposed modifications to the FERC staff’s 

Procedures for these situations. The FERC staff’s Procedures require that the pipe for crossing 

wetland be assembled in adjacent uplands. Where feasible, the only access roads that would be 

used in wetlands are existing roads that can be used with no modifications and without impacting 

the wetlands. Wetlands are discussed in more detail in section 4.3 of this EIS, including 

alternative crossing methods and requested variances from the FERC staff’s Procedures. 

Standard wetland crossing measures include cutting vegetation to grade during clearing, and only 

removing stumps and roots within the trench and up to 15 feet from the edge of the trench. 

Sediment barriers would be installed after clearing, but prior to grading, along the edge of the 

construction right-of-way to prevent sediment flow into the wetland outside of the work area. 

During crossing of unsaturated wetlands (i.e., wetlands without standing water or saturated 

soils), construction would be similar to the upland cross-county techniques described above, but 

would also include segregation of topsoil over the trench line. Trench plugs would be installed 

where necessary to prevent the unintentional draining of water from the wetland. 

In wetlands with saturated soils or standing water Pacific Connector may operate equipment off 

of pre-fabricated wooden mats or timber riprap. Timber riprap would originate from trees 

cleared from the construction right-of-way. Typically, the “push-pull” or “float” techniques for 

pipeline installation would be used in saturated wetlands where water in the trench would allow. 

All materials used to support equipment, and sediment barriers, would be removed from 

wetlands after the pipeline is installed, the trench backfilled, and right-of-way restored. The 

FERC staff’s Procedures would not allow the use of fertilizer, lime, or mulch during restoration 

in wetlands, unless required by the appropriate land-managing agency. 

Agricultural and Residential Areas 

Pacific Connect estimated that the pipeline would cross about 32.4 miles of agricultural land, 0.7 

mile of residential land. Pacific Connector’s ECRP requires some special construction 

considerations for the crossing of agricultural and residential lands. However, Pacific Connector 

has not indicated that it would use special construction techniques to cross commercial or 

industrial lands, other than maintaining access to existing businesses whose driveways or access 

roads may be crossed by the pipeline. 

Pacific Connector developed site-specific construction plans for all residences within 50 feet of 

work areas. Some of the typical measures to be taken in residential areas include notification of 

landowners, limiting hours of construction, dust control, fencing the construction right-of-way, 

maintaining access, and replacing landscaping (see section 4.7). 

The FERC staff’s Plan requires topsoil segregation in all residential areas, and annually 

cultivated or rotated agricultural lands, pasture, and hayfields. In these areas, topsoil should be 

stripped and segregated from either the full construction right-of-way, or over the trench line and 

subsoil storage area. Pacific Connector identified about 120 places where it intends to salvage 

and segregate topsoil along the pipeline route (see table F-5 in Appendix F). Along the 

alignment where topsoil segregation is proposed, Pacific Connector has requested 10 feet of 

TEWA in addition to the 95-foot construction right-of-way. The purpose of this TEWA is to 
2-100 2.0 – Description of the Proposed Action 

provide space to stockpile and separate topsoil from trench subsoil. The USFS indicated that it 

wants topsoil be salvaged on NFS lands. However, Pacific Connector has proposed a 

modification from section IV.B. of the FERC staff’s Plan, which specifies that topsoil be 

salvaged according to landowner requests. This is further discussed in section 4.2. 

Another requirement of the FERC staff’s Plan is that excess rock should be removed from at 

least the top foot of soil in all actively cultivated or rotated cropland, pasture, hayfields, and 

agricultural lands. Pacific Connector would use rock pickers where necessary to remove excess 

rocks from these areas during cleanup. 

When crossing agricultural land, Pacific Connector would attempt to limit impacts on prime farm 

land, in keeping with compliance with the Farmland Protection Policy Act. Pacific Connector 

believes that its ECRP contains measures to reduce impacts on prime farm land, including top 

soiling and compaction relief. This is discussed further in section 4.2 of this EIS. 

The FERC staff’s Plan requires an applicant to consult with landowners and local soil 

conservation authorities to locate drain tiles. The BLM has identified that French drains were 

installed to stabilize Elk Creek Road near MPs 33.8 and 35.9. The pipeline crosses agricultural 

lands in Klamath County, which are underlain by drain tiles. The drain tiles are located along 

approximately 20 miles of the 40-mile agricultural area. The tiles are mostly small (4 to 6 

inches) and depending upon exact pipeline location and groundwater levels, impacts to the drain 

tiles are unknown at this time. Pacific Connector has not obtained the exact locations of the 

drain tiles along the proposed alignment but would identify the presence of drain tiles on 

individual properties during right-of-way easement negotiations. Drain tile repair and/or 

replacement should be a part of the easement agreement. Pacific Connector would ensure that 

any drain tiles cut or damaged by construction of the pipeline would be repaired before 

backfilling. See additional discussion in section 4.3.2.4. 

The proposed pipeline would cross numerous irrigation canals and ditches in agricultural fields 

in Klamath County. Some of the irrigation canals and ditches in this area are part of the BOR’s 

Klamath Project. To minimize agricultural impacts and to schedule the crossings of the majority 

of the canals and ditches when they are dry and not in use, Pacific Connector is proposing to 

install its pipeline through the Klamath Basin, between about MPs 188 and 230, during the 

winter. This would correspond with the ODFW recommended crossing window for the Lost 

River. The winter construction schedule would also minimize the crossing of high groundwater 

areas in the Klamath Basin, which are caused from irrigation and canal leakage or drainage. The 

BOR would require that irrigation canals and ditches under its jurisdiction be crossed between 

October 15 and March 15, outside of the irrigation season. Pacific Connector would work with 

the BOR, the appropriate irrigation districts, and individual landowners to develop site-specific 

procedures to minimize disruption of irrigation canals and ditches during construction. 

Road, Railroad, and Utility Crossings 

The proposed route of the Pacific Connector pipeline would cross about 520 roads, and 7 

railroads. Pacific Connector would use an open cut to cross the vast majority of these roads, 

most of which are dirt or graveled. There would be about 50 paved asphalt roads that would be 

open cut. Six paved asphalt roads and five of the railroads would be crossed using a bore. Six 

roads and one railroad would be crossed using an HDD associated with a waterbody crossing. A 
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least 5 feet of cover would be maintained over pipeline crossings of paved county, city, and state 

roads. 

Pacific Connector would obtain all necessary permits from applicable county, state, or federal 

land-managing agencies for public roads to be crossed, and permission to cross private roads 

from the landowners. Pacific Connector produced draft transportation management plans for 

roads on federal and non-federal lands. The draft plan for federal lands would be revised to 

address comments from the BLM, BOR, and USFS, and included as part of Pacific Connector’s 

POD. These plans are discussed in more detail in section 4.9 of this EIS. 

Pacific Connector would endeavor to notify agencies and private landowners at least seven days 

in advance of any road work or closures caused by pipeline construction activities. In some 

situations, caused by unforeseen construction schedule changes, a minimum of 48-hours notice 

would be provided. The construction contractor would be responsible for notifying county 

highway departments, as needed. During an open cut crossing, Pacific Connector would try to 

keep one lane of the road open for traffic, with detours around construction, plating over the 

open trench, or other methods. However, in some situations the road may have to be closed for a 

day when the pipeline would be installed across it. Where road closures occur, Pacific 

Connector would provide access around the construction site for local residents and emergency 

vehicles. Advanced signage would be used to provide notice of construction activities. In 

addition, Pacific Connector would utilize traffic control measures, such as signs, lights, barriers, 

and flaggers to ensure public safety and provide for efficient movement of traffic through or 

around the construction area, and to protect workers. 

Existing powerlines, pipelines, and other underground utilities would be crossed by conventional 

construction techniques that would be acceptable to the facility owner or operator. In most 

instances, the new pipeline would have to be installed beneath the existing buried utility to 

maintain the necessary depth of cover. Pacific Connector would coordinate with each utility 

owner/operator to design crossings. Prior to construction, Pacific Connector would contact the 

local “One Call” or “Call Before You Dig” system to determine the location of utilities to be 

crossed. These utility crossings would then be marked in the field during pre-construction 

surveys. 

2.4.2.3 Aboveground Facility Construction 

Construction activities and storage of construction materials and equipment would be confined to 

areas within the meter station and compressor station sites. Excavation would be performed as 

necessary to accommodate the new reinforced concrete foundation for meter and compressor 

station equipment. Forms would be set, rebar installed, and the concrete poured and cured in 

accordance with applicable standards. Backfill would be compacted in place, and excess soil 

would be used elsewhere or distributed around the site. 

The meter and compressor station equipment would be shipped to the sites by truck, and offloaded using cranes. The equipment would then be positioned on the foundation, leveled, 

grouted (if necessary), and secured with anchor bolts. Piping would be welded or connected 

with flanges. All welders and welding procedures would be qualified in accordance with API 

standards. All welds in gas piping systems would be x-rayed (or tested with other nondestructive testing method) to ensure compliance with code requirements. All components in 

high-pressure natural gas service would be hydrostatically tested prior to placing in service. 
2-102 2.0 – Description of the Proposed Action 

All mainline block valves would be installed within Pacific Connector’s permanent pipeline 

easement. Construction of the mainline block valves would be the same as those described for 

the pipeline facilities, except that during restoration of the pipeline right-of-way, an area of about 

50 x 50 feet surrounding the valve sites would be graveled and fenced 

2.5 POST-AUTHORIZATION ACTIONS, CONSTRUCTION, AND MITIGATION 

REVIEW 

The FERC has a three phase project review process. The first phase is the Pre-filing 

environmental review process. The second phase is the review of the application. The last phase 

is post-authorization review. Each stage of the review process requires the submission of 

progressively more detailed information and involves an exhaustive review and consultation with 

key stakeholders. The Project Order, issued by the Commission, is the culmination of the second 

phase. However, the Commission Order is typically conditional. The issuance of an Order does 

not necessarily mean that construction of the project can begin. During the third phase, there are 

usually two additional sets of authorizations necessary: one set prior to any project construction, 

and the second prior to operation of facilities. 

The final EIS contains the FERC staff’s recommendations regarding the feasibility, safety, and 

environmental impacts associated with the proposed Project and recommended measures for 

ensuring safety and mitigating any environmental impacts identified through analysis of the 

proposal and consideration of concerns raised during the Pre-filing and application review. After 

issuance of the final EIS, the Commission considers the entire record of the proceeding. If the 

Commission ultimately finds that the Project is in the public interest and authorizes the proposal, 

the project-specific mitigation measures recommended in the final EIS, and any others identified 

by the Commission as necessary, may be included as conditions to the Order. Development of 

the information and the consultations required by these mitigative measures are the subject of the 

third, post-authorization, phase of the Commission’s review process. 

It is during the post-authorization review phase that detailed plans for the Commission-required 

mitigation measures are developed. As an example, pursuant to Section 3 A(e) of the NGA, the 

ERP must include a cost-sharing plan for safety measures. Details of the ERP, including details 

of the cost-sharing plan, are developed and submitted to the Commission for review and 

approval during the post-authorization review phase. Approval of this plan, and a number of 

others specified as conditions of an Order, must be received before the Commission’s second 

authorization, the authorization to commence construction, would be issued. 

In many instances it is impossible to develop detailed plans related to certain aspects of a project 

before the details of the Commission’s underlying authorization are known. Hence, it is more 

effective and efficient for all involved to delay the development of such plans until after the 

Commission has specified a project as being consistent with the public interest. In some cases, 

environmental surveys cannot be completed until after the Commission has issued a Certificate, 

and the pipeline company can use the power of eminent domain under section 7h of the NGA to 

access parcels where permission was previously denied. Authorization to commence 

construction will not be issued until the conditions requiring pre-construction approval have been 

satisfied, with input as appropriate from all named agencies and others. 

If the FERC issues an Order authorizing the facilities, the Coast Guard issues a LOR indicating 

that the waterway is suitable for LNG carrier traffic to the proposed LNG import terminal, and 
2-103 2.0 – Description of the Proposed Action 

the federal land-managing agencies issue a Right-of-Way Grant for the pipeline, both Jordan 

Cove and Pacific Connector would be responsible for documenting compliance with a number of 

pre-construction conditions prior to being allowed to begin any construction activities. Also, 

before construction could begin, Jordan Cove and Pacific Connector must receive other 

necessary permits, including those issued by the COE, ODSL, ODEQ, and ODLCD under the 

RHA, CWA, CAA, and CMZA. In addition, Jordan Cove and Pacific Connector would have to 

document that all required cultural resources survey and evaluation reports and necessary 

treatment plans have been submitted and approved by the SHPO, appropriate federal landmanaging agencies, and the FERC staff, and the FERC would have to consult with the ACHP if 

any historic properties would be adversely affected in order to comply with the NHPA. To 

comply with the ESA and the MSA, the FERC would need to produce a BA and EFH 

Assessment and complete formal consultations with the FWS and NMFS before construction 

could begin. 

Jordan Cove and Pacific Connector would request a notice to proceed with construction through 

the filing with the FERC of an Implementation Plan (IP), which should demonstrate that all preconstruction conditions of the Commission’s Order have been met. An IP would have to be filed 

at least 60 days prior to construction being allowed to begin. 

Jordan Cove estimates that it would take approximately 36 months to construct its proposed 

LNG import terminal, including the access channel and slip. Site preparation would be done 

over a 4-month period. Final engineering design for various terminal facilities would need to be 

developed during this period. The LNG storage tanks would have the longest lead time, with 

about 26 months between when foundations are first laid and finishing construction of the tanks. 

Concurrently, work would be done on all processing equipment and terminal buildings. 

Excavation of the slip would begin after the tank foundations are set, and about 9 months would 

be needed to complete the Port’s proposed facilities, including the access channel. The in-water 

work, including removal of the berm and dredging of the access channel, would need to be done 

during the ODFW recommended window between October and February. 

After it receives a Certificate from the FERC, Pacific Connector would need to finalize right-ofway agreements with landowners, and complete civil and environmental surveys of the entire 

pipeline route. Actual construction activities for the pipeline would be initiated by Pacific 

Connector about one year after work starts on the LNG terminal. The first task would be the 

clearing of forested portions of the right-of-way and TEWAs, which would begin in the spring 

and continue through the fall of the first pipeline construction period. Also during that first 

construction season, Pacific Connector proposes to install its HDD crossing of three major rivers 

(Coos River, Rogue River, and Klamath River). During the first fall after pipeline construction 

is initiated, Pacific Connector would install its pipeline in the Coos Bay estuary, during the 

appropriate ODFW in-water work window. The following winter, the pipeline would be 

installed in portions of the Klamath Basin, when many of the irrigation ditches in the area would 

be low or dry, and when the ODFW recommended crossing of the Lost River. Starting in the 

next spring, during the second pipeline construction year, the pipeline would be installed along 

the rest of the route. Restoration and revegetation activities would begin during the following 

fall season. 

During what is typically a 3-year construction period for an LNG terminal, mitigation measures 

are implemented and monitored as appropriate. Sometimes during construction, on-the-ground 

conditions are identified that require modifications of the mitigation plans that were developed 
2-104 2.0 – Description of the Proposed Action 

prior to the start of construction. As part of its ongoing, detailed post-authorization project 

review, the FERC staff would inspect the construction in progress, as would third-party 

inspectors, ensuring that all required measures are implemented. Finally, at the end of 

construction, the project sponsor would file a request for authorization to commence operation of 

the facility. The information contained in this request should demonstrate how the project 

sponsor has complied with all of the Commission requirements and be consistent with the results 

of the Commission’s inspections. This final authorization from the Commission would not be 

granted unless all measures to ensure safe and secure operations and the necessary environmental 

protections are in place and serving their intended purpose. 

2.6 ENVIRONMENTAL COMPLIANCE AND MONITORING 

In preparing construction drawings and specifications for the Project, Jordan Cove and Pacific 

Connector would incorporate proposed mitigation measures identified in their applications, as 

specified in the Commission Order, and requirements of other federal, state, and local agencies. 

Jordan Cove’s and Pacific Connector’s construction contractors would also be provided copies of 

applicable environmental permits. Jordan Cove and Pacific Connector would conduct training 

for construction personnel regarding implementation of environmental permit requirements, and 

measures of specific mitigation plans. Environmental training would be conducted before and 

during construction. 

During pipeline construction, Pacific Connector would be represented on each pipeline spread by 

a Chief Inspector, who would be responsible for quality assurance and compliance with 

mitigation measures, other applicable regulatory requirements, and company specifications. In 

accordance with the FERC staff’s Plan, the Chief Inspector would be assisted by at least one fulltime EI per construction spread. The EI would report directly to the Chief Inspector and would 

have stop-work authority. The EI’s responsibilities would include: 

• ensuring compliance with the requirements of the FERC Staff’s Plan and Procedures, the 

environmental conditions of the section 3 and Certificate authorization, the mitigation 

measures proposed by the applicant (as approved and/or modified by FERC’s 

authorization), other environmental permits and approvals, and environmental 

requirements in landowner easement agreements; 

• identifying, documenting, and overseeing corrective actions, as necessary to bring an 

activity back into compliance; 

• verifying that the limits of authorized construction work areas and locations of access 

roads are properly marked before clearing; 

• verifying the location of signs and highly visible flagging marking the boundaries of 

sensitive resource areas, waterbodies, wetlands, or areas with special requirements along 

the construction work area; 

• identifying erosion/sediment control and soil stabilization needs in all areas; 

• ensuring that the location of dewatering structures and slope breakers would not direct 

water into known cultural resources sites or locations of sensitive species; 

• verifying that trench dewatering activities do not result in the deposition of sand, silt, 

and/or sediment near the point of discharge into a wetland or waterbody. If such 

deposition is occurring, the dewatering activity would be stopped and the design of the 

discharge would be changed to prevent reoccurrence; 
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• ensuring that subsoil and topsoil are tested in agricultural and residential areas to measure 

compaction and determine the need for corrective action; 

• advising the Chief Inspector when conditions (such as wet weather) make it advisable to 

restrict construction activities to avoid excessive rutting; 

• ensuring restoration of contours and topsoil; 

• verifying that the soils imported for agricultural or residential use have been certified as 

free of noxious weeds and soil pests, unless otherwise approved by the landowner; 

• approving straw bales for use in dewatering structures, mulch, and/or erosion control and 

verifying that the straw is certified free of noxious weeds and soil pests; 

• determining the need for and ensuring that erosion controls are properly installed, as 

necessary, to prevent sediment flow into wetlands, waterbodies, sensitive areas, and onto 

roads; 

• inspecting and ensuring the maintenance of temporary erosion control measures at least: 

− on a daily basis in areas of active construction or equipment operation; 

− on a weekly basis in areas with no construction or equipment operation; and 

− within 24 hours of each 0.5 inch of rainfall; 

• ensuring the repair of all ineffective temporary erosion control measures within 24 hours 

of identification; 

• keeping records of compliance with the environmental conditions of the FERC 

Certificate, and the mitigation measures proposed by the Project sponsor in the 

application submitted to the FERC, and other federal or state environmental permits 

during active construction and restoration; 

• identifying areas that should be given special attention to ensure stabilization; and 

• completing restoration after the construction phase. 

In addition, the FERC staff would conduct inspections to monitor the Project for compliance 

with the Commission's environmental conditions and Project mitigation measures proposed by 

Jordan Cove and Pacific Connector, or required by regulatory and land management agencies. 

Pacific Connector has agreed to fund third-party environmental monitors to the extent necessary 

up to the involvement of the FERC staff and federal land-managing agency inspections during 

Project construction. The third-party environmental monitors would report directly to the FERC 

staff, and would be available on site during all phases of construction. The details of the scopeof-work and selection of the third-party contractor would be finalized prior to the start of 

construction. 

Finally, other federal, state, and local agencies with jurisdiction or permitting authorities would 

conduct oversight inspections and monitoring to the extent deemed necessary by those agencies 

in order to meet their regulatory responsibilities. The USFS has requested that Pacific Connector 

use a cost recovery agreement to fund agency monitoring of construction and operational 

activities on NFS lands. The details of such a cost recovery agreement would be determined 

through ongoing consultations between the USFS and Pacific Connector, and the details would 

be specific in the Right-of-Way Grant. 
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2.7 OPERATION AND MAINTENANCE PROCEDURES 

2.7.1 Waterway for LNG Marine Traffic 

The operation of LNG carriers arriving at the Jordan Cove import terminal would not be subject 

to regulation by the FERC under section 3 of the NGA. The LNG carriers must comply with all 

federal and international standards regarding LNG shipping. A detailed discussion of design and 

safety features of LNG carriers is presented in sections 2.1.3 and 4.12.5 of this EIS. 

LNG carriers would enter Coos Bay under the navigational control of a Coos Bay pilot who 

would take control of the ships about 5 miles from the Coos Bay entrance. The pilots would 

decide whether the tide, current, and wind conditions allow safe entry into the Coos Bay 

navigation channel and onward to the LNG terminal. The LNG carrier would transit the 

waterway with a tug escort, with two tugs used for transit and three tugs used for mooring. The 

pilot would provide advice and guidance to the Master of the vessel during transit and mooring. 

The Coast Guard’s WSR’s outlines certain conditions that must be met in order for the waterway 

to be found suitable for LNG marine traffic , including additional resources or assets that would 

be required prior to allowing LNG carriers to transit the Coos Bay navigation channel to the 

Jordan Cove import terminal. The Coast Guard’s final decision about the suitability of the 

waterway for LNG marine traffic would be found in its LOR. Safety and security measures 

relating to LNG marine traffic in the waterway are described in more detail in section 4.12.5 of 

this EIS. 

The COE would be responsible for maintenance dredging of the Coos Bay navigation channel, 

and the Port would be responsible for maintenance dredging of the access channel and slip at the 

LNG terminal. The Port estimates that up to 0.35 mcy of material would be removed from the 

access channel and slip every 2 to 4 years in order to maintain the necessary operating depth. 

The Port has proposed to dispose of material from maintenance dredging within an unconfined 

open water disposal area (Coos Bay Site F) approximately 1.75 miles north-northwest of the 

north jetty (see section 2.1.4). The Port’s maintenance dredging plan, including disposal, would 

need to be approved by the COE. 

2.7.2 LNG Terminal Facilities 

Jordan Cove would operate and maintain its facilities in compliance with 49 CFR 193.2503 and 

193.2605 and sections 11.3.1 and 11.5.2 of NFPA 59A, 33 CFR 127, and other applicable federal 

and state regulations. Before commencing operation of the LNG terminal, Jordan Cove would 

prepare and submit for approval operation and maintenance manuals that address specific 

procedures for the safe operation and maintenance of the LNG storage and processing facilities. 

Jordan Cove would also prepare an operations manual that addresses specific procedures for the 

safe operation of the ship unloading facilities in accordance with 33 CFR 127.305. Operating 

procedures would address normal operations as well as safe startup, shutdown, and emergency 

conditions. 

All operations and maintenance personnel at the terminal would be trained to properly and safely 

perform their jobs. The terminal operators would be trained in the potential hazards associated 

with LNG, cryogenic operations, and the proper operations of all the equipment. The operators 

would meet all the training requirements of the Coast Guard, DOT, Coos Bay, Coos County Fire 

Department, and other regulatory entities. 
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The terminal full-time maintenance staff would conduct routine maintenance and minor 

overhauls. Major overhauls and other major maintenance would be handled by bringing in 

maintenance personnel specifically trained to perform the maintenance. All scheduled and 

unscheduled maintenance would be entered into a computerized maintenance management 

system (CMMS). 

2.7.3 Pipeline and Associated Aboveground Facilities 

The Pacific Connector pipeline and associated aboveground facilities would be operated and 

maintained in accordance with 49 CFR 192, Transportation of Natural and Other Gas by 

Pipeline: Minimum Federal Safety Standards, as required by the DOT. Section 4.12.10 of this 

EIS presents a discussion of the DOT’s safety regulations and requirements for natural gas 

pipelines and describes how these requirements would be met by the pipeline operator. 

The pipeline would be inspected regularly for the life of the pipeline by aerial patrols or on-theground personnel to observe general right-of-way conditions and to identify any indications of 

soil erosion that may expose the pipe, stressed vegetation that may indicate a leak in the line, 

damage to erosion-control structures, unauthorized encroachment onto the right-of-way, and 

other conditions that could present a safety hazard or require preventive maintenance or repairs. 

All inspections would be in accordance with DOT standards. Generally, repair of erosion control 

structures, drain tiles, and the need for additional fill may be required in the first year or two 

following construction in areas where the trench may have settled. Areas susceptible to damage 

from large storm events would be inspected and repaired as appropriate depending on the nature 

of damage. Waterbody crossings would be inspected periodically for the life of the pipeline. 

Any areas of concern regarding the stability or integrity of the waterbody crossings that are 

brought to the attention of the pipeline operator would be assessed and repaired as necessary. A 

supply of replacement pipe, leak clamps, sleeves, and related materials would be stored at local 

district offices for use during repair activities. 

Vegetation along the permanent pipeline right-of-way would be periodically maintained by 

mowing or cutting. Vegetation maintenance would be a required periodic use of the federal or 

private lands crossed by the pipeline, and would be covered in lease agreements for each 

individual affected property. Generally, herbicides would not be used except for select treatment 

of nuisance vegetation or select use within aboveground facilities. No herbicides would be used 

for vegetation control without the consent of the landowner or land-managing agency. 

Vegetation maintenance would be conducted every 3 to 5 years, depending on vegetation growth 

rates. However, to facilitate periodic corrosion and leak surveys, a corridor not exceeding 10 

feet in width centered on the pipeline may be maintained in a herbaceous state by annual 

maintenance if required. 

In upland areas, trees and shrubs within 15 feet of the centerline (30 feet maintained corridor) 

would be trimmed to heights no greater than 6 feet tall, with the remains left on the right-of-way 

to discourage OHV traffic, benefit wildlife habitat, and to decompose naturally. This slash, and 

chipping where appropriate, should not exceed the fuel loading specifications of the regulatory 

agencies. The permanent pipeline easement outside of the 30-foot-wide maintained corridor 

would not be maintained, allowing trees and shrubs to revegetate naturally. A schematic cross 

section of the resulting vegetation across the permanent operational right-of-way in forested 

areas is shown in figure 2.7-1. 
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Figure 2.7-1 Right-of-Way Vegetation Maintenance in Forested Areas 
2-109 2.0 – Description of the Proposed Action 

In forested and shrub wetland areas, vegetation maintenance would be as described above except 

trees and shrubs would be selectively removed as necessary to minimize equipment operating 

within the wetland. Where the pipeline crosses a waterbody, vegetation maintenance would be 

limited to allow a riparian strip at least 25 feet wide, measured from the waterbody’s OHWM, to 

permanently revegetate with native species, with the exception of maintenance required to 

maintain vegetation no greater than 6 feet tall within 15 feet of the centerline of the pipe. A 

typical plan view of resulting vegetation within the pipeline right-of-way at waterbody crossings 

is shown in figure 2.7-2. 

Figure 2.7-2 Right-of-Way Vegetation Maintenance in Riparian Areas 
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On federal lands where Riparian Reserves are affected, a 100-foot riparian strip (or less if the 

pre-construction riparian vegetation did not extend to 100 feet) would be planted perpendicular 

to the waterbody on both sides of the waterbody. However, to facilitate periodic pipeline 

corrosion/leak surveys, a corridor centered on the pipeline and up to 10 feet wide would be 

maintained in an herbaceous state in this riparian strip with no vegetation greater than 6 feet in 

height. Herbicides would not be used in or within 100 feet of a waterbody’s mean high water 

mark. Herbicides would only be used on NFS lands if needed to control invasive species, in 

accordance with each National Forest’s management plans. 

In addition to DOT-required surveys, Pacific Connector would monitor the pipeline system using 

a supervisory control and data acquisition (SCADA) system. SCADA systems are used to 

monitor and control facilities or equipment in industries such as telecommunications, water and 

waste control, energy, oil and gas refining, and transportation. A SCADA system gathers 

information; transfers the information back to a control center; carries out necessary analysis and 

control; and displays the information in a logical and organized fashion 24 hours a day, 7 days 

per week. The control center for the Pacific Connector pipeline would be provided by Williams 

Pacific Operator and would be located in Salt Lake City, Utah. 

The aboveground facilities would be inspected for the life of the pipeline at intervals that meet 

DOT requirements. Pipeline personnel would perform routine checks of the facilities, including 

calibration of equipment and instrumentation, inspection of critical components, and scheduled 

and routine maintenance of equipment. Safety equipment, such as pressure-relief devices, fire 

detection and suppression systems, and gas detection systems, would be tested for proper 

operation. Corrective actions would be taken for any identified problem. Vegetation at 

aboveground facilities would be periodically maintained using mowing, cutting, trimming and 

the selective use of herbicides. 

2.8 SAFETY CONTROLS 

2.8.1 LNG Terminal Facilities 

The LNG terminal facilities would be designed, constructed, operated, and maintained in 

accordance with DOT Federal Safety Standards for Liquefied Natural Gas Facilities, 49 CFR 

193. The facilities would also meet the NFPA 59A, 2001 Edition, LNG Standards. The marine 

cargo transfer system and any appurtenances found between the LNG carriers and the last valve 

immediately before the LNG storage tanks would comply with the Coast Guard regulations for 

Liquefied Natural Gas Waterfront Facilities, 33 CFR 127 and Executive Order 10159. The 

major federal siting and design requirements for LNG facilities are summarized in table 2.8.1-1. 

TABLE 2.8.1-1 

Federal Siting and Design Requirements for LNG Facilities

Requirement Description 

Thermal Radiation Protection (49 CFR 193.2057 and 

section 2.2.3.2 of NFPA 59A) 

This requirement is designed to ensure that certain public land uses 

and structures outside the LNG facility boundaries are protected in 

the event of an LNG fire. 

Flammable Vapor-Gas Dispersion Protection (49 CFR 

193.2059 and sections 2.2.3.3 and 2.2.3.4 of NFPA 59A) 

This requirement is designed to prevent a flammable vapor cloud 

associated with an LNG spill from reaching a property line that can be 

built upon. 
2-111 2.0 – Description of the Proposed Action 

TABLE 2.8.1-1 

Federal Siting and Design Requirements for LNG Facilities

Requirement Description 

Seismic Design (49 CFR 193.2101, and NFPA 59A) This requirement outlines the necessary site specific seismic hazard 

study and specifies that critical safety-related components of the 

facility must be designed to survive earthquake ground motions 

estimated to have a 1 to 2 percent probability of occurring within a 50-

year period. 

Wind Forces (49 CFR 193.2067) This requirement specifies that all facilities be designed to withstand 

wind forces of not less than 150 mph without the loss of structural 

integrity. 

Impounded Liquid (section 2.2.3.8 of NFPA 59A) This requirement specifies that liquids in spill impoundment basins 

cannot be closer than 50 feet from a property line that can be built 

upon or a navigable waterway. 

Container Spacing (section 2.2.4.1 of NFPA 59A) This requirement specifies that LNG containers with capacities 

greater than 70,000 gallons must be located a minimum distance of 

0.7 times the container diameter from the property line or buildings. 

Vaporizer Spacing (section 2.2.5.2 of NFPA 59A) This requirement specifies that integral heated vaporizers must be 

located at least 100 feet from a property line that can be built upon 

and at least 50 feet from other select structures and equipment. 

Process Equipment Spacing (section 2.2.6.1 of NFPA 

59A) 

This requirement specifies that process equipment containing LNG or 

flammable gases must be located at least 50 feet from sources of 

ignition, a property line that can be built upon, control rooms, offices, 

shops, and other occupied structures. 

Marine Transfer Spacing (33 CFR 127.105) This requirement specifies that each LNG unloading flange must be 

located at least 985 feet from any bridge crossing a navigable 

waterway. 

2.8.1.1 Spill Containment 

The LNG spill containment systems for the new facility would be designed and constructed to 

comply with DOT regulations 49 CFR 193 Sections 193.2155 through 193.2185. These 

regulations require that each LNG container and each LNG transfer system be provided with a 

means of secondary containment, which has been sized to hold the quantity of LNG that could be 

released as a result of the design spill, which is appropriate for the area and LNG equipment. 

The design spills are defined in NFPA 59A. 

The LNG storage tank concrete outer container would be designed to contain 110 percent of the 

contents of the nine percent nickel steel inner container. The storm surge barrier dike would be 

designed to hold the contents of one 160,000 m3

 LNG storage tank. 

The transfer piping spill containment system would be sized to contain the volume of LNG that 

could be released in ten minutes from a single pipe rupture that would produce the highest 

release rate. The LNG spill containment system consists of spill collecting troughs that drain to 

one of two LNG spill containment sumps. The unloading and LNG tank sumps are sized to 

contain a ten minute spill from a line at the design rate. Each spill containment sump would be 

65 feet long by 65 feet wide by 25 feet deep with a usable depth of 20 feet. The usable volume 

of the sump would provide for containment of a 10-minute spill from a single pipe rupture that 

would produce the highest release rate in accordance with NFPA requirements. Stormwater that 

collects within the LNG spill containment sumps would be passed through oil water separators, 

then pumped to the firewater pond and released into the ocean through the Port’s industrial 

wastewater pipeline. 
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2.8.1.2 Thermal Exclusion and Vapor Dispersion Zones 

Thermal exclusion zones were calculated using the LNG Fire III computer model as required by 

49 CFR 193.2057(a). In these calculations the weather conditions from the area that produced 

the furthest exclusion distance were utilized as required in 49 CFR 193.2057(b). The analysis 

shows that the thermal radiation requirements for siting the facility would be in compliance with 

49 CFR 193.2057. 

Vapor dispersion exclusion zones were calculated using the dense gas dispersion model 

(DEGADIS) as outlined in 49 CFR 193.2059(a). These calculations for weather conditions 

followed the requirements in 49 CFR 193.2059(b)(2a). The analysis shows that the vapor 

dispersion requirements for siting the facility would be in compliance with 49 CFR 193.2059. 

2.8.1.3 Hazard Detection Systems 

Hazard detectors would be installed throughout the facilities to give operations personnel a 

means for early detection and location of released flammable gases and fires. The hazard 

detection system would consist of separate detection units for combustible gas, fire, smoke, high 

and low temperature and would be hard wired to the main control system for alarm. Smart area 

gas detectors would be provided to monitor flammable gases within the LNG terminal. 

Low temperature sensors would be located in the spill impoundment basin to shut down and/or 

prevent the storm water pumps from starting in the event of an LNG spill. Smart 

ultraviolet/infrared (UV/IR) fire and flame detectors would also be located throughout the LNG 

terminal and high temperature detectors would be located to detect a fire on the vent pipes of the 

LNG storage tank relief valves. 

2.8.1.4 Hazard Control Systems 

Several different types of fire suppression agents would be available for fighting fires within the 

LNG terminal. The type of agent that would be used in a specific situation would depend on the 

characteristics of a particular event and on the relative effectiveness of the various agents on that 

particular type of fire. A high expansion foam system would be provided for the LNG spill 

containment sumps and at the dock. High expansion foam concentrate is metered or 

proportioned into the firewater system by means of a typical balanced pressure foam 

proportioning system. The resulting foam solution is delivered via underground piping to the 

high expansion foam generators. The high expansion foam generator, ANGUS or equivalent, 

would be water motor powered, thus no electrical power would be required. The foam generator 

produces nominal 500:1 high expansion foam, that is, 500 parts air for every part foam solution. 

This foam is applied to LNG spills, whether ignited or unignited. Applied to ignited spills, the 

foam controls the fire, greatly reducing the level of radiant heat to the surroundings. If the spill 

remains unignited, the foam serves to reduce the downwind distance to lower flammable limit 

(LFL) by warming the LNG vapors. High expansion foam systems would be in accordance with 

NFPA 11A. 

Dry chemical fire suppression systems would be provided for the LNG storage tank relief valves 

and would be automatically activated to extinguish any potential fires at the valves. Manually 

operated dry chemical units would be strategically located throughout the facilities. 
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2.8.1.5 Firewater Systems 

The LNG terminal would have firewater supply and distribution systems for extinguishing fires, 

cooling structures and equipment exposed to thermal radiation, and dispersing flammable vapors. 

Hydrants, manual monitors, automatic sweep monitors, and hose reels would be located 

throughout the LNG terminal. Internal building water sprinkler systems would be located at the 

main control room, warehouse, and office. 

The main components of the firewater distribution system would include: 

• Freshwater storage pond with a storage capacity of approximately 10 million gallons; 

• One electric motor-driven firewater "jockey" pump, having a rated capacity of 215 gpm 

at 150 psig discharge pressure; 

• Five diesel engine-driven and one electric motor-driven firewater pumps, each with a 

rated capacity of 2,500 gpm at 150 psig discharge pressure. Freshwater firewater pumps 

would be designed and installed in accordance with NFPA 20. Per NFPA 20, diesel 

engine-driven firewater pumps would have individual fuel tanks that would allow for up 

to eight hours of continuous pump operation; 

• Fifty firewater monitors and two elevated firewater monitors would be provided. The 

elevated monitors located on the marine unloading berth would be remotely operated 

from a safe distance with a view of the unloading berth. Firewater monitor nozzles 

would be adjustable from straight stream to full fog. In locating firewater monitors, an 

effective coverage range of 200 feet diameter is assumed; 

• Hydrants are integrated with most monitors and offer the opportunity for direct action by 

means of 2.5-inch hose lines, as well as the capability to deliver pressurized firewater to 

automotive fire apparatus equipped with a fire pump; 

• Hose reels, each including 100 feet of hard rubber non-collapsible 1.5-inch fire hose and 

adjustable fog nozzle for a rapid first response with firewater; 

• An automatic sprinkler system in accordance with NFPA 13 would be installed in the 

administration and warehouse/workshop buildings. In addition, hose reels would be 

mounted on building vertical steel members; and 

• An underground firewater piping distribution system, with strategically-located post 

indicating isolation valves, located in order to minimize system impairment due to 

maintenance or repair. The firewater piping material would be high-density polyethylene 

(HDPE) for all underground piping and carbon steel for all aboveground piping. The 

system is designed and installed in accordance with NFPA 24. 

2.8.1.6 Fail Safe Shutdown System 

The LNG terminal would have an ESD with shutdown and control devices designed to leave the 

facility in a safe state. The ESD system would be used for major incidents and would result in 

either total plant shutdown, shutdown of ship unloading, and/or individual pieces of equipment, 

depending on the type of incident. Three levels of shutdown would be configured for the Jordan 

Cove as follows: 

• Level 1 shutdowns are to be used for a major incident and would carry out a total Jordan 

Cove shutdown. 
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• Level 2 shutdowns would only shutdown the appropriate jetty unloading area and can be 

initiated manually, automatically by local instrumentation, by a Level 1 shutdown, or by 

ship-to-shore operation. 

• Level 3 shutdowns for shutting down individual pieces of equipment would be initiated 

automatically by trip input signals to the safety instrumented system (SIS). 

2.8.1.7 Warning Systems 

The LNG terminal would include sirens that would be audible in all locations within the LNG 

terminal property. The sirens would have a distinctive tone for easy recognition between alarms 

and emergency events. 

2.8.1.8 Security Systems 

Jordan Cove would prepare a security procedures manual and plan in close coordination with the 

FERC, Coast Guard and DOT. The manual/plan would establish a written program for physical 

security for all facilities at the LNG terminal. The plan, which would comply with all applicable 

regulations, provides for risk-based levels of security carried out by trained personnel during all 

operation shifts and, if necessary, by governmental law enforcement offices to respond to serious 

threats. These procedures and plans would be formulated in the following sequence: 

• Conduct Facility Assessment; 

• Prepare Draft Plan Outline; 

• Conduct Stakeholder Meeting; 

• Prepare Draft Plan; 

• Conduct Plan Review Meeting; 

• Submit Plan to Agencies; 

• Coast Guard Review; 

• Plan Approved; 

• Begin Implementation of Plan; and 

• Terminal Operation. 

2.8.1.9 Emergency Response Plan 

Section 3A(e) of the NGA, as amended by section 311 of the EPAct of 2005, stipulated that in 

any Order authorizing an LNG terminal, the Commission shall require the LNG terminal 

operator to develop an ERP in consultation with the Coast Guard and state and local agencies. 

The FERC must review and approve the ERP prior to any final approval to begin construction. 

In section 4.12.6 of this EIS we have included a recommendation that Jordan Cove file the ERP 

for our review and approval prior to initial site preparation. Commission practice has been for 

applicants to document consultations with appropriate stakeholders during development of its 

ERP, including correspondence to and from the Coast Guard COTP, state and county local 

emergency planning commissions, state and local law enforcement agencies, and local fire 

departments. 

On several LNG import terminal proposals, 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 carriers while in transit 

and unloading at the facility. In addition, Section 3A(e) of the NGA (as amended by the EPAct) 

specifies that the ERP shall include a Cost-Sharing Plan that contains a description of any direct 
2-115 2.0 – Description of the Proposed Action 

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 carriers that 

serve the facility. In section 4.12.6 of this EIS we have included a recommendation that Jordan 

Cove develop and file with the FERC a Cost Sharing Plan prior to the start of initial site 

preparation. On February 27, 2009, Jordan Cove entered into a Memorandum of Understanding 

(MOU) with the State of Oregon, through the ODE, to cooperatively develop an emergency 

preparedness program for the proposed LNG terminal. Jordan Cove committed to providing the 

ODE and local emergency response organizations with adequate funding, personnel, equipment, 

and other resources as appropriate to implement the ERP. See section 4.12.6 for additional 

details of the ERP and Cost Sharing Plan. 

2.8.2 Pipeline and Associated Aboveground Facilities 

The Pacific Connector pipeline and associated aboveground facilities would be designed, 

constructed, operated, and maintained in accordance with the DOT’s Transportation of Natural 

and Other Gas By Pipeline: Minimum Federal Safety Standards in 49 CFR 192. These safety 

standards are discussed in section 4.12.10 of this EIS. 

Pacific Connector would develop an enhanced pipeline Integrity Management Program (IMP) to 

maintain and improve pipeline safety and reliability for the entire Pacific Connector system. The 

program would be implemented through: 

• integrity assessment of pipelines in High Consequence Areas (HCAs); 

• improving integrity management data systems; 

• increasing the integrity and reliability of the pipeline system; and 

• providing increased public assurance of pipeline safety. 

This program may be audited by the DOT. The IMP would be developed and implemented to 

comply with the prescriptive based requirements of Subpart O, 49 CFR 192, and Pacific 

Connector would monitor the program’s effectiveness and strive for continuous improvement. 

The IMP would be updated during operation of the pipeline. Pacific Connector would complete 

the HCA determination within 1 year of the in-service date of the JCE & PCGP Project. 

2.8.2.1 Corrosion Protection and Detection System 

The Pacific Connector pipeline would be protected from corrosion by a fusion-bonded epoxy 

coating. In addition, a low voltage cathodic protection system would be installed to assist in 

protecting the buried pipeline from corrosion. The cathodic protection system functions by using 

rectifiers and/or groundbeds to impress a DC current of approximately 1 volt on the pipeline. 

This current provides protection from corrosion by making the pipeline cathodic to the 

surrounding environment. 

Following the installation and balancing of the cathodic protection system, Pacific Connector 

personnel would routinely check the voltage and amperage of the rectifiers, as well as the pipeto-soil potentials. Continual adjustments would be made as conditions change. Annual close 

interval surveys would be completed to determine pipe to soil potentials in accordance with DOT 

requirements at least once per calendar year but with intervals not to exceed 15 months. 

Problems detected through the monitoring program would be corrected promptly and checked in 

a follow-up survey no later than 12 months after the initial discovery. The interior of the pipe 

would be periodically monitored for corrosion using internal in-line pigging technology. 
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2.8.2.2 Emergency Response Procedures 

Pipeline system emergencies can include gas leaks, fire or explosion, and/or damage to the 

pipeline and aboveground facilities. Pacific Connector would maintain 24-hour emergency 

response capabilities, including an emergency-only phone number, which accepts collect 

charges. The number would be included in informational mail-outs, posted on all pipeline 

markers, and provided to local emergency agencies in the vicinity of the pipeline and compressor 

station. 

In accordance with DOT regulations, Pacific Connector would also develop an ERP to address 

procedures to be followed in the event of an emergency along the pipeline. Operations personnel 

would attend training for emergency response procedures and plans prior to commencing 

pipeline operations. Pacific Connector would meet with local emergency responder groups (fire 

departments, police departments, land-managing agencies including the BLM, BOR, and USFS, 

and other public officials) to review plans and would work with these groups to communicate the 

specifics about the pipeline facilities in the area and the need for emergency response. Pacific 

Connector would also meet periodically with the groups to review the plans and revise them 

when necessary. If requested by local public emergency response personnel, Pacific Connector 

would participate in any operator-simulated emergency exercises and post-exercise critiques. 

Pacific Connector would use adequate local or contract resources to support the pipeline and 

facilities if an emergency occurs. 

All of the information that Pacific Connector gathers about its system would be used to tailor its 

safety and integrity management activities, so that parts of the system in the greatest need of 

attention receive greater scrutiny, such as residential areas or areas subject to growth and 

development. For example, Pacific Connector would decide where and when to internally 

inspect the pipeline based on this information. Risk assessment of the pipeline system 

determines what inspection criteria are required. This may include many different types of 

assessment tools that provide specific types of information about the condition of the pipeline. 

The Butte Falls Compressor Station would also be equipped with automatic emergency detection 

and shut down systems. For example, the station would have hazardous gas and fire detection 

systems, and an emergency shut down system. The emergency shut down system would be 

designed to shut down and isolate elements of the compressor station in the event of a fire, 

before the development of a flammable mixture of gas could occur. The system would include 

sensors for detecting natural gas concentrations as well as ultraviolet sensors for detecting 

flames. Additionally, the compressor station equipment would be designed to shut down 

automatically if a mechanical failure poses risk to the equipment or otherwise constitutes a 

hazard. The compressor station would be equipped with relief valves to protect the piping from 

over-pressurization. 

Personnel would be able to respond to a compressor station emergency in 60 minutes or less 

during non-scheduled work hours and within a few minutes if they are at the compressor station. 

Personnel would be on call at all times, 24 hours a day, 365 days a year to respond to 

emergencies. Emergencies while the compressor station is unattended would be monitored 

remotely via the Gas Control Facility in Salt Lake City, Utah. Personnel living within a 30-

minute travel time of the compressor station would be dispatched by Gas Control in the event of 

an emergency at the compressor station. 
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Personnel would be Operator Qualified per DOT PHMSA requirements for operational and 

emergency situations at the station. Fire protection, first aid, and safety equipment would be 

maintained at the compressor station and Pacific Connector personnel would be trained in first 

aid and proper equipment use. 

2.9 GAS QUALITY AND INTERCHANGEABILITY 

We received comments during scoping with regard to the quality and interchangeability of the 

LNG that would be imported and re-vaporized by the proposed Jordan Cove LNG terminal and 

transported pursuant to a FERC tariff by the Pacific Connector pipeline. We have received 

similar comments during our review of other proposed LNG projects and their downstream 

pipelines, and the Commission has been evaluating several aspects of this issue. On June 15, 

2006, the Commission, in Docket No. PL04-3-000, issued its Policy Statement on Provisions 

Governing Natural Gas Quality and Interchangeability in Interstate Natural Gas Pipeline 

Company Tariffs (GQI Policy Statement) where the Commission explained how it would 

evaluate issues related to gas quality and interchangeability. As a practical matter gas flowing 

from the Jordan Cove LNG terminal into the Pacific Connector pipeline would need to meet the 

gas quality and interchangeability provisions contained in the tariffs of the interconnecting 

pipelines. Otherwise the downstream entity could reject the gas. 

2.9.1 Interchangeability 

Imported LNG may have different physical characteristics from domestically produced gas. 

Interchangeability means the extent to which a substitute gas can safely and efficiently replace 

gas normally used by an end-user in a combustion application. Interchangeability is often 

measured by Wobbe Index of the gas, which is derivative of the higher heat content and specific 

gravity of the gas. The differing characteristics of imported LNG may present operational issues 

for transmission systems and end-use equipment, although the extent to which these cause any 

real problems is dependent upon the specific operational parameters of the pipeline system and 

the end use equipment. Interchangeability provisions are set forth in the pipeline’s FERC tariff. 

2.9.2 Gas Quality 

Gas quality is concerned with the impact of non-methane hydrocarbons on the safe and efficient 

operation of pipelines, distribution facilities, and end-used equipment. Natural gas is primarily 

methane, but in some regions where it is produced, it contains heavier liquid hydrocarbons 

(pentanes, hexanes, etc.). The temperature at which liquids suspended in the natural gas stream 

separate and drop out is called the hydrocarbon dew point. When hydrocarbon dropout occurs 

these liquids may create safety, reliability and integrity problems for pipelines and downstream 

customers. Hydrocarbon dropout is not an issue associated with LNG supplies as the heavier 

hydrocarbons which tend to drop out are removed during the liquefaction process. Gas quality 

provisions are also contained in pipeline tariffs. 

2.9.3 Other Gas Specifications 

In addition to gas quality and interchangeability provisions pipelines typically have provisions in 

their tariffs setting forth limits on non-hydrocarbon constituents. Some of the limitations are for 

carbon dioxide, oxygen, nitrogen, water vapor, hydrogen sulfides, sulfur, temperature, PCB, 

microbiological agents, and objectionable materials (odors, dust, impurities), among others. 
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2.9.4 Resolution of Gas Quality Issues 

Natural gas quality is a complex and highly technical issue. The Commission reviews the gas 

quality and interchangeability provisions of new pipeline companies in the context of the GQI

Policy Statement. The GQI Policy Statement states that: (1) only natural gas quality and 

interchangeability specifications contained in a Commission-approved gas tariff can be enforced; 

(2) pipeline tariff provisions on gas quality and interchangeability need to be flexible to allow 

pipelines to balance safety and reliability concerns with the importance of maximizing supply, as 

well as recognizing the evolving nature of the science of underlying gas quality and 

interchangeability specifications; (3) pipelines and their customers should develop gas quality 

and interchangeability specifications based on technical requirements; (4) in negotiating 

technically based solutions, pipelines and their customers are strongly encouraged to use the 

Natural Gas Council Plus interim guidelines filed with the Commission on February 28, 2005, as 

a common reference point for resolving gas quality and interchangeability issues; and (5) to the 

extent pipelines and their customers cannot resolve disputes over gas quality and 

interchangeability, those disputes can be brought before the Commission on a case-by-case basis 

to be resolved based on a record of fact and technical review. The Commission will review 

Pacific Connector Pipeline’s tariff provisions concerning gas quality and interchangeability in 

the context of the GQI Policy Statement. 

2.10 FUTURE PLANS AND ABANDONMENT

Jordan Cove has no current plans that would result in the future expansion of its proposed LNG 

import terminal. Jordan Cove also has not proposed to change its planned LNG import terminal 

into an export facility, as speculated by some commenters on the draft EIS. In order to either 

expand the LNG terminal or convert it into an export facility, Jordan Cove would have to file a 

different application with the FERC. Any other applications would be subject to a separate, 

independent environmental review by the FERC staff, and the proposal outlined in the 

application would be considered a new undertaking. 

Based on the operations of existing LNG import terminals long past their originally planned 

design life, Jordan Cove does not anticipate abandonment of the proposed LNG import terminal 

facility in the foreseeable future (more than 30 years). If at some point, Jordan Cove did propose 

to abandon the LNG terminal, it would seek authorization from the FERC to do so. This would 

involve a separate proceeding in which all interested parties would have an opportunity to 

participate, and the FERC would conduct a new environmental review, and would impose 

necessary and appropriate conditions in an Order authorizing the abandonment of the facility. 

Furthermore, in anticipation of any future abandonment, under the terms of its Option to 

Purchase and Lease with the Port, Jordan Cove has committed to the removal of all leasehold 

improvements and repair of any damage to the property in the event of lease termination. The 

terms outlined in the Option to Purchase and Lease between the Port and Jordan Cove require 

that Jordan Cove remove all improvements to the Jordan Cove site including both the upland 

facilities and the marine terminal improvements in the event of default or of termination of use of 

the site for the intended purpose (LNG storage and regasification). The Port would be given a 

first right of refusal to allow Jordan Cove to abandon the improvements in-place, in the event 

that the Port deems, in its sole discretion, that the terminal facilities would have value to the Port 

and reuse of the facilities are likely. In this event the Port has agreed to waive the obligation of 

Jordan Cove to remove the surface structures and return the site to a clear and level condition. 
2-119 2.0 – Description of the Proposed Action 

Jordan Cove is required to provide sufficient surety to cover the estimated cost of this 

termination provision. 

In its February 27, 2009 MOU with the State of Oregon, Jordan Cove committed to providing a 

retirement cost estimate and funding surety that is consistent with the EFSC Retirement and 

Financial Assurance Standard at OAR Chapter 345 Divisions 21 and 22. The MOU stipulates 

that Jordan Cove would do the following: 

• Before beginning construction of the LNG terminal, Jordan Cove would submit to the 

ODE a detailed engineering estimate of the cost to retire and restore the facility; 

• Before beginning construction, Jordan Cove would post with the ODE a bond or letter of 

credit to cover the amount in the estimate to retire the facility; 

• Two years prior to closure of the LNG terminal and the associated power plant, Jordan 

Cove would develop a final retirement plan, in consultation with Coos County, to be 

approved by the ODE; and 

• Jordan Cove would retire the facility in a non-hazardous condition, so that the land could 

be restored to future productive use. 

Pacific Connector has no plans for future expansion or abandonment of its proposed facilities. 

Pacific Connector stated that with its proposed use of current corrosion coating technologies, 

combined with proper routing, construction/installation, mature and robust integrity 

management programs, and operational maintenance techniques, its proposed pipeline could be 

kept in service over a long period of time. There are many exiting interstate natural gas pipelines 

operating in the United States that are more than 50 years old. 

If Pacific Connector decides to expand or abandon its proposed pipeline or aboveground facilities 

it would need to file a new, separate application with the FERC for that action. The FERC would 

consider that action a new undertaking, and conduct an independent environmental review of the 

proposal, including consultations with other appropriate regulatory agencies. Only after 

documenting that review in an environmental document that meets the requirements of the NEPA, 

and public review and comment on that environmental document, as appropriate, would the 

FERC make a decision about whether or not to authorize the proposed expansion or abandonment 

actions. 

The federal land-managing agencies would need to evaluate any proposed abandonment under the 

terms of the Right-of-Way Grant. The BLM must consider the final disposition of the pipeline 

facilities in accordance with 43 CFR 2886, and would require Pacific Connector to address 

termination and restoration issues in its final POD. 

Pacific Connector indicated that abandonment or deactivation of facilities would comply with 

Williams Gas Operator’s Operation and Maintenance Manual and DOT CFR 192.727, 

Abandonment or Deactivation of Facilities. The pipeline would be abandoned in place, where 

necessary, and would be disconnected from all sources and supplies of gas, purged of gas, and 

have the ends sealed. 
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For aboveground facilities, when service is permanently discontinued to a customer, Pacific 

Connector would complete one of the following activities: 

• fit the valve closest to the abandoned portion of the pipeline with a locking devise to 

prevent gas flow; 

• install a mechanical devise of fitting in the appropriate service line or meter assembly to 

prevent gas flow; or 

• physically disconnect the piping to the customer from the gas supply source and seal the 

pipe ends. 

Work necessary for abandonment or deactivation would be conducted within the permanent 

right-of-way, where possible. For example, excavations may have to be done to seal pipe ends, 

or remove block valves, that would typically require a 50-foot by 50-foot work space. Pacific 

Connector would apply for the necessary authorizations from appropriate federal, state, or local 

government agencies for any activities related to abandonment that may occur outside of its 

permanent right-of-way easement.