3-1 3.0 – Alternatives

3.0 ALTERNATIVES 

In considering Jordan Cove’s and Pacific Connector’s applications, the FERC will review both 

the environmental and non-environmental record in deciding whether it is in the public 

convenience and necessity to issue any authorization for the Project. To adhere to the CEQ 

regulations for complying with the NEPA (at 40 CFR Part 1502.14), the FERC and federal 

cooperating agencies must consider reasonable alternatives. This EIS compares the 

environmental impacts of the proposed action against a range of alternatives. This analysis 

should provide agency decision makers with a basis for understanding the staff’s recommended 

preferred alternative; which may include the proposed action as modified. 

Each of the cooperating agencies can use this alternatives analysis as part of their decision 

making process. Each agency has its own administrative procedures and actions to consider. 

The FERC, for example, will consider whether or not to approve the facilities proposed by 

Jordan Cove and Pacific Connector. The Coast Guard will issue a LOR as to the suitability of 

the waterway for LNG marine traffic, and provide recommendations regarding RMMs which 

should be implemented to ensure the security of the waterway and the port. The COE will 

review permit applications submitted by the applicants under section 10 of the RHA and section 

404 of the CWA. The BLM will decide whether or not to issue a Right-of-Way Grant for the 

Pacific Connector pipeline across BLM-administered lands, across BOR lands, and across NFS 

lands with agreement from the USFS and BOR. 

In accordance with the NEPA and Commission policy, we have evaluated a number of 

alternatives to the JCE & PCGP Project to determine if any are reasonable and environmentally 

preferable to Jordan Cove’s and Pacific Connector’s proposed action. Alternatives considered 

by the FERC, described in more detail below, include no action or postponed action, system 

alternatives, LNG terminal site alternatives, LNG terminal layout alternatives, dredging and 

dredge material disposal alternatives, and pipeline route alternatives. In the draft EIS we 

recommended a number of pipeline route variations as preferable to the proposed route, and we 

directed Pacific Connector to incorporate these route variations into its proposed route. On 

December 4, 2008 Pacific Connector filed these changes as its revised proposed route. These 

changes are reflected throughout this final EIS. 

Alternatives were evaluated against the objectives of the JCE & PCGP Project, as described in 

section 1.1 of this EIS. The primary objective of the Project is to provide a new access point for 

LNG imports and a new source of natural gas to Pacific Northwest, northern California, and 

northern Nevada markets to meet growing demands. To achieve this objective, Jordan Cove 

would construct and operate an LNG import terminal with docking/unloading facilities capable 

of berthing one LNG carrier, an LNG storage capacity of 320,000 m3, and vaporization facilities 

capable of sending out about 1.0 Bscfd of natural gas to the Pacific Connector pipeline. The 

234-mile long, 36-inch-diameter pipeline would serve the target markets by: 

• delivering natural gas to the existing interstate facilities of Williams Northwest Grants 

Pass lateral through an interconnect near Myrtle Creek, Oregon; 

• delivering natural gas to the LCD facilities of Avista through an interconnect near Shady 

Cove, Oregon; and 
3-2 3.0 – Alternatives 

• delivering natural gas to the existing facilities of GTN, Tuscarora, and PG&E through 

interconnects at the terminus of the pipeline at the Oregon/California border near Malin, 

Oregon. 

The FERC’s evaluation criteria for selecting potentially reasonable and environmentally 

preferable alternatives include whether they: 

• are technically and economically feasible, reasonable, and practical; 

• offer significant environmental advantage over the proposed Project; and 

• meet the objectives of the Project, as described above. 

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

are technically and economically feasible and practical. Some alternatives may be impracticable 

because they are unavailable and/or incapable of being implemented after taking into 

consideration costs, existing technologies, and logistics in light of the overall Project purpose. In 

conducting a reasonable analysis, it is also important to consider the environmental advantages 

and disadvantages of the proposed action and to focus the analysis on those alternatives that may 

reduce impacts and/or offer a significant environmental advantage. 

The Commission has three possible courses of action in processing the applicant’s proposals. 

The Commission may: 1) deny the proposals, 2) postpone action pending further study, or 3) 

authorize the proposals with or without conditions. In arriving at a course of action, the 

Commission considers a range of alternatives in light of the Project’s objectives, evaluation 

criteria, and environmental comparisons. Each alternative is considered until it is clear that the 

alternative is not reasonable or would result in greater environmental impacts that could not be 

readily mitigated. Those alternatives that appear to be the most reasonable with less than or 

similar levels of environmental impact are reviewed in the greatest detail. 

3.1 NO ACTION OR POSTPONED PROJECT 

If the Commission denies Jordan Cove’s and Pacific Connector’s proposals or postpones action 

on the proposals, the environmental impacts identified in this EIS would not occur. If the 

Commission selects the no action or postponed action alternative, the objectives of the proposed 

Project would not be met and the applicants would not be able to import LNG to provide natural 

gas to markets in the Pacific Northwest, northern California, and northern Nevada. 

Various studies indicate that under certain scenarios existing natural gas supplies and 

infrastructure could fall short of meeting regional peak demand in the near future (NWGA 2007; 

ICF 2007). Without the additional natural gas volumes to be provided through the LNG import 

terminal proposed by Jordan Cove and the associated sendout pipeline proposed by Pacific 

Connector, customers in the Pacific Northwest, northern Nevada, and northern California would 

have fewer and potentially more expensive options for obtaining natural gas supplies in the 

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

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

environmental impacts, in the event the Commission chooses the No Action Alternative. 
3-3 3.0 – Alternatives 

Increased demand for natural gas, coupled with limits on supply, could lead to future higher 

prices. Higher natural gas prices (or the threat of higher gas prices) could also lead to alternative 

proposals to develop other natural gas delivery infrastructure, increased efficiency and 

conservation or reduced use of natural gas, and/or the use of other sources of energy. Alternative 

fuel sources, such as coal or oil, could provide an equivalent amount of energy as the proposed 

Project, but may have greater environmental impacts (see section 3.1.3.2 below). The EIA 

Annual Energy Outlook for 2008 projected an increase in total coal consumption in the United 

States between 2006 and 2030 as coal is used more in the future for electric generation, in part 

because of constraints on supplies of natural gas and higher natural gas prices. Higher natural 

gas prices were also cited as a reason for the projected increased demand for renewable fuels. 

However, as discussed in more detail in section 3.1.3.1, existing renewable energy sources, such 

as solar, wind, and geothermal resources, would not be able to produce the amount of energy 

equal to the proposed Project. 

3.1.1 Alternative Natural Gas Infrastructure Proposals 

The adoption of the no action alternative could result in the expansion of other existing interstate 

natural gas pipeline systems or LNG facilities, or the construction of new natural gas 

infrastructure to meet the increasing demand for natural gas in the Pacific Northwest, northern 

California, and northern Nevada. In section 3.2 we examine the most reasonably foreseeable 

natural gas and LNG system alternatives. Any expansion of existing systems or construction of 

new facilities would result in specific environmental impacts that could be less than, similar to, 

or greater than those associated with the proposed Project. 

3.1.2 Increased Efficiency and Conservation of Natural Gas 

Denying or postponing a decision on Jordan Cove’s and Pacific Connector’s applications could 

limit access to new supplies of natural gas for the Pacific Northwest, northern Nevada, and 

northern California in the future. One possible result of limiting new supplies of natural gas in 

the region could be consumer conservation and programs to stifle demand and increase energy 

efficiency. There is no doubt that both conservation and increased efficiency have an important 

role to play in the future energy needs of the West Coast. California implemented one of the 

most aggressive energy efficiency programs in the United States, with the lowest per capita 

consumption rate of electricity in the nation. Between 1990 and 2002, utilities in the Pacific 

Northwest invested $2.4 billion in conservation, resulting in savings of 2,600 average MW per 

year (ODE 2005a). In its Fifth Power Plan, the NWPCC (2005) recommended conservation 

targets of 700 average MW between 2005 and 2009 and 2,500 average MW during the 20-year 

planning period. 

State regulators have already begun to require gas and electric companies to implement 

conservation programs and have promoted public programs encouraging energy conservation. 

The state of Oregon offers both Business and Residential Energy Tax Credits and an Energy 

Loan Program designed to help businesses and residential consumers invest in energy efficiency 

through such actions as the purchase of more efficient appliances, heating and air conditioning 

systems, and building renovations. These programs have seen dramatic results in the last 5 

years. According to the 2005-2007 Oregon Biennial Energy Plan (ODE 2005a), in 2000 the 

combined residential and business energy tax credit programs stimulated savings of 58.9 

kilowatt-hours (kWh). By 2003, savings had reached 860.3 million kWh. In 2005, the Business 

Energy Tax Credit resulted in savings of 2.2 billion kWh in electricity and 107.9 million therms 
3-4 3.0 – Alternatives 

in natural gas, while the Residential Energy Tax Credit saved 104.1 million kWh in electricity 

and 2.8 million therms in natural gas total in Oregon (ODE 2008a). 

Although conservation may slow the growth of natural gas use, energy efficiency programs alone 

are not expected to reverse the demand for additional natural gas or reduce the price of natural 

gas for customers in the face of growing populations in the Pacific Northwest, northern 

California, and northern Nevada, and increased use of natural gas for industrial purposes 

including electrical generation. Even though energy efficiency has helped to flatten demand, the 

CEC (2007) estimates that electricity use in California will continue to rise at a rate of 1.25 

percent annually. 

3.1.3 Other Sources of Energy 

It is also conceivable that adoption of the no action alternative could promote the development of 

other (non-LNG/natural gas) sources of energy. State agencies are promoting renewable energy 

programs to help reduce the demand for fossil fuels. These include hydropower, solar, wind, 

geothermal, nuclear power, and biofuels. While renewable fuels can contribute to meeting the 

energy needs of the area, they take years to develop and are not predicted to totally replace the 

future demand for natural gas in the region partly because natural gas has other end-uses beyond 

electric power production. Absent new additional sources of natural gas, other fossil fuels, 

including coal and oil, may be used to make up the projected energy gap. The use of other fossil 

fuels, in place of natural gas, could have more adverse environmental impacts than the proposed 

Project by generating more greenhouse gases and contributing to global warming (see discussion 

below). For comparison purposes where applicable, we assume that all of the LNG would be 

converted to electric power, through typical high-efficiency combined cycle gas-fired turbine 

generating stations. However, as alluded to above, this might not be a reasonable assumption. 

3.1.3.1 Renewable Energy 

Renewable energy resources represent a possible alternative to the use of natural gas. For 

example, hydro and wind resources represent alternatives for electricity generation, whereas 

biomass, solar, and geothermal resources can be used to generate heat as well as electricity. 

However, there are also environmental impacts associated with the use of renewable resources. 

For example, hydropower dams may affect fish, and wind turbines may affect birds and bats. 

The Pacific Northwest and California have been at the forefront nationally in terms of the use of 

renewable energy resources, in large part due to the historical prevalence of hydropower 

resources in the region. The state of Washington passed the Energy Independence Act and 

Renewable Portfolio Standard (RCW 19.285) in 2006, requiring electric utilities with more than 

25,000 customers to establish conservation targets beginning in 2010, with the goal of having 15 

percent of their load generated from renewable resources by 2020. In 2007, the Oregon 

legislature created a Renewable Portfolio Standard requiring electric utilities in that state to 

include power generated from renewable sources in their energy mix, with the goal of having 25 

percent come from renewable sources by 2025 (ODE 2008a). California also has a Renewables 

Portfolio Standard, with of goal of generating one-third of the state’s energy from renewable 

resources by 2020. Currently, about 11 percent of the electricity generated in California comes 

from renewable resources other than hydropower, including solar, wind, and biomass sources 

(CEC 2007). 
3-5 3.0 – Alternatives 

The ODE (2008b) wrote the following in its LNG and Natural Gas Review: 

“Wind power, solar power, and hydropower all rely on beneficial weather conditions for 

electricity production. There is currently no grid scalable method to store electricity so 

there needs to be backup production in case the wind is not blowing or the sun is not 

shining.....As renewable energy becomes a larger part of the Oregon energy portfolio, 

more gas-fired generation will likely be built to fill the gaps. This could increase the 

demand for natural gas in Oregon.” 

Hydropower and Wave Energy

Hydropower, or generating electricity from water stored behind dams and then run through 

turbines, plays a significant role in the current energy mix of the Pacific Northwest, accounting 

for 64 percent of the region’s energy capacity in 2006 (NWPCC 2008). In 2007, hydropower 

generated 66,700 thousand megawatt hours (MWhr) in Washington state (EIA 2007c). In 

Oregon, in 2005, hydropower produced 42 percent of the electricity in the state (ODE 2008a). 

Hydropower provided about 7 percent of the power capacity for the state of Nevada in 1997 

(Nevada 2008). In California, hydropower accounts for about 21 percent of the state’s energy 

(California 2008). Combined, instate hydropower projects in California generated 48,876 

gigawatt-hours (GWh) of electricity in 2006 (CEC 2006). 

However, the ODE recognizes that climate change may alter the runoff regime feeding water to 

the hydroelectric dams along the upper Columbia River, resulting in less summer power in the 

future. Legal issues concerning the operation of the dams with regards to fisheries could also 

diminish hydropower generation (ODE 2008b). According to the NWPCC (2007), most feasible 

hydroelectric facilities have already been developed. New hydropower projects in the Pacific 

Northwest are estimated to yield 480 MW in additional electric capacity through 2025, but that 

new capacity would mainly replace older hydroelectric facilities that are retired. ICF (2008a) 

indicated that of the 2,600 MW of new electric generation capacity that is scheduled to come on 

line in Oregon and Washington through 2009, only 15 MW (or less than 1 percent) would be 

from new hydroelectric capacity. 

It is unlikely that new dams would be constructed in the future because of high development 

costs and environmental impacts. In fact, efforts are underway to remove some existing dams to 

restore habitat.1

 Further, environmental scrutiny during the relicensing process for existing dams 

has, in some instances, resulted in increased release of water for fisheries, which has reduced 

their electric generation capacity. It has been estimated that the percentage contribution of 

hydrogeneration is going to decline from supplying about 10 percent of the nation’s electricity in 

2005 to about 6 percent in 2020 (EIA 2005). Thus, the development of additional hydropower 

resources is not considered to be a reasonable or environmentally preferable alternative to the 

proposed Project. 

A new potential source of electric power for the future is hydrokinetic energy, or electricity 

generated from ocean currents, swells, waves, or tidal action. It has been projected that if 

hydrokinetic technologies could be successfully developed, these facilities could potentially 

double the amount of hydrogenerated electricity available in the United States (FERC 2008). 

 

1

 Portland General Electric plans to abandon the Bull Run and Little Sandy hydroelectric projects in Oregon and 

take out the Marmot and Little Sandy dams associated with those projects (ICF 2008a). 
3-6 3.0 – Alternatives 

The ODE (2008a) estimated that ocean wave energy could provide over 500 MW in electricity 

from Oregon projects developed over the next 10 years. 

Currently, the United Kingdom has an ocean energy program supported by the government. The 

FERC recently initiated a licensing process for hydrokinetic test projects in the United States. 

The goal of the FERC pilot process is to allow developers to test new technologies, to determine 

the best location for hydrokinetic facilities, and to discover the environmental effects associated 

with the siting and operation of such facilities. A preliminary permit, issued for up to 3 years, 

gives the developer priority to study a site, but does not authorize construction and operation. In 

2008, the FERC granted 123 preliminary permits for hydrokinetic power projects. However, 

only six of these were for wave projects, one was for a tidal project, and the rest went to in-river 

current systems. 

Although numerous preliminary permits have been issued on the east coast, only two wave 

power projects have been licensed under the FERC pilot program on the West Coast. Both were 

proposals from Finavera Renewables Ocean Energy, Ltd. (Finavera). One proposal called for the 

installation of four 250 kW wave energy conversion buoys in Makah Bay off the coast of 

Washington State. The other Finavera project would be located off the coast of Humboldt 

County, California (Boyle 2008). In February 2009, Finavera filed to surrender its license for 

both the Makiah Bay and Humboldt County wave power projects. The only other hydrokinetic 

project currently with FERC permission to operate is a 70 kW facility below an existing 

Mississippi River dam near Hastings, Minnesota, that was approved in December 2008 as an 

addition to a traditional hydropower license (Wheldon 2009). 

Additional wave power projects are in the early development stage for facilities near Grays 

Harbor, Washington and Reedsport, Oregon (International Water Power and Dam Construction 

2008; Coos Bay World 2008; KCBY 2008). A report by the Electric Power Research Institute 

identified seven sites along the Oregon Coast as being potentially suitable for wave energy 

projects. In 2006, Ocean Power Technologies proposed a wavepower project at Newport, 

Oregon, and received a preliminary permit from the FERC early in 2009 (Chambers 2009). In 

addition, the FERC is reviewing hydrokinetic proposals at Winchester Bay, Oregon and Coos 

Bay under the traditional hydropower license application process. The ODE counted eight 

applications for wave energy projects to the FERC proposed by developers or Oregon coastal 

counties (ODE 2008a). In March 2008, the FERC signed a MOU with the State of Oregon to 

coordinate procedures and schedules for the review of wave energy projects in state waters off 

the coast of Oregon (Electric Light & Power Utility 2008; Dam Engineering 2008). 

While there are many proposals being pursued, there are currently no commercial wave power 

facilities operating in the United States. The development of wave energy resources in the future 

is speculative, because of challenges related to the use of new technologies, financial barriers, and 

an unclear regulatory process. Nor are the potential environmental impacts resulting from the 

construction and operation of a hydrokinetic project fully understood, although it appears that a 

wave power facility would likely have some effects on aquatic resources. Therefore, we do not 

consider hydrokinetic resources to be a reasonable, feasible, or foreseeable alternative to the 

proposed Project. 
3-7 3.0 – Alternatives 

Geothermal

Geothermal resources are naturally occurring sources of heat, such as hot springs, geysers, or 

volcanoes that could be tapped to generate energy. Geothermal resources include hightemperature (above 100 °C) sources for electric generation, intermediate temperature (50 to 100 

°C) sources for industrial, agricultural, and municipal uses, and low temperature sources for 

residential heat pump uses. 

In 2003, wind and geothermal resources combined supplied 1 percent of the electric generation 

in Oregon, averaging 53 MW of power (ODE 2008a). Geothermal resources in Oregon are used 

to supply heat for buildings, swimming pools, and industrial uses. As of 2005, there were about 

2,200 ground-source heat pumps providing space and water heating to homes in Oregon. The 

City of Klamath Falls uses geothermal energy for a district heating system. There have been 

explorations on the flanks of Newberry Volcano to evaluate its potential future use for hightemperature geothermal electricity production (ODE 2005a). The Warm Springs Tribes are 

considering a geothermal project at Mount Jefferson. 

The 13-megawatt Raft River Project in southern Idaho is the only commercial geothermal power 

plant operating in the Pacific Northwest (NWPCC 2007). California has 33 geothermal power 

plants that generate nearly 90 percent of the nation’s total amount of geothermal electricity (EIA 

webpage, Geothermal Energy). In 2003, California produced nearly 13 million MWh of 

electricity from geothermal sources. Nevada has 14 geothermal power plants, with a combined 

capacity of about 177 MW (Nevada Renewable Energy & Energy Conservation Task Force 

webpage). 

The main barriers to the further development of geothermal resources are the identification of 

potential naturally occurring sources, and above-market costs. In California, most available 

geothermal sites appear to have already been exploited, with a decline in geothermal energy 

production from its peak of 14.5 MWh in 1990. Given the physical limits of geothermal sites 

that have a potential for future exploitation, the lack of interest from investors in developing new 

potential resources, and the minimal energy geothermal resources produce, we do see this type of 

renewable resource as a feasible, reasonable, or predictable alternative to the proposed Project. 

Biomass and Biogas

Biomass resources can produce electricity and heat or steam from wood, wood waste, plant and 

animal waste, or other organic matter. As of 2007, biomass generation represented about 2 

percent of the total electric power capacity of the Pacific Northwest (NWPCC 2007). That year, 

the Washington Public Utilities Commission (PUC) estimated that biomass projects in the state 

were capable of generating almost 200 MW in total. In 2004, biomass produced 79 trillion Btu 

of energy in Oregon, or about 6 percent of that state’s total energy supply (ODE 2008a). 

More than 90 percent of Oregon’s biomass energy comes from forest or wood waste and paper 

mill pulping liquor. About 40 percent of Oregon’s biomass energy comes from wood waste 

burned at 49 industrial sites. Ten of these sites produced 866,000 MWh of electricity. About 46 

percent of the total biomass energy in Oregon is produced from combustion of pulping liquids at 

six mills. Two mills produced about 310,000 MWh of electricity in 2004 (ODE 2008a). A new 

10-MW wood waste cogeneration plant recently went on line at the end of 2007 in Lyons, 

Oregon (NWPCC 2008). 
3-8 3.0 – Alternatives 

There are three landfills in Oregon that tap waste methane gas to generate 37,000 MWh of 

electricity annually for industrial use, with a fourth under construction in southern Oregon. In 

addition, 29 wastewater treatment plants in Oregon use methane to generate 26,000 MWh of 

electricity annually to provide heat for sewage treatment. Two facilities produced about 500 

MWh of electricity annually from cow manure (ODE 2008a). 

In California, about 19 percent of the state’s renewable energy comes from biomass resources. 

California would like to see about 2,000 MW generated from biomass resources by 2020, mainly 

the product of biogas from dairies and landfills (CEC 2007). The only biomass power project 

known in Nevada is a heating system for an elementary school in Ely (Nevada Renewable 

Energy & Energy Conservation Task Force webpage). 

Barriers to the further development of biomass resources include uncertainty in biomass outputs, 

the high costs associated with the transporting of forest products to an energy conversion facility, 

and lack of private capital investment in the development of additional biomass facilities. The 

CEC has invested $94 million over the last 5 years attempting to develop biomass resources, and 

overcome economic obstacles and environmental impacts. In Oregon, virtually every paper mill 

has already installed equipment to allow the utilization of biomass waste, leaving little potential 

to develop new resources. Because of the relatively high costs of development, only about 15 

MW in new biomass generation were brought on line between 2004 and 2007 in the Pacific 

Northwest (NWPCC 2007). Because of the difficulties of developing biomass resources, and the 

small amount of additional energy they could produce, we do not believe that this represents a 

feasible, reasonable, and foreseeable alternative to the proposed Project. 

Solar

There are three primary ways to harvest solar energy: 1) direct sunlight into buildings can be 

used for light and heat; 2) roof-mounted collectors can use sunlight to heat water; and 3) sunlight 

can be converted into electricity using photovoltaics or solar panels. There are about 300 solar 

electric systems in the State of Oregon, and residents have installed more than 17,600 solar water 

heating systems in the last 25 years (ODE 2008a). 

In California, solar power accounted for 616 GWh of electricity in 2006, representing only about 

0.2 percent of the gross system power for the state (CEC 2006). A 64 MW solar project is 

currently being built near Boulder, Nevada (Nevada Renewable Energy & Energy Conservation 

Task Force webpage). 

Solar power has never made a significant contribution to the energy mix in the Pacific Northwest 

because of the weather conditions in its major metropolitan population centers. There is not 

enough sunlight to generate much solar energy during the cloudy winter months when there is 

peak demand in Portland and Seattle. National Weather Service data collected at the SeattleTacoma International Airport, which has a similar climate to much of western Oregon, showed 

the average annual possible sunshine for the area is about 47 percent. Data presented by the 

Renewable Energy Power Project indicated that the daily average is 2.9 kWh per square meter 

(m2

) for Seattle. At this rate, thousands of acres of solar collectors would be needed. Solar 

technology is still in the early development stages, and the cost of producing power with this 

technology is high (ICF 2008a). There is little existing infrastructure for solar energy in southern 

Oregon. While solar power is and will continue to be a component of the renewable energy mix 
3-9 3.0 – Alternatives 

for the Pacific Northwest, solar power does not appear capable of producing enough energy in 

this region to be considered a reasonable or feasible alternative to the proposed Project. 

Wind

In the Pacific Northwest in 2007, wind power accounted for about 3 percent of the regional 

electric capacity (NWPCC 2007). As of 2007, wind projects in operation in Oregon could 

generate a total of 450 MW (ODE 2008a). The Washington PUC estimated that in 2007 wind 

farms in that state could generate a total of about 915 MW (with two projects overlapping into 

Oregon). 

In California, wind power generated about 4,927 GWh of electricity in 2006, representing about 

1.8 percent of the gross system power in the state (CEC 2006). There are currently no wind 

farms in Nevada (Nevada Renewable Energy & Energy Conservation Task Force webpage). 

Due to the variable nature of wind, on average, wind turbines only generate about one-third of 

their maximum output capacity. Another barrier to the further development of wind farms in 

eastern Oregon is lack of transmission capacity. The clustering effects at wind farms result in 

spikes and troughs in production that have no relation to demand, and contribute to transmission 

congestion. However, a stakeholder group evaluating this situation in 2006 believes that about 

6,000 MW of electricity from eastern Oregon wind projects could find its way into the region’s 

grid by 2024 (ODE 2008a). In addition, the cost of developing new wind projects has gone up 

since 2004 because of rising prices for equipment (NWPCC 2007). In California, wind power 

generation has grown at a rate of only about 1.5 percent per year since 1990. Environmental 

consequences from wind farms include visual effects and impacts on birds and bat populations. 

Lastly, there are limitations to wind power in comparison to energy production from the 

proposed Project. We estimate that 1 Bscf/d throughput of natural gas when supplied to a 

combined cycle combustion turbine would generate about 5,200 MW on a continuous basis. 

Based on conversations with staff at the ODE, it is estimated that the total capacity of all 

currently operating, approved, and proposed wind farms in Oregon would be 3,700 MW. Using 

the largest wind turbine made by General Electric (capable of generating 3.6 MW in high wind 

areas offshore), it would take 4,337 wind turbines to produce an equivalent amount of electricity 

that could be generated using the total capacity of the natural gas from the JCE & PCGP Project. 

Therefore, we do not believe that wind power represents a reasonable, feasible, foreseeable 

alternative to the proposed Project. 

Nuclear Energy 

Nuclear power has the potential to generate enough energy to substitute for the proposed Project. 

However, due to economic, environmental, and regulatory factors, the future of nuclear power as 

an energy alternative is in doubt. There are currently 103 nuclear reactors operating at 65 sites in 

31 states, generating about 19 percent of the nation’s electricity. There is only one nuclear 

power plant currently operating in the Pacific Northwest; the Columbia Generating Station in 

Washington with an electrical output of 1,107 MW. There are four nuclear power plants 

currently operating in California; two at Diablo Canyon and two at San Onofre, with a combined 

electrical generation capacity of 4,324 MW (NRC 2008). Nuclear power represented about 5 

percent of the energy mix in California in 2006, and imported nuclear power represented about 

3.4 percent of the energy mix in Oregon in 2003 (ODE 2008a; CEC 2007b). 
3-10 3.0 – Alternatives 

The only nuclear power facility in Oregon, the Trojan plant on the Columbia River in Columbia 

County, operated between 1976 and 1992. It was closed in 1993, years before its scheduled 

operational life-span, in part because of environmental and safety issues. The Hanford nuclear 

weapons plant in southeast Washington halted production in 1988, but is the site of radioactive 

contamination that will take years and billions of dollars to remediate (ODE 2008a). 

Until recently, no new nuclear power plants have been planned since the mid-1980s due to 

concerns raised after the Three Mile Island incident in Pennsylvania in 1979. As a result of 

incentives offered in the EPAct, the Nuclear Regulatory Commission expects that it may receive 

up to 21 new applications for nuclear power plants between 2007 and 2009. Two of these 

proposed plants would be located in Idaho; one at Bruneau and one near Boise. The NWPCC 

believes that the earliest a new nuclear power plant could come online in the Pacific Northwest 

would be 2015. The CEC indicated that it does not expect to see the development of new 

nuclear power plants in California in the near future because of problems related to the 

disposition of spent fuel, long regulatory review time, and costs. The ODE (2008a) has stated 

that “nuclear plants are not likely to be approved in Oregon in the near term.” An Oregon law 

requires voter approval to allow a new nuclear power plant to be built in the state, and only if a 

permanent repository can be found for the disposal of plant waste. 

We do not consider nuclear power to be a feasible foreseeable alternative to the proposed 

Project. Barriers to the nuclear industry include problems related to the disposition of spent fuel, 

long regulatory review time, and costs. The Watts Bar nuclear power plant in Tennessee that 

began operation in 1996 took 23 years to complete, at a cost of $6.9 billion. The proposed 

nuclear power plant at Bruneau, Idaho is estimated to cost $4.5 billion to build (Idaho Statesman 

2008). 

3.1.3.2 Other Fossil Fuels 

Compared to other fossil fuels, such as oil and coal, natural gas is relatively clean and efficient. 

Burning natural gas results in less emission of regulated pollutants (nitrogen dioxide [NO2], 

sulfur dioxide [SO2], and particulate matter with an aerodynamic diameter of 10 microns or less 

[PM10]), or unregulated green house gasses such as CO2. It is likely that other fossil fuels would 

be used in place of natural gas if it were not available. Table 3.1.3.2-1 shows a comparison of air 

emissions from burning different types of fossil fuel. The emissions shown in the table 

demonstrate the advantage of using natural gas in terns of air quality. In order to reduce 

emissions from new coal- or oil-burning power facilities, emission control equipment could be 

required. This may reduce the economic viability of these facilities. 

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

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

proposed LNG. The distribution of these fuels to market would require more truck, barge, and 

train trips than the distribution of an equivalent amount of energy derived from natural gas, 

which would increase emissions and traffic congestion. 
3-11 3.0 – Alternatives 

TABLE 3.1.3.2-1 

Comparison of Air Emissions from Burning Fossil Fuels

Emission Rate (tons per year) a/

Natural Gas Fuel Oil Coal 

Sulfur dioxide (SO2) 110 86,643 231,785 

Nitrogen oxide (NO2) 16,555 33,113 115,893 

Particulate matter with a diameter of 10 microns or less (PM10) 1,325 1,878 5,133 

Carbon monoxide (CO) 16,445 17,440 3,618 

Carbon dioxide (CO2) 18.333,333 26,583,333 34,833,333 

Carbon (C) 5,000,000 7,250,000 9,500,000 

a/ The emissions generated by coal, fuel oil, and natural gas were estimated using information from the EPA Web site. They were 

calculated for boilers with heat input ranges of between 100 and 250 million BTUs per hour. The emissions for each fuel type 

were estimated based on a total annual fuel use of 146,000,000 million BTUs per year. 

The ODE conducted an independent review of lifecycle GHG emissions resulting from an LNG 

project, making assumptions about fuel burned from the point of origin to its use for electric 

generation in Oregon. The ODE concluded that carbon emissions from vaporized LNG when 

combusted in a conventional electric power plant would fall somewhere between domestically 

produced natural gas transported by interstate pipeline and coal. According to the ODE review, 

when combusted in a conventional electric power plant, lifecycle GHG emissions from LNG 

were forecast to be 6 to 12 percent greater than domestically produced natural gas transported by 

interstate pipelines, but 39 to 48 percent less than coal (ODE 2008b). 

The ODE admits that natural gas would produce less GHG than using coal for electric 

generation. The report states: “Over 40 percent of the electricity consumed in Oregon comes 

from coal-fired generation. As climate change legislation is enacted, it is likely that financial 

considerations will encourage the switch from coal to natural gas since natural gas has much 

lower life-cycle GHG emissions. It is unlikely that Oregon will be able to replace all of the coalfired power it uses with renewables in the short-term, so natural gas consumption is likely to 

rise.” 

Another LNG developer in Oregon has questioned the validity of the ODE LNG review and 

GHG conclusions (NorthernStar 2008). That developer claims that the ODE GHG calculations 

were flawed because they were based on disputed research conducted by Carnegie Mellon 

University that made assumptions regarding not-yet-developed carbon capture technologies. 

ICF (2008d) conducted a study comparing GHG emissions from imported LNG, Rocky 

Mountain natural gas, and Rocky Mountain coal when used as fuel for electric generation in 

Oregon. The study assumed that the LNG was brought by ship from countries around the Pacific 

Basin to the Jordan Cove terminal, that the coal was transported by railroad from the Power 

River Basin to Oregon, and the natural gas was delivered from the Green River Basin via the 

proposed Ruby pipeline. The total supply chain was examined, including exploration, drilling, 

production, processing, and transportation of natural gas; liquefaction, loading, shipping, storage, 

and regasification of LNG; and the mining, preparation, loading, and transportation of coal. 

Total GHG emissions were expressed per megawatt-hour of electricity generated at Oregon 

power plants. Natural gas from the Green River Basin would result in almost 1,200 pounds of 

CO2 per MMBtu (lb/CO2e/MMBtu), while Pacific Basin LNG would result in about 1,300 

lb/CO2e/MMBtu, and Powder River Basin coal would cause 2,300 lb/CO2e/MMBtu. 
3-12 3.0 – Alternatives 

A recent study by Pace (2009) for the Center for Liquefied Natural Gas compared GHG 

emissions produced from using LNG at a modern natural gas-fired combined cycle power plant 

with current coal burning technology for electric generation, an advanced ultra supercritical coal 

fired (SCPC) power plant, and an integrated gasification combined cycle (IGCC) coal-fired 

power plant. It was estimated that LNG would produce about 1,045 lb/CO2e/MMh, existing coal 

technology would produce 2,731 lb/CO2e/MMh, advanced ultra SCPC would produce 1,868 

lb/CO2e/MMh, and coal IGCC would produce 1,808 lb/CO2e/MMh. 

3.2 SYSTEM ALTERNATIVES 

System alternatives would make use of other existing or proposed LNG or natural gas pipeline 

facilities to meet all or most of the natural gas demand of the proposed Project. A system 

alternative would make it unnecessary to construct all or part of the proposed Project, although 

some modifications or additions to the existing facilities may be necessary. These modifications 

or additions would result in environmental effects that may be less than, similar to, or greater 

than those associated with this Project. 

3.2.1 Existing Pipeline Systems 

Two existing interstate natural gas pipelines, the Williams Northwest system and TransCanada’s 

GTN pipeline system, currently serve the Pacific Northwest. Williams Northwest is a 3,900-

mile-long bi-directional transmission system crossing the states of Washington, Oregon, Idaho, 

Wyoming, Utah, and Colorado. This system provides access to British Columbia, Alberta, 

Rocky Mountain, and San Juan Basin natural gas supplies. It has a peak design capacity of 3.4 

Bscfd (Williams Northwest Pipeline 2008). 

The GTN pipeline system includes 612 miles of pipeline beginning at Kingsgate, British 

Columbia, traversing through northern Idaho, southeastern Washington and central Oregon, and 

terminating near Malin, Oregon, where it interconnects with Tuscarora and PG&E. Natural gas 

for the GTN pipeline originates primarily from WCSB supplies; although it can receive Rocky 

Mountain gas through interconnections with Williams Northwest near Spokane and Palouse, 

Washington and Stanfield, Oregon. The GTN system can handle about 2.9 Bscfd (GTN 2008). 

In 2006, GTN transported about 2190 Mscfd to the northern California border (CEC 2007a). 

Natural gas is transported into northern Nevada via two jurisdictional interstate pipeline systems 

operated by Paiute Pipeline Company (Paiute) and Tuscarora. Paiute, a subsidiary of Southwest 

Gas Corporation, receives gas from Williams Northwest via its Owyhee Lateral at the Idaho 

border, and has an interconnection with Tuscarora at Wadsworth Junction, Nevada. Natural gas 

in the Paiute system could originate from the San Juan Basin, the Rockies, or the WCSB. 

Paiute’s existing pipeline system serves the communities of Elko, Lovelock, Fallon, Dayton, 

Yerington, Reno, Carson City, and Lake Tahoe. Paiute provides firm transportation and contract 

LNG storage (through a peak shaving plant) for three LDC customers: Sierra Pacific Power 

Company, Southwest-Northern Nevada, and Southwest-Northern California. 

Tuscarora, a subsidiary of TransCanada, receives gas from GTN near Malin, Oregon, and 

extends over northern California to an interconnection with Paiute near Wadsworth, Nevada. 

Tuscarora consists of about 240 miles of 20-inch-diameter pipeline, with a subscribed capacity of 

180,000 Mscfd (Tuscarora Gas Transmission 2008). It mainly supplies natural gas to the Reno 

metropolitan area. 
3-13 3.0 – Alternatives 

The existing PG&E system serves northern California. PG&E receives natural gas originating 

from the Rocky Mountains and the Southwestern United States via its Line 300, with a receipt 

capacity of about 1,140 Mscfd. It receives natural gas originating from Canada and the Rocky 

Mountains via an interconnection with GTN at the Oregon/California border with PG&E Lines 

400/401, which has a receipt capacity of about 2,021 Mscfd. PG&E also accepts natural gas 

produced in California into its system (CEC 2007a). PG&E’s existing system extends from 

Eureka to Bakersfield. It includes 6.136 miles of transportation pipelines and 40,123 miles of 

distribution lines (PG&E 2008). The local distribution system operated by PG&E is regulated by 

the California Public Utilities Commission. 

There is an existing non-jurisdictional 12-inch-diameter pipeline that extends some 60 miles, 

over the Coast Range, from the Williams Northwest Grants Pass lateral near Roseburg to Coos 

Bay. This pipeline was constructed by Coos County and is operated by Northwest Natural as a 

LDC. The Coos County pipeline has a MAOP of 1,000 psig and was designed to bring gas from 

the Williams Northwest interstate system to the communities around Coos Bay, flowing in the 

opposite direction of the proposed Pacific Connector pipeline. The terminus of the Coos County 

pipeline is approximately 7.7 miles south of the proposed Jordan Cove LNG terminal. 

Northwest Natural built a line from the terminus of the Coos County pipeline across Coos Bay to 

the North Spit, as part of its local distribution system. 

It is possible that the Coos County pipeline could be converted into a jurisdictional facility, and 

used as a system alternative to the proposed Pacific Connector pipeline. In that situation, 

modifications would need to be made to the Coos County pipeline, to connect to the proposed 

Jordan Cove LNG terminal, and reverse the direction of flow to make deliveries into the Grants 

Pass lateral. However, the estimated maximum capacity of the Coos Bay pipeline is about 

45,000 Dth/d, which is less than 5 percent of the proposed Jordan Cove LNG terminal send-out 

capacity. Also, the Coos County pipeline ends at the Grants Pass lateral, and one of the main 

objections of the Pacific Connector pipeline is to provide gas from imported LNG to markets in 

northern Nevada and northern California through an interconnection with the existing Tuscarora 

and PG&E pipeline systems near Malin, Oregon, about 170 miles east of Roseburg. Because it 

does not extend to the California border, and has restricted capacity and operating pressure, we 

do not believe the conversion of the Coos County pipeline to interstate service would be a 

reasonable or practical system alternative to the Pacific Connector pipeline. However, the route 

of the Coos County pipeline was considered as a partial alternative route for the Pacific 

Connector pipeline below in section 3.4.1.1. 

As system alternatives to the proposed JCE & PCGP Project, we considered the possibilities of 

expanding or modifying the existing interstate natural gas systems of either Williams Northwest, 

GTN, Tuscarora, Paiute, or PG&E to handle the additional volumes proposed by the JCE & 

PCGP Project and meet the Project objectives of bringing new sources of gas to southern 

Oregon, northern Nevada, and northern California. It is unknown exactly what additional 

facilities would have to be built to accommodate the proposed volumes of the JCE & PCGP 

Project on existing systems. The expansion or modifications to those existing systems would 

result in environmental impacts equal to or greater than the new facilities proposed by Jordan 

Cove and Pacific Connector. Both Williams Northwest and GTN have recently considered 

expansions of their systems, as discussed below in section 3.2.2. 
3-14 3.0 – Alternatives 

One of the obstacles associated with the expansion of existing interstate pipeline systems as 

alternatives to the JCE & PCGP Project, would be the procurement of new sources of natural gas 

that those systems could transport, in addition to the volumes they currently carry, as opposed to 

the importation of LNG. It is unlikely that substantial additional volumes of natural gas could be 

produced in the Southwest (Anadarko Basin of Oklahoma and Permian Basin of Texas) in the 

future and transported to the West Coast. The CEC estimated that natural gas supplies coming 

into southern California at Topock and Blythe from Southwest sources (via the existing El Paso 

pipeline system) would decline by about 17 percent between 2007 and 2017. Net natural gas 

imports from Canada are projected to decrease from 3.3 Tcf in 2005 to 1.2 Tcf in 2030 (EIA 

2007). 

There are projections for increased domestic production from shale gas in the Appalachian Basin 

and northwest Louisiana and east Texas, and from unconventional sources in the Rocky 

Mountain region. However, there are currently no interstate pipelines extending from the East or 

Gulf Coasts to the Pacific Coast. There is also the potential for natural gas to be brought down 

from Alaska to the continental United States. In June 2008 the FERC initiated the Pre-filing 

review for an Alaska natural gas pipeline proposed by Denali-Alaska Pipeline LLC (Denali). 

Denali indicated it would like to file a formal application with the FERC in August 2011, and 

estimated that the Alaska pipeline would not be constructed and operational until at least 2018. 

The Rocky Mountain region is expected to increase its production of natural gas over the next 20 

years, primarily from unconventional sources such as tight sands, shale, and coalbed methane. 

The portion of natural gas contributed by the Rocky Mountain region to the total of the lower 48 

states onshore natural gas production is expected to increase from 27 percent (in 2003) to 38 

percent in 2025 (EIA 2005). Part of this predicted gain in share of total onshore production is 

because some other domestic regions are expected to experience declining production rates. 

Much of the additional new production in the Rocky Mountain region is targeted for markets in 

the Midwest. For example, the Rockies Express pipeline system would transport natural gas 

from Wyoming to Ohio. The proposed Pathfinder and Bison projects would transport natural gas 

from Wyoming to North Dakota, for ultimate delivery to the Chicago area. 

There are also plans for new pipelines to bring Rocky Mountain gas to Oregon, northern Nevada, 

and northern California. Both the Bronco and Ruby projects propose to construct pipelines 

between the hub at Opal, Wyoming to interconnections with the existing GTN, Tuscarora, and 

PG&E systems just east of Malin, Oregon. The proposed Sunstone pipeline would bring more 

Rocky Mountain gas to eastern Oregon by looping part of the Williams Northwest system. The 

proposed Palomar pipeline would provide additional supplies of Canadian and Rocky Mountain 

natural gas to the Portland metropolitan area through an expansion of GTN’s system. The 

Palomar, Ruby, Bronco, and Sunstone projects are discussed in more detail below in section 

3.2.2. 

In addition, Sempra LNG, a subsidiary of Sempra Energy (Sempra), recently put its Energia 

Costa Azul LNG terminal (Costa Azul), located near Ensenada, Mexico, into service. This 

facility, which can supply natural gas to northern Mexico and southern California using LNG 

imported from the Pacific Basin, is discussed more fully below (see section 3.2.3.1). 
3-15 3.0 – Alternatives 

3.2.2 Newly Proposed Pipelines 

We considered the Palomar, Ruby, Bronco, and Sunstone projects as system alternatives to the 

JCE & PCGP Project. These projects would be new jurisdictional interstate pipelines that are in 

different stages of review before the FERC. In the case of the proposed Bronco pipeline, no 

proposal to the FERC has been submitted yet. 

3.2.2.1 Palomar 

On December 11, 2008, Palomar Gas Transmission, LLC (Palomar) filed an application with the 

FERC, in Docket No. CP08-35-000, to build and operate a bi-directional natural gas pipeline in 

Oregon. Palomar is a joint venture between GTN and Northwest Natural. The main purpose of 

the Palomar project is to bring Canadian and Rocky Mountain gas to the Portland, Oregon 

metropolitan area and the Willamette Valley, and compete with the Williams Northwest system, 

which currently is the only interstate pipeline with direct interconnections with Northwest 

Natural, the LDC for northwestern Oregon and southwestern Washington. In addition, a 

segment of the Palomar pipeline would interconnect with the proposed Bradwood Landing LNG 

(Bradwood) terminal, and provide a second sendout pipeline that could bring new supplies of 

natural gas from imported LNG to the Portland metropolitan area and to the GTN mainline. 

The Palomar mainline would consist of about 217 miles of 36-inch-diameter pipeline, with a bidirectional flow. It could transport about 1,299,000 Mscfd of natural gas eastbound, and 98,135 

Mscfd westward. The pipeline would begin at an interconnection with GTN northwest of 

Madras, and extend over portions of Wasco, Clackamas, Marion, Yamhill, Washington, 

Columbia, and Clatsop Counties, Oregon. Palomar envisions the construction of the pipeline in 

two segments. The first segment would be about 111 miles long from the point of origin with 

GTN to an interconnection with Williams Northwest near Molalla, Oregon. From the vicinity of 

Molalla, a 3.8-mile, 24-inch diameter lateral would provide an interconnection with Northwest 

Natural. The second segment would be about 106 miles long between Molalla and Bradwood. If 

the Bradwood project is not built, Palomar would terminate its pipeline at the end of the first 

segment, at its interconnection with Northwest Natural. Northwest Natural could then construct 

an expansion of its non-jurisdictional local distribution system to connect Palomar to its Mist 

storage field in Columbia County, Oregon. 

The FERC is preparing a separate environmental review of the Palomar project. Based on a 

preliminary review of Palomar’s application, the Palomar pipeline is likely to have environment 

impacts similar to the Pacific Connector pipeline, because Palomar is about the same length, 

would also cross the Cascade and Coast ranges, and would go through forest that may provide 

habitat for the marbled murrelet and northern spotted owl. 

The Palomar pipeline would cross almost 51 miles of federal lands, including parcels 

administered by the Prineville and Salem Districts of the BLM, and the Mount Hood National 

Forest. The route would cross two federally designated Wild and Scenic Rivers: the Deschutes 

and the Clackamas. Other special management areas crossed by the Palomar pipeline include the 

Tillamook and Clatsop State Forests, and the White River State Game Management Area. 

In comparison, construction of the Palomar project would affect about 4,003 acres, while the 

Pacific Connector project would impact a total of about 6,260 acres during construction. The 

Palomar pipeline would be co-located adjacent to existing powerlines or roads rights-of-way for 
3-16 3.0 – Alternatives 

about 26 percent of its route, while the Pacific Connector pipeline would follow existing rightsof-way for about 39 percent of its route. About 56 percent of the Palomar route would cross 

forest and almost 33 percent would cross agricultural land, while 61 percent of the Pacific 

Connector route would cross forest and 14 percent would cross agricultural land. The Palomar 

pipeline would cross 131 perennial waterbodies, while the Pacific Connector would cross 100 

perennial waterbodies. Therefore, the Palomar pipeline has no clear environmental advantages 

over the Pacific Connector pipeline. 

We do not consider Palomar to be a preferable alternative to the JCE & PCGP Project because it 

could not meet some of its main objectives, to provide new sources of natural gas through 

imported LNG to markets in southern Oregon, northern Nevada, and northern California. While 

Palomar would bring new sources of natural gas to the Pacific Northwest, its target market is the 

Portland metropolitan area and the Willamette Valley. Palomar would transport most of its gas 

from Canada, obtained from GTN. It could also transport natural gas produced in the Rockies, 

obtained through GTN’s interconnections with Williams Northwest. A number of studies have 

predicted that Canadian exports into the Western United States are not likely to increase in the 

future, and may even decline as production in the WCSB levels off over time, additional 

customers in Canada are served, and United States production increases. Palomar may 

supplement deliveries to Northwest Natural and Williams Northwest with imported LNG 

obtained from the proposed Bradwood terminal (discussed below in section 3.2.4.4). The FERC 

authorized the Bradwood project in September 2008; however, there are still several other 

federal and state permits that Bradwood must secure prior to construction. If the Bradwood 

project is built, natural gas from that facility flowing through the Palomar pipeline would have to 

be transported long distance through the existing GTN system to reach markets in northern 

Nevada and northern California in order to compete with the JCE & PCGP Project. It is 

unknown if the GTN system has uncommitted capacity that could handle the additional volumes 

from Bradwood. 

3.2.2.2 Ruby 

The Ruby pipeline project was originally planned to be a joint venture between El Paso 

Corporation, Bear Stearns, and PG&E. Bear Stearns has recently undergone financial problems, 

and in early May 2008 PG&E announced it was pulling out of an agreement to acquire a 25.5 

percent equity interest in the project, citing rising steel prices contributing to higher-thanexpected pipeline costs. However, PG&E will remain as the anchor shipper for the Ruby 

pipeline, contracted for 375,000 Dt/d for 15 years (Magill and Bass 2008; Seay and Magill 

2008). 

Ruby Pipeline LLC (Ruby) filed an application with the FERC on January 27, 2009, in Docket 

No. CP09-54-000. We intend to produce a separate, stand-alone environmental document for the 

Ruby project to comply with the NEPA. 

The 42-inch-diameter Ruby pipeline would extend for about 678 miles from the Opal Hub in 

southwestern Wyoming to the Oregon/California border near Malin, Oregon, where it could 

interconnect with the northern terminus of PG&E’s 400/401 lines, the northern terminus of 

Tuscarora, and the southern terminus of GTN. The project would include a total of about 95,061 

hp of compression, provided by four new compressor stations located in Lincoln County, 

Wyoming, Box Elder County, Utah, and Elko and Humboldt Counties, Nevada. The Ruby 

pipeline would be designed to eventually transport up to 1,500,000 MMBtu per day of natural 
3-17 3.0 – Alternatives 

gas. The purpose of the Ruby project is to deliver Rocky Mountain gas to markets in the Pacific 

Northwest, northern California, and northern Nevada. 

The Ruby project could satisfy most of the main of objectives of the JCE & PCGP Project. Ruby 

would bring additional volumes of natural gas from the Rocky Mountain region to markets in 

northern Nevada and northern California. While Canadian imports are likely to decline in the 

future, natural gas production in the Rocky Mountain region is projected to increase. Producers 

in the Rockies are seeking take away capacity and looking for new customers other than 

Midwestern markets, while West Coast consumers seek additional sources of competitively 

priced natural gas. The only objectives of the JCE & PCGP Project that would not be met by 

Ruby would be the diversification of West Coast gas supplies through the importation of LNG, 

and direct interconnections with Williams Northwest and Avista to serve markets in southern 

Oregon. 

The Ruby pipeline would be significantly longer (almost 678 miles) than the proposed Pacific 

Connector pipeline (234 miles). It stands to reason that a longer pipeline would not have any 

clear environmental advantages. For example, construction of the Pacific Connector pipeline 

would affect about 6,260 acres, while construction of the Ruby pipeline would affect about 

14,010 acres. The Ruby pipeline would cross 1,173 waterbodies, while the Pacific Connector 

pipeline would cross 218 waterbodies. Ruby identified 516 archaeological sites within its 

construction right-of-way APE, while Pacific Connector found a total of 98 sites along its 

pipeline route and at proposed TEWAs and yards. The Ruby project would need 74,441 hp more 

in compression than the Pacific Connector project, which would result in greater air quality and 

noise impacts. For these reasons, we cannot consider the Ruby project to be an environmentally 

preferable alternative to the JCE & PCGP Project. 

3.2.2.3 Bronco 

The Bronco pipeline project is being proposed by Spectra Energy (Spectra). While Spectra has 

not identified a specific route for the pipeline, it would extend almost 700 miles from Opal, 

Wyoming to Malin, Oregon. The purpose of the Bronco Project would be transport Rocky 

Mountain gas to the Pacific Northwest and California markets. The pipeline would have a 

capacity of about 1 Bscfd. 

While the BLM indicated that Spectra has filed a Right-of-Way Grant application to cross 

federal lands, it has not yet requested the initiation of Pre-filing review at the FERC. Spectra has 

not yet announced the results of its open season for the Bronco Pipeline Project, which ended in 

February 2008. A Spectra representative stated that the project “may not work out as we 

originally saw it.” Other industry analysts have indicated that the Bronco Project may be 

canceled because of competition from the Ruby Project and Williams’ Sunstone Project, which 

would serve the same markets, purpose, and need (Inside FERC 2008a). 

The Bronco Project could achieve objectives similar to the JCE & PCGP Project, in providing 

additional volumes of natural gas to northern Nevada and northern California. However, the gas 

from Bronco would come from domestic wells in the Rocky Mountains, while Jordan Cove 

wants to import LNG to diversify West Coast supplies. The Bronco pipeline would have no 

clear environmental advantages over the Pacific Connector pipeline, as it would be substantially 

greater in length. We have no environmental information about the potential impacts the Bronco 
3-18 3.0 – Alternatives 

pipeline may have on specific resources. At this time, even its exact route is uncertain. We 

consider the Bronco Project to be speculative, given its lack of customer support. 

3.2.2.4 Sunstone and Blue Bridge Projects 

In January 2008, Williams, in partnership with TransCanada, sent out a letter to prospective 

customers to determine interest in expanding its existing Williams Northwest pipeline system 

between Wyoming and Oregon. The letter implied that the new project was meant to compete 

with the proposed Ruby project (Williams 2008). In June 2008, Sempra announced it would 

acquire a 25 percent stake in the so-called Sunstone project, together with an undisclosed amount 

of capacity on the pipeline. The pipeline was originally designed to transport about 1.2 Bscfd of 

natural gas (Coos Bay World 2008; Gas Daily 2008). . 

On October 23, 2008, Sunstone Pipeline LLC (Sunstone) filed a request that the FERC initiate a 

Pre-filing review of its project. The project was described as 601 miles of 42-inch-diameter 

pipeline, between Opal, Wyoming and Stanfield, Oregon, and two new compressor stations, 

including 46,820 hp of compression in Lincoln County, Wyoming and 11,200 hp of compression 

in Gooding County, Idaho. The purpose of the project is to provide additional volumes of Rocky 

Mountain natural gas to West Coast markets. 

The FERC agreed to begin the Pre-filing process for Sunstone, in Docket No. PF09-2-000, on 

November 14, 2008. However, shortly thereafter, Sunstone informed the FERC that it was 

suspending environmental studies, and asked staff to stop working on the project, while customer 

support was reassessed. 

In March 2008, Williams and PSE announced their joint plans to develop the so-called Blue 

Bridge project. This would consist of up to about 170 miles of 30- and 36-inch-diameter 

pipeline extending from the terminus of the Sunstone project at Williams Northwest’s existing 

interconnection with GTN at Stanfield, Oregon to Seattle, Washington. The Blue Bridge project 

would also require the addition of compression at Williams Northwest’s existing Plymouth, 

Washougal, and Chehalis compressor stations in Washington. The Blue Bridge project would 

make available up to 500,000 Dth/d of natural gas from Rocky Mountain and WCSB producers 

(Steis 2008). PSE, an LDC serving customers in western Washington, indicated it would be the 

anchor shipper on the pipeline, and may become an equity investor in the project. 

The Sunstone and Blue Bridge projects could achieve some of the main objectives of the JCE & 

PCGP Project. They would provide additional volumes of Canadian and Rockies produced 

natural gas to markets in the Pacific Northwest, northern Nevada, and northern California. 

However, these projects would not meet the objective that Jordan Cove has of diversifying 

regional sources of natural gas through the importation of LNG. 

At this time we have no data about the potential environmental impacts of either the Sunstone or 

Blue Bridge projects. Because the Sunstone pipeline would be substantially longer than the 

Pacific Connector pipeline, it does not appear to be clearly environmentally superior. 

There is some question whether Sunstone has strong enough customer support to go forward. In 

a progress report filed with the FERC on March 3, 2009, Sunstone wrote: “...on November 12, 

2008 field work on the project was temporarily suspended....It is anticipated that environmental 

survey work will resume in June 2009. Until then, pre-filing activities will be limited to 
3-19 3.0 – Alternatives 

evaluating market needs. Sunstone continues to market the project, and is currently evaluating 

the project scope and timing to best meet the needs of our shippers.” On March 16, 2009 Blue 

Bridge filed a letter with the FERC requesting the initiation of our Pre-filing process. 

3.2.3 Existing LNG Facilities 

3.2.3.1 Existing LNG Import Terminals in the United States and Mexico 

There are six existing onshore LNG import terminals in operation in the United States that are 

regulated by the FERC. They are located in Everett, Massachusetts; Cove Point, Maryland; 

Elba, Georgia; Lake Charles and Sabine, Louisiana; and Freeport, Texas. There are two 

operating offshore LNG import facilities in the waters off the United States: one in the Gulf of 

Mexico and the other in Massachusetts Bay; both buoy-based receiving facilities owned by 

Excelerate Energy, that come under the jurisdiction of the Coast Guard and U.S. Department of 

Transportation, Maritime Administration (MARAD) according to the Deepwater Port Act. 

There are three other FERC-authorized onshore LNG import terminals currently under 

construction along the Gulf of Mexico (at Hackberry, Louisiana; Pascagoula, Mississippi; and 

Sabine, Texas) and one offshore LNG import terminal under jurisdiction of the Coast Guard and 

MARAD under construction in Massachusetts Bay. In addition, the FERC has authorized 11 

other onshore LNG import terminals in the United States (at Bradwood, Oregon; Fall River, 

Massachusetts; Long Island Sound, New York; Logan Township, New Jersey; Cameron, 

Louisiana; Pascagoula, Mississippi; Port Lavaca, Texas; Port Arthur, Texas; and three in Corpus 

Christi, Texas) that have not yet been built. None of the operating, under-construction, or 

authorized but un-built LNG import terminals on the Gulf or East Coasts would be a reasonable 

or feasible system alternative to the proposed project because of their distance from the proposed 

market area for the JCE & PCGP Project. 

As previously mentioned, there is an LNG terminal that was recently completed by Sempra on 

the Pacific Coast in Baja, Mexico. The Costa Azul terminal is sited within a 400-acre parcel, 

about 15 miles north of Ensenada, with two full containment LNG storage tanks with a total 

capacity of 320,000 m3, open rack vaporizers (ORV), and a 42-mile-long, 36-inch-diameter 

pipeline with an average sendout capacity of 1.0 Bscfd. Half of the processing capacity is leased 

to Shell. In April, 2008, Costa Azul received its first shipment of LNG from Qatar to test the 

LNG terminal. Sempra signed a 20 year agreement to receive future shipments from Indonesia. 

However, Sempra indicated to the industry press late in 2008 that while the Costa Azul LNG 

import terminal was now on-line, it did not expect active shipments of LNG to begin coming to 

the terminal until the end of 2009 (Nemic 2008). 

In October 2007, in Docket No. CP06-61-000, the FERC authorized the expansion of the North 

Baja Pipeline between an interconnection with the El Paso pipeline system at Ehrenberg, Arizona 

and the Mexican border near Yuma, Arizona where it interconnects with the Gasoducto 

Bajanorte pipeline. The Gasoducto Bajanorte pipeline terminates at Costa Azul, while the El 

Paso pipeline system extends to southern California near Blythe where it interconnects with the 

Southern California Gas Company (SoCal Gas) intrastate pipeline network. The purpose of the 

North Baja pipeline expansion is to bring new supplies of natural gas, from LNG imported to 

Costa Azul, to markets in southern California. In addition, the proposed Transportadora De Gas 

Natural De Baja California pipeline would transport natural gas from Costa Azul to southern 

California via an interconnection with the existing intrastate pipeline system of the San Diego 

Gas and Electric Company (SDG&E) (CEC 2007a). 
3-20 3.0 – Alternatives 

The CEC estimates that up to 50 percent of the capacity of the Costa Azul LNG terminal would 

be contracted for use in Mexico, with the remainder available for southern California markets. 

Natural gas from Costa Azul would be conveyed into southern California via the existing 

intrastate pipeline systems of SoCal Gas and SDG&E, both subsidiaries of Sempra, the owner of 

Costa Azul. The California Public Utilities Commission has divided the state so that SoCal Gas 

and SDG&E are LDCs that serve southern California, while PG&E serves northern California. It 

is unlikely that substantial volumes of gas intended for SoCal Gas and SDGC would find its way 

to the northern California distribution system of PG&E. 

3.2.3.2 Existing LNG Storage Facilities in the Pacific Northwest and Nevada 

Five LNG storage facilities currently exist in the Pacific Northwest. These are peak shaving 

plants that liquefy natural gas, store it as LNG, and then vaporize the LNG back into natural gas 

for use during periods of peak demand. These facilities do not add new supplies of natural gas to 

the region, but rather act as storage facilities, using existing supplies, to even out the 

discrepancies created by varying seasonal demands. 

Pauite operates a peak shaving plant in Lovelock, Nevada. There are no LNG peak shaving 

plants in California. 

In Oregon, Northwest Natural owns and operates two peak shaving LNG storage plants. One is 

located in Portland, and has a 28,000 m3 tank with a storage capacity of 600 Mscfd. The other is 

located in Newport and has a 48,000 m3 tank and a storage capacity of 1.0 Bscfd. In 

Washington, Williams Northwest owns and operates a peak shaving LNG storage plant in 

Plymouth with a liquefaction capacity of 19.7 Mscfd, a storage capacity of 60,000 m3, and a 

vaporization capacity of 300 Mscfd. In Gig Harbor, Washington, PSE operates a small LNG 

peak shaving plant with a capacity of 31 million Dth, and a maximum withdrawal rate of 3 

million Dth a day. In Nampa, Idaho, Intermountain Gas operates an LNG peak shaving plant 

with a capacity of 588 million Dth and a maximum withdrawal of 60 million Dth/d (NWGA 

2007). 

We considered the possibility of converting one of the existing peak shaving LNG storage plants 

into an LNG import terminal as a system alternative to the proposed Project. Such a conversion 

would not make sense at land-locked peak shaving plants, such as at Nampa, Idaho, and 

Lovelock, Nevada, which cannot receive LNG carriers. While several other existing peak 

shaving plants are located along waterbodies, they could not presently handle deep draft LNG 

carriers. Plymouth is located on the Columbia River, but is upriver of several dams, and so it 

would not be accessible to LNG carriers. Although Gig Harbor is located on Puget Sound, the 

PSE peak shaving facility is located about 1 mile from the harbor and would not be accessible to 

LNG carriers. While it may be feasible to construct a pipeline to transmit LNG from the harbor 

to the PSE peak shaving facility, such a pipeline would have additional associated environmental 

impacts. The Portland facility is located on the Willamette River and would potentially be 

accessible to LNG carriers. However, the waterway for LNG marine transit would be over 100 

miles long and the navigation channel is obstructed by a bridge at Ross Island that only has 

clearances of 120 feet high and 100 feet wide. Newport is on the Oregon coast; however, the 

port of Newport is relatively small, with channel depths ranging from 20 to 30 feet. The port at 

Newport could not accommodate LNG carriers without extensive dredging. Therefore, we 

conclude that converting existing peak shaving LNG storage plants in the region into LNG 

import terminals is not a reasonable or feasible system alternative to the proposed Project. 
3-21 3.0 – Alternatives 

3.2.4 Proposed West Coast Alternative LNG Import Terminals 

We assessed existing proposals for offshore and onshore LNG import terminals on the Pacific 

Coast of North America, including facilities proposed on the west coast of Mexico, Canada, and 

the United States. 

3.2.4.1 Proposed LNG Import Terminals on the West Coast of Mexico 

The proposed LNG import terminals on the West Coast of Mexico include two offshore facilities 

(Terminal GNL Mar Adentro de Baja California and Moss-Maritime LNG Project) and one 

onshore facilities (Terminal GNL de Sonora). The Terminal GNL Mar Adentro de Baja 

California, proposed by Chevron Corporation (Chevron), would have been a gravity-based 

structure (GBS) (see section 3.3.4) located near the Coronado Islands off the coast of Tijuana 

with a projected average sendout capacity of 700 Mscfd. In March 2007, Chevron announced it 

was dropping its plans to develop its proposed Baja, Mexico LNG import terminal (East Bay 

Business Times 2007). 

The Moss-Maritime LNG Project, proposed by a partnership between Moss-Maritime and 

Terminales y Almacenes Maritimos de Mexico, would be a floating storage and regasification 

unit (FSRU) (see section 3.3.4). The terminal would be located about 5 miles from Rosarito 

Beach off the coast of Baja, Mexico and have an average sendout capacity of 297 Mscfd. This 

facility was granted a permit from the Mexican government, but its current status is unknown 

(Lindquist 2007). 

The Terminal GNL de Sonora would be an LNG import terminal located near Puerto Libertad, 

Sonora, on the eastern shore of the Gulf of California (Sea of Cortez), with a sendout capacity of 

1.3 Bscfd, proposed by El Paso and DKRW Energy LLC. The partners have received some 

environmental permits from the Mexican Federal Ministry of the Environment and Natural 

Resources. Gas supply for this facility still needs to be secured, and in May 2006 El Paso 

announced it was halting plans for a 59-mile-long sendout pipeline that would link the proposed 

terminal to markets in Tucson (CEC 2009). 

Costa Azul is the only LNG import terminal that has been authorized and built on the West Coast 

of Mexico. All the other Mexican LNG proposals are considered to be speculative at this time. 

The target markets for the Mexican LNG import terminals would be northern Mexico, southern 

California, and other states in the southwestern United States (Arizona and Texas). The 

proposed LNG import terminals in northern Mexico would be far from the market areas of 

northern California, northern Nevada, and the Pacific Northwest proposed to be served by the 

JCE & PCGP Project. These terminals could not meet the Project objectives without 

substantially increasing their proposed capacity and constructing over 1,000 miles of new 

pipeline with compressor stations. Therefore, we do not consider the proposed Mexican LNG 

terminals to be reasonable or feasible alternatives to the proposed Project and did not evaluate 

them further. 

3.2.4.2 Proposed LNG Import Terminals on the West Coast of Canada 

One proposed onshore LNG import facility (WestPac) in British Columbia, Canada, has not yet 

begun the environmental review process for its revised project. The other LNG terminal 

(Kitimat) in British Columbia has been converted into an export facility. 
3-22 3.0 – Alternatives 

WestPac LNG Terminal, British Columbia 

WestPac LNG Corporation proposes to construct and operate an LNG import terminal near 

Kiddie Point on Texada Island, about 75 miles northwest of Vancouver in the Straights of 

Georgia, British Columbia, Canada. Originally, WestPac started the environmental review 

process with the Prince Rupert Port Authority in 2006 for an LNG terminal site on Ridley Island 

(CEC 2009). The proposed location of the LNG terminal was moved to Texada Island in July 

2007. The terminal would include a marine jetty capable of handling about 36 LNG carriers a 

year, with capacities up to 165,000 m3. Onshore, there would be two full-containment LNG 

storage tanks, re-gasification facilities, and an electric generation plant. While WestPac indicated 

it would have access to the Vancouver Island gas pipeline, it did not reveal any details about its 

sendout pipeline. Instead, WestPac indicated that it would provide a detailed project description 

with the application it intends to file with the British Columbia and Canadian Environmental 

Assessment Offices (EAO) early in 2009 (WestPac 2008). In January 2008, the sponsors put the 

project on hold pending review of initiatives that may be taken by the provincial government of 

British Columbia related to emission or climate change regulations (Gas Daily 2008). 

The WestPac LNG facility may be an alternative to the proposed JCE & PCGP Project, if the 

project were to include pipeline connections to the existing grid enabling the transportation of 

natural gas to markets in the Western United States. However, at the present time it is unclear 

what the target markets may be for this project, and how gas would be transported from the LNG 

terminal to end users. In addition, environmental review of the proposal would not resume until 

2009, and there is uncertainty over whether or not the appropriate Canadian government 

authorities would approve the project. Therefore, we do not consider the WestPac LNG terminal 

to be a feasible alternative to the JCE & PCGP Project. 

Kitimat LNG Terminal, British Columbia 

The Kitimat LNG terminal, proposed by a subsidiary of Galveston LNG, Inc., would be located 

at Bish Cove, about 8 miles southwest of the Port of Kitimat, British Columbia. The project was 

originally proposed in 2004 as an import facility. An environmental assessment was completed 

for the Kitimat LNG import terminal, and the project was approved by the Canadian 

Environmental Ministry in August 2006. 

In September 2008, Kitimat announced plans to totally redesign the terminal as an export 

facility, because of rising demand for natural gas in Asia, and increasing natural gas production 

in North America (Fisher 2008). The export terminal would include liquefaction equipment, and 

two full containment LNG storage tanks, each with a capacity to hold 210,000 m3 (8.9 Bcf). The 

terminal would load four to five LNG carriers per month, with deliveries targeted to Asian 

nations with little natural gas reserves, including Japan, Korea, and China. The export terminal 

would receive natural gas through a 9-mile-long lateral pipeline from the new 292-mile-long 

Pacific Trails Pipeline, which in turn would connect to the existing Spectra Energy system near 

Summit Lake, British Columbia (Kitimat LNG webpage). Pacific Trails Pipeline, to be operated 

by a partnership between Galveston LNG Inc. and Pacific Northern Gas Ltd., filed a formal 

environmental application with the British Columbia EAO in August 2007 (CEC 2009). 

Although Kitimat would like the terminal to be in operation by 2013, the company admitted it 

would not be applying for an export license from the Canadian National Energy Board for 

several years. In the meantime, Kitimat did receive environmental approvals from the Canadian 

federal government in December 2008, and from the British Columbia provincial government in 
3-23 3.0 – Alternatives 

January 2009. Also in January 2009, it was announced that Mitsubishi Corporation acquired 

capacity and an equity stake in the Kitimat export terminal. 

The Kitimat LNG export terminal would not be a reasonable alternative to the JCE & PCGP 

Project. In fact, in its current reincarnation, Kitimat’s goals are the opposite of the objectives 

stated by Jordan Cove. While Kitimat wishes to export LNG created from British Columbia 

natural gas to Asian markets, Jordan Cove seeks to import LNG from Pacific Basin producing 

nations to provide a new source of natural gas to markets in the Pacific Northwest, northern 

Nevada, and northern California. 

3.2.4.3 Proposed LNG Import Terminals in California 

There is one proposed onshore LNG import terminal, at Long Beach, and multiple proposals for 

terminals off the Pacific Coast in California. While the onshore terminal comes under the 

jurisdiction of the FERC, the offshore proposals are being reviewed by the Coast Guard and 

MARAD under the authority of the Deepwater Port Act. 

Long Beach LNG Import Terminal Project 

The Long Beach LNG Import Terminal Project was proposed by Sound Energy Solutions (SES), 

a joint venture between Mitsubishi Corporation and ConocoPhillips, in FERC Docket Nos. 

CP04-58-000 et al., to be located within the Port of Long Beach, California. Features of the 

terminal include an LNG carrier berth capable of handling an LNG carrier up to about 200,000 

m3

 capacity in size, two LNG storage tanks with a combined capacity of 320,000 m3, four shell 

and tube vaporizers (STV), and a typical sendout capacity of 700 Mscfd of natural gas. A 2.3-

mile-long 36-inch-diameter pipeline would be constructed to transport natural gas from the LNG 

terminal to existing SoCal Gas facilities. In addition, a 4.6-mile-long 10-inch-diameter pipeline 

would be constructed to transport vaporized ethane from the LNG terminal to an existing Conoco 

Phillips plant. 

In October 2005, the FERC and Port of Long Beach produced a joint draft EIS for this project. 

In January 2007, the Long Beach Board of Harbor Commissioners, who would be responsible for 

leasing the property for the LNG terminal, decided to end its environmental review (Polakovic 

2007). In March 2008, the FERC issued a letter to SES stating that staff would no longer work 

on its application for an LNG import terminal at Long Beach, because the company could not 

document that it had access to or control over its proposed terminal site. SES appealed the City 

of Long Beach’s decision through the local judicial system, but a Superior Court judge ruled, in 

March 2008, against SES, finding that Long Beach had acted in an appropriate manner in halting 

its environment review process. In June 2008, SES withdrew its proposal (CEC 2009). 

Cabrillo Deepwater Port LNG Facility 

The Cabrillo Deepwater Port LNG facility, proposed by BHP Billiton, would be located in the 

Santa Barbara Channel about 14 miles from Point Mugu. The import facility would consist of an 

FSRU permanently moored to the ocean floor, with three independent Moss spherical storage 

tanks mounted within the hull together with eight vaporizers. An underwater 30-inch-diameter 

pipeline would extend about 21 miles, coming ashore in the vicinity of Ormond Beach in 

Ventura County, California, and interconnecting with the existing SoCal Gas system. The 

facility would have the ability to send out an average of about 800 Mscfd of natural gas. 
3-24 3.0 – Alternatives 

BHP Billiton filed an application with MARAD on September 3, 2003, that was deemed 

complete on January 27, 2004. The Coast Guard and California State Lands Commission (CLC) 

issued a final EIS for this project in March 2007. In April 2007, the CLC and the California 

Coastal Commission voted against authorizing the Cabrillo Deepwater Port LNG facility. The 

governor of California rejected BHP Billiton’s proposal in May 2007. Consequently, on June 5, 

2007, the MARAD issued an ROD denying the application for the Cabrillo Port (MARAD 

2007). 

Clearwater Port LNG Project 

The Clearwater Port LNG Project was proposed by NorthernStar Natural Gas, Inc., the same 

developers promoting the Bradwood Project in Oregon. The Clearwater Port Project would use 

existing offshore Platform Grace, located in the Santa Barbara Channel about 13 miles from 

Oxnard. A new floating dock would need to be installed adjacent to the existing platform to 

moor LNG carriers during transfer. No storage facilities are proposed. The platform would be 

reconfigured to accommodate vaporizers. The natural gas would be delivered from the platform 

to the shore via a new 32-inch-diameter, 13-mile-long subsea pipeline. An additional 12-milelong underground pipeline would convey the gas onshore from Oxnard to an interconnection 

with the existing SoCal system near Camarillo. The average sendout capacity of the facility 

would be about 1.2 Bscfd. 

Clearwater Port filed an application with MARAD on January 28, 2004. On August 23, 2007, 

the application was deemed complete, and on September 18, 2007, MARAD issued a notice of 

intent to produce a draft EIS for the project. On October 23, 2007, the Coast Guard issued a 

“stop the clock” letter to the applicant with a list of 396 questions. 

Ocean Way LNG Terminal 

The Ocean Way LNG terminal, to be located in the Pacific Ocean about 22 miles south of Los 

Angeles, California, was proposed by Woodside Energy, Inc. (Woodside). The project would 

include a mooring facility and an underwater pipeline that would come onshore near Los 

Angeles International Airport and interconnect with the existing SoCal Gas intrastate local 

distribution system. The LNG would be regasified while still on board the ship, and the facility 

would have a first phase nominal sendout capacity of about 400 Mscfd. 

Woodside filed its application with MARAD on August 18, 2006. In September 2007 the 

application was deemed complete, and a notice of intent to prepare a draft EIS was issued. The 

Coast Guard stopped the clock on this project on November 23, 2007, issuing a letter to Woodside 

with a list of 61 questions (CEC 2009). In January 2009, Woodside withdrew its application for the 

Ocean Way LNG import terminal, citing changing market conditions. 

Pacific Gateway LNG Facility 

The Pacific Gateway LNG facility is proposed by Excelerate Energy, LLC (Excelerate) to be 

located off the shore of northern California. Excelerate, which currently operates an offshore 

LNG import terminal in the Gulf of Mexico, would use specially designed LNG tankers for the 

transportation of LNG and vaporization into natural gas. The northern California proposal would 

deliver up to 1.0 Bscfd of natural gas. This project is currently in the conceptual design phase, 

with Excelerate conducting “fatal flaw” analyses of offshore terminal locations and pipeline 
3-25 3.0 – Alternatives 

routes (Excelerate 2007). An application under the Deepwater Port Act has not yet been 

submitted for this project. 

Esperanza LNG Terminal 

In March 2007, Esperanza Energy, LLC (Esperanza), a subsidiary of Tidelands Oil and Gas 

Corporation, announced plans for an offshore LNG import terminal to be located in the Pacific 

Ocean about 15 miles from Long Beach, California. This facility would use the proprietary 

HiLoad system developed by TORP Technology to vaporize LNG as it is offloaded from ships. 

The natural gas would be transported to shore by an undersea pipeline, with a sendout capacity 

of about 1.2 Bscfd. One unique feature of this proposal would be the use of warm water 

discharged from an onshore host to regasify the LNG (Esperanza 2007; Nemec 2007). 

Esperanza has not yet filed its application under the Deepwater Port Act. An application is 

expected to be filed by Esperanza by the end of 2009 (CEC 2009). 

Conclusions About the Proposed California LNG Import Terminals 

None of the proposed LNG import terminals in California is viewed as reasonable or feasible 

alternatives to the JCE & PCGP Project. None of these proposals have been authorized at this 

time. The Long Beach onshore terminal proposal and the Ocean Way offshore terminal proposal 

have been withdrawn by their sponsors. One of the offshore terminal applications (Cabrillo Port) 

has been denied. Others (Pacific Gateway and Esperanza) are in the speculation stage, with no 

applications yet submitted. In addition, the target markets for most of these projects are in 

southern California. If any of these projects were authorized and constructed, a multiple hundred 

mile long pipeline would be necessary to reach markets in northern California, northern Nevada, 

and southern Oregon. The California LNG import terminal proposals, therefore, could not easily 

meet some the main objectives of the JCE & PCGP Project, and may have environmental 

impacts greater than the JCE & PCGP Project. 

3.2.4.4 Other Proposed LNG Import Terminals in Oregon 

In addition to the JCE & PCGP Project, there are two other LNG import terminals that have been 

proposed in Oregon. As discussed below, both the Bradwood LNG Project and the Oregon LNG 

Project are considered feasible alternatives to the JCE & PCGP Project. It appears that these 

alternatives could meet most, but not all, of the stated objectives of the JCE & PCGP Project. If 

the FERC finds that these projects are environmentally acceptable, the Commission could 

approve none, all, or some of them, and allow the market to decide which LNG terminals and 

associated pipelines ultimately get built. 

Bradwood Landing LNG Project 

In June 2006, Bradwood Landing LLC and NorthernStar Energy LLC (together referred to as 

NorthernStar) filed their applications with the FERC, in Dockets CP06-365-000 and CP06-366-

000, for a proposed LNG import terminal in Clatsop County, Oregon, and an associated sendout 

pipeline located in Clatsop and Columbia Counties, Oregon and Cowlitz County, Washington. 

The Bradwood LNG import terminal would be located at Columbia River Mile 38 and its 

operational footprint would cover about 40 acres onshore. Dredging would be necessary within 

a 58-acre area in the Columbia River to create a ship maneuvering basin. NorthernStar 

anticipates about 125 LNG carriers coming to call at the terminal each year. The LNG terminal 
3-26 3.0 – Alternatives 

facilities would include a single ship berth, two 160,000 m3

 LNG storage tanks, and SCV 

vaporizers. 

The project also includes a 36.3-mile sendout pipeline that would connect the LNG terminal to 

the existing Williams Northwest system north of Kelso, Washington. The pipeline would follow 

an existing right-of-way for about 22 percent of its route. There are three residences identified 

within 50 feet of the construction right-of-way along the proposed pipeline route. 

The closest residences to the proposed Bradwood LNG terminal are about 0.6 mile away, on 

Puget Island. However, LNG marine traffic in the Columbia River waterway to the terminal 

would pass by the communities of Warrenton and Astoria, Oregon, and Skamokawa and 

Cathlamet, Washington. The Coast Guard issued a WSR, on February 28, 2007, indicating that 

the waterway may be suitable for LNG marine traffic if certain conditions are met. Those 

conditions include the enforcement of safety and security zones around LNG carriers, and the 

restriction of meeting places for other commercial river traffic. 

The proposed Bradwood project would be located in a high seismic hazard area, and the facilities 

may be susceptible to soil liquefaction and landslides. Approximately 700,000 cy of sediment 

would be dredged to create the proposed ship maneuvering area in the Columbia River. The 

project would temporarily affect about 113 acres of wetland during construction, and have 

permanent impacts on about 19 acres of wetlands during operation. The pipeline would cross 94 

waterbodies, of which 19 are proposed to be crossed using HDDs, including the Columbia River 

and Cowlitz River. About 211 acres of forest would need to be cleared for construction of the 

Bradwood Project. 

The Bradwood project may affect EFH for 90 species of groundfish, 5 coastal pelagic species, 

and 13 migratory species. The project may also affect federally listed threatened or endangered 

species. There are 14 ecologically significant units (ESUs) of salmonid species (5 Chinook 

salmon ESUs, 1 chum salmon ESU, 1 coho salmon ESU, 1 sockeye salmon ESU 5 steelhead 

ESUs, and 1 char ESU [bull trout]); 4 species of sea turtles; 8 marine mammal species; 1 deer 

species; 5 bird species; 1 butterfly; and 3 plant species. The FERC submitted a BA/EFH 

Assessment to the FWS and NMFS in March 2007. NorthernStar submitted a revised draft BA 

and a Compensatory Mitigation Plan to the FERC on June 4, 2008. The FERC is currently 

preparing a revised BA/EHF Assessment for submittal to the FWS and NMFS, to address the 

Services’ comments on the March 2007 version. 

The FERC issued a final EIS for the Bradwood project in June 2008. The Commission issued an 

Order authorizing the project on September 18, 2008. After considering requests for rehearing, 

the Commission issued an Order on Rehearing on January 15, 2009. Some intervening parties 

have appealed the Order on Rehearing to the 9th Circuit Court. 

The main environmental advantages of the Bradwood project in comparison to the JCE & PCGP 

Project would be the shorter distance of its sendout pipeline. Some disadvantages would be the 

longer LNG carrier voyage up the Columbia River waterway past several communities, and 

potential impacts on federally listed threatened and endangered species, including 13 salmonid 

ESUs. 

The purpose of the Bradwood project is to provide up to 1.3 Bscfd of natural gas to markets in 

the Pacific Northwest through new sources of imported LNG. Therefore, the Bradwood project 
3-27 3.0 – Alternatives 

could be a reasonable alternative to the proposed JCE & PCGP Project. However, it is unclear if 

the Bradwood project could meet all of the objectives of the JCE & PCGP Project. NorthernStar 

did not propose to serve customers in southern Oregon through direct interconnections with the 

Williams Northwest Grants Pass Lateral or with the Avista LDC system. Also, if natural gas 

were to be provided by the Bradwood LNG import terminal to markets in northern Nevada or 

northern California, it would have to be transported longer distances through the existing GTN 

system than the Pacific Connector pipeline. 

Oregon LNG Project 

On June 10, 2007, the FERC agreed to the request from LNG Development Company LLC and 

the Oregon Pipeline Company (hereafter referred to together as Oregon LNG) to initiate the Prefiling environmental review of their proposed Oregon LNG Project, in Docket No. PF07-10-000, 

with an LNG import terminal in Warrenton, Clatsop County, Oregon, and an associated 121-

mile-long sendout pipeline crossing Clatsop, Tillamook, Washington, Yamhill, Marion, and 

Clackamas Counties, Oregon. The development of an LNG import terminal at Warrenton was 

originally proposed by Calpine Corporation (Calpine). However, after Calpine declared 

bankruptcy, rights to the project were transferred to Oregon LNG, a subsidiary of the Leucadia 

National Corporation. 

On October 10, 2008, Oregon LNG filed an application with the FERC under Docket No. CP09-

6-000. The FERC intends to produce a separate, stand-alone EIS for the Oregon LNG project. 

Oregon LNG proposes to construct and operate and LNG import terminal within a 96-acre tract 

on the East Skipanon Peninsula, near the confluence of the Skipanon and Columbia Rivers, at 

about Columbia River Mile 11.5. The portion of the East Skipanon Peninsula containing the 

site for Oregon LNG terminal is owned by the State of Oregon, and leased by the ODSL to the 

Port of Astoria. Oregon LNG holds a 65-year sublease with the Port of Astoria for the parcel. 

The Skipanon Peninsula was created by placement of sandy sediments dredged from adjacent 

waterways beginning in the 1920s. The surrounding land use is industrial and recreational. An 

18-hole golf course was planned for this area (Port of Astoria 2006). The City of Warrenton 

recently rezoned the area for water-dependent industrial use in order to allow for an LNG 

terminal at this location (Ramsayer 2005). The onshore portions of the parcel are zoned Water 

Dependent Industrial Shorelands 1-2, while the marine facilities are zoned Aquatic Development 

A-1. 

The proposed Oregon LNG import terminal would be located downstream of the Astoria-Megler 

Bridge. It would have a single berth designed to handle about 100 LNG carriers per year, sized 

from 70,000 m3

 to 266,000 m3 in capacity. The berth would be located offshore in Young’s Bay, 

adjacent to the Columbia River navigation channel, on submerged lands owned in fee by the 

ODSL, with current depths between 20 and 30 feet below mean lower low water. Oregon LNG 

expects that construction of its turning basin would require dredging of about 1.2 mcy of material 

within a 135-acre area to reach depths of about 45 feet required for the safe docking of LNG 

carriers. About 200,000 cy of dredged material would be deposited at the south end of the 

onshore terminal parcel to raise the elevation of the process area. For the remainder of the 

dredged materials, Oregon LNG indicated that its preferred alternatives included placement at 

Three Tree Point (Columbia River Mile 30.2) and Price Island (Columbia River Mile 34.8). 
3-28 3.0 – Alternatives 

Oregon LNG believes that its dock would qualify for the “wharf exception” under ORS 

780.040(1), which would not require a lease from ODSL. The unloading platform at the berth 

would include three unloading arms and one vapor return arm. A transfer pipeline would 

connect the unloading arms on the dock to the LNG storage tanks. Construction of the marine 

facilities, including the dock and turning basin, would affect about 148 acres. 

Onshore facilities would include three 160,000 m3 full containment LNG storage tanks, 

vaporizers, and a sendout system with a peak capacity of 1.5 Bscfd of natural gas. Oregon LNG 

currently plans on using a combination of direct ambient air vaporizes and natural gas-fired 

heaters to re-gasify the LNG. 

Oregon LNG would install a new 36-inch-diameter 121-mile-long natural gas sendout pipeline to 

connect the LNG import terminal with the existing Williams Northwest system near Molalla, 

Oregon. About 30 percent of this pipeline route would follow existing rights-of-way, for roads, 

railroads, and powerlines. Construction of the sendout pipeline would affect about 1,634 acres. 

In addition, Oregon LNG would install a 9.5-mile-long 24-inch-diameter lateral, in Washington 

County, Oregon, that would connect to existing Northwest Natural LDC system facilities. The 

lateral’s maximum capacity would be 0.8 Bscfd. Aboveground facilities associated with the 

sendout pipeline would include a single electric-drive gas compressor station, located about MP 

52, where the Northwest Natural lateral would split off from the mainline. Oregon LNG 

indicated that it would be willing to transport its gas on the proposed Palomar pipeline, instead of 

building its own sendout pipeline, if the parties could reach a mutual agreement. 

National Wetlands Inventory (NWI) data indicate approximately 70 acres of wetlands are present 

within the 96-acre site proposed for the LNG terminal. Oregon LNG estimates that construction 

of the upland portion of the terminal would permanently affect about 19.1 acres of estuarine and 

4.1 acres of palustrine wetlands. The main pipeline would cross 268 waterbodies, and the lateral 

would cross 23 waterbodies. 

Federally listed threatened and endangered species within the waterway to the proposed LNG 

terminal include four species of sea turtles, eight marine mammals, and two birds. At the LNG 

terminal, including the marine berth and turning basin within the lower Columbia River estuary, 

Oregon LNG identified potential habitat for eight ESUs for Pacific salmon, five DPSs of 

steelhead trout, plus the green sturgeon. Along the pipeline route there is habitat for four salmon 

ESUs, two steelhead DPSs, two plants, one invertebrate, and two birds. 

The closest residences are about 0.5 mile from the southern boundary of the Oregon LNG 

terminal site. The facility would be visible from the hillside of the western portion of the City of 

Astoria and from the City of Warrenton. Oregon LNG indicated that there are 12 residential 

structures located in close proximity to its proposed sendout pipeline. 

The proposed pipeline and lateral would cross a total of about 68 miles of non-wetland forest, 

including portions of the Clatsop and Tillamook State Forests. About 45 miles of non-wetland 

agricultural land would be crossed by the pipeline, including some vineyards in the Willamette 

Valley. 

No archaeological sites were identified at the proposed Oregon LNG terminal, mainly because 

the terrestrial portion of this facility would be located on fill. Nine archaeological sites were 
3-29 3.0 – Alternatives 

found along surveyed portions of the pipeline route; of which eight require additional 

investigations to assess their NRHP eligibility. 

In summary, the main environmental advantage of the Oregon LNG project would be the shorter 

distance of the sendout pipe in comparison to the Pacific Connector pipeline. Environmental 

challenges for the Oregon LNG project include potential effects on numerous species of 

federally listed threatened and endangered fish, and the potential impacts of the sendout pipeline 

on agricultural land (including vineyards) in the Willamette Valley. 

The Oregon LNG project can be considered a viable alternative to the JCE & PCGP Project, in 

that it would import LNG to diversify natural gas supplies available in the Pacific Northwest. 

However, the sendout pipeline for the Oregon LNG terminal would interconnect with the 

existing Williams Northwest system at Mollala, to directly serve customers in the Portland 

metropolitan area and the Willamette Valley. The Oregon LNG project may not meet all of the 

objectives of the JCE & PCGP Project, in that it does not propose interconnections to the 

Williams Northwest Grants Pass Lateral and Avista to provide direct service to southern Oregon. 

Natural gas would have to transported a longer distance from the Oregon LNG terminal to reach 

markets in northern Nevada and California in comparison to the Pacific Connector pipeline from 

the Jordan Cove terminal. 

3.3 REGIONAL REVIEW OF ALTERNATIVE ONSHORE LNG IMPORT 

TERMINAL PORTS 

The project proponent selects the location of its facilities. The FERC then conducts an 

environmental review of that location, and compares the proposed facilities against other 

identified feasible and reasonable alternatives to determine if any alternative may be 

environmentally preferable. Below is a discussion of how Jordan Cove selected its proposed 

location for an LNG import terminal at Coos Bay. After reviewing these data, the FERC was 

unable to identify any other alternative locations for an LNG terminal in the region that could 

serve the same target markets, and would be environmentally superior. 

A number of factors were used by Jordan Cove to screen potential ports for its proposed LNG 

import terminal within a regional context. Jordan Cove based its regional site selection process 

on the growing demand for natural gas in the Pacific Northwest, northern Nevada, and northern 

California (see section 1.1 of this EIS), and the fact that this area is currently underserved in 

terms of existing LNG import terminals and access to additional North American natural gas 

supply. Potential sites along the West Coast of Canada, Mexico, and southern California were 

not considered by Jordan Cove because of their distance away from the selected target markets, 

and constraints on existing pipeline infrastructure. 

Jordan Cove and Pacific Connector set the boundaries of their target markets around the main 

metropolitan areas within the region they seek to serve: Boise, Idaho; Spokane, Washington; 

Seattle, Washington; Portland, Oregon; Reno, Nevada; and Sacramento, California. Sacramento, 

rather than San Francisco, was identified as the southernmost market center because it has a 

higher projected growth rate in the future. 

Jordan Cove then identified ports within its study area that could handle LNG carriers. It 

examined 7 ports in California, 12 in Oregon, and 22 in Washington, with Stockton, California 
3-30 3.0 – Alternatives 

being the southern most port and Bellingham, Washington the northernmost port (figure 3.3-1). 

Those ports that have a channel depth of 36 feet MLLW are listed on table 3.3-1. 

TABLE 3.3-1 

Ports Potentially Suitable for LNG Carrier Traffic Within Jordan Cove’s Project Study Area Based on 

Channel Depth of 36 Feet MLLW a/

Washington Ports Oregon Ports California Ports 

Port Angeles Portland Humboldt 

Port Townsend St. Helens 

Gray’s Harbor/Aberdeen Port Westward 

Skamokawa Wauna/Bradwood Landing 

Longview Astoria/Warrenton 

Kalama Coos Bay 

Vancouver 

a/ Depth of maintained federal navigation channel. 

Using the list of potentially suitable ports that met minimum channel depth requirements, Jordan 

Cove then applied other suitability criteria to further narrow the list of potential ports: 

• transit navigation restrictions; 

• population density near site; 

• population density along waterway to terminal, and transit distance; 

• compatibility with existing port users; 

• impacts on other waterway users, including commercial fishing and recreational boating; 

• land use zoning; 

• land availability and ownership; and 

• environmentally sensitive areas. 

Even if the navigation channel is deep enough to handle LNG carriers, there may be other 

obstructions along the channel that may prohibit LNG carrier transit. A typical LNG carrier 

requires a vertical air draft of 135 feet high, and horizontal clearance of at least 185 feet wide. 

There may be bridges or powerlines across the channel that would be less than those clearances. 

In addition, Jordan Cove considered other navigational obstacles, such as shoaling and swift 

currents, and existing restrictions that may prohibit transit by LNG carriers. Jordan Cove was 

also concerned about high levels of vessel traffic in the navigation channel, conflicts with other 

existing berths, and other users of the waterway, including commercial fishing and recreational 

boating. Lastly, Jordan Cove preferred that its LNG import terminal not be located in proximity 

to densely populated, urban areas. 
3-31 3.0 – Alternatives 

Figure 3.3-1. Potential Ports for an LNG Import Terminal 
3-32 3.0 – Alternatives 

Jordan Cove ruled out potential ports in northern California because they either did not have 

deep enough navigation channels, had obstructions to LNG carrier transit, or had high population 

densities. The San Francisco Bay area is heavily populated. The navigation channel from San 

Francisco to either Stockton or Sacramento is about 75 nautical miles long. The channel to 

Stockton is 35 feet deep at MLLW. The channel to Sacramento is only 30 feet deep. At least a 

36 foot deep channel would be necessary to handle LNG carriers. Bodega Bay, Tomales Bay, 

and Crescent City Harbor are also not deep enough to accommodate LNG carriers. Humboldt 

Bay is deep enough, but the navigation channel is obstructed by a fixed highway bridge. 

The ports at Cherry Point, Port Angeles, Port Townsend, Gray’s Harbor, Skamokawa, Longview, 

Kalama, and Vancouver, Washington all have navigation channels deep enough to handle LNG 

carriers. However, these ports have the disadvantage of greater distance away from target 

markets in northern Nevada and northern California. In addition, there are injunctive exclusions 

to LNG tankers at Cherry Point and Port Townsend. At Gray’s Harbor, there is an obstruction of 

a highway bridge that has a clearance of only 35 feet. 

Except for Coos Bay, ports along the Oregon Coast, such as Tillamook Bay, Depoe Bay, 

Yaquina Bay, Florence, Reedsport, Bandon, Port Ordford, Gold Beach, and Brookings have 

channels that are not deep enough for LNG carriers. There are some suitable deepwater ports 

along the Columbia River. On the lower Columbia River, potential sites for LNG terminals have 

been identified at Warrenton/Astoria and Bradwood/Wauna. At Warrenton and Bradwood there 

are potential sites for an LNG import terminal that have been previously taken up by other LNG 

developers (Oregon LNG and NorthernStar), which are discussed above in section 3.2.4 as 

proposed LNG terminal alternatives. The Port of Astoria itself was not considered for an LNG 

terminal because of population density and lack of industrial zoned waterfront land that could be 

developed for this purpose. However, a potential site for an alternative LNG terminal was 

identified at Tansy Point in Warrenton, at the location presently occupied by Warrenton Fiber. 

This parcel is surrounded by residences, and no developer has stepped forward yet to propose the 

conversion of this existing wood chipping yard into an LNG import terminal. 

Other potential ports in Oregon further up the Columbia River, including Port Westward, St. 

Helens, and Portland, were found undesirable by Jordan Cove because of longer transit distance 

along the waterway and populations densities. LNG carriers would have to transit about 58 

miles up the Columbia River waterway to reach Port Westward, and about 104 miles to reach 

Portland. In the case of Port Westward, problems related to the lease of waterfront property 

caused another LNG developer to not to go forward with a proposal at that location. 

At Coos Bay, Jordon Cove found a navigation channel deep enough to handle LNG carriers. The 

transit along the waterway is relatively short, at 7.5 miles to the proposed terminal location. 

There are no obstructions along the waterway. LNG marine traffic in the waterway would pass 

by the communities of Charleston, Empire, North Bend, and Coos Bay, with population densities 

ranging between 2,500 and 5,000 people per square mile in portions of North Bend and Coos 

Bay. In comparison, LNG carriers heading up the lower Columbia River to the proposed 

Bradwood LNG import terminal would have to travel about 38 miles and pass by the 

communities of Warrenton and Astoria, with population densities at Astoria being about 1,600 

people per square mile. There are no residences within one mile of the proposed Jordan Cove 

LNG terminal. The Jordan Cove terminal property is currently zoned for industrial development, 

and is large enough to accommodate all proposed facilities and the surrounding vapor hazard 
3-33 3.0 – Alternatives 

zone. There has been declining commercial shipping at the Port of Coos Bay over the last 20 

years, and the Port is taking an active role in encouraging the location of an LNG terminal by 

providing the land, access channel, and slip. 

3.3.1 Coos Bay Terminal Site Alternatives 

Within Coos Bay, Jordan Cove looked at four tracts of industrial land as potential LNG terminal 

locations below the railroad bridge at CM 9 that would prevent LNG carriers from transiting 

further up the bay (figure 3.3-2). These sites are discussed below. 

• Parcel A – Port Industrial Park – This parcel, comprising less than 100 acres, was 

eliminated by Jordan Cove because of limited size. The Port sold this tract to Southport 

who constructed a small dimension lumber mill on the site in 2005. Concurrent with this 

development, the Port installed a new railroad spur that runs parallel to the Trans-Pacific 

Parkway on the North Spit to serve the mill. Southport also has a berth at CM 6.4 along 

the Coos Bay navigation channel. Jordan Cove proposes to store sand dredged from the 

access channel and slip for its LNG terminal on Port owned land adjacent to the 

Southport parcel (see section 2.1.1.2). 

• Parcel B – Former Weyerhaeuser Linerboard Mill – The Weyerhaeuser mill has been 

removed from this property, and the tract is available for future industrial development. 

However, Jordan Cove believes it is too close to the railroad bridge to allow for the 

creation of an access channel and berth to handle LNG carriers. Instead, Jordan Cove 

proposes to use the former Weyerhaeuser Linerboard Mill property to store material that 

would be excavated and dredged by the Port for the slip at the proposed Jordan Cove 

LNG terminal located at the Henderson Ranch tract (see below). 

• Parcel C – Roseburg Forest Products – Jordan Cove originally proposed to use the 

Roseburg tract for its smaller terminal, conceived for intrastate gas supply, under the 

Oregon Energy Facilities Siting Council (EFSC) review process. That proposal would 

have only included one LNG storage tank, and is discussed in more detail below as an 

alternative design scenario (see section 3.1.3.7). The Roseburg tract would not be large 

enough for an LNG import terminal with a slip, two LNG storage tanks, and the 

necessary vapor exclusion zones. However, Jordan Cove would use portions of the 

Roseburg property for some of its buildings, including the entry office, construction 

staging areas, access roads, and the NGL extraction export facilities. 

• Parcel D – Henderson Ranch – The Henderson Ranch site, located immediately to the 

west of the Roseburg property was identified as the preferred location for the Jordan 

Cove LNG terminal. The Port obtained this property through an agreement with 

Weyerhaeuser. The tract is zoned for industrial use, and is currently vacant land that was 

formerly used by the COE to deposit materials dredged from the Coos Bay navigation 

channel. 
3-34 3.0 – Alternatives 

Figure 3.3-2. Potential LNG Terminal Sites in the Coos Bay Area 
3-35 3.0 – Alternatives 

3.3.2 Alternative Terminal Configurations 

We considered whether or not there are alternative designs for the LNG terminal that may lessen 

environmental impacts and still achieve the Project objectives. This included an examination of 

a smaller facility with only one storage tank; various other storage tank designs; different berth 

configurations; and other vaporizer technologies. Based on Jordan Cove’s responses to our data 

request questions about these issues, we believe that the currently proposed LNG facility 

terminal design makes sense from both an engineering and environmental standpoint in order to 

meet the Project objectives. We could not identify another alternative design that was 

environmentally superior, and still could meet the engineering criteria necessary to achieve 

Jordan Cove’s expectations and the Project objectives. Those criteria included the ability to 

dock LNG carriers up to 217,000 m3

 in capacity, store up to 320,000 m3 of LNG, send out up to 

1.0 Bscfd of natural gas at peak deliverability, and include thermal exclusion zones that could be 

owned or controlled by Jordan Cove within its terminal tract. 

3.3.2.1 Smaller LNG Terminal at Roseburg Property Alternative 

In November 2004, Jordan Cove provided the EFSC with a Notice of Intent to build an LNG 

import terminal at Coos Bay with a smaller footprint at a different site than the proposal filed 

with the FERC in September 2007. The earlier design included a single berth for LNG carriers, 

a 3,000-foot-long, 20-inch-diameter cryogenic transfer pipeline from the dock to the LNG 

storage tank, a single duel-containment LNG storage tank with a capacity of 120,000 m3, 

vaporization system with the capacity to deliver about 8,500 thousand standard feet of natural 

gas per hour, and a 25 MW power plant. These facilities would have been located on about 93 

acres within the Roseburg property. The single full containment LNG storage tank was to be 

located east of the existing Roseburg mill buildings. The berth would have been adjacent to the 

existing Roseburg dock. Jordan Cove originally envisioned this smaller LNG terminal as serving 

a “niche” market entirely within the state of Oregon. 

Jordan Cove eventually became convinced that the smaller LNG terminal with a single storage 

tank was not economically viable. Two LNG storage tanks, with a combined volume of 320,000 

m3

, would be necessary to serve future demands. The project objectives changed to providing 

gas to markets in the Pacific Northwest, northern Nevada, northern California, as well as LDCs 

in southern Oregon. The increased volume of LNG storage capacity would be necessary to 

ensure a constant rate of natural gas sendout with minimal risk of stock outages, and to avoid 

demurrge of inbound LNG cargoes. 

Jordan Cove considered the possibility of constructing one large LNG storage tank on the 

Roseburg property, with a 200,000 m3

 capacity. However, no existing LNG terminal in the 

United States has a storage tank that large, and so Jordan Cove settled on a design using two full 

containment tanks with a capacity of 160,000 m3

 each, which are the size of LNG storage tanks 

installed at the Costa Azul terminal near Ensenada, Mexico. While two tanks could be located 

within the Roseburg track, modeling indicated that the vapor dispersion zone for storage of 

320,000 m3

 of LNG would extend beyond the parcel that Jordan Cove originally sought to 

acquire. 

Besides the fact that the one LNG storage tank design could not meet the objectives of the newly 

redefined project, and the Roseburg parcel was too small to contain all the facilities for the new 
3-36 3.0 – Alternatives 

design and its associated vapor hazard zones, there were no significant environmental differences 

between the original concept and the current LNG terminal proposal on the adjacent Henderson 

Ranch property. Both parcels are zoned for marine industrial development. While there is 

existing industrial land use at Roseburg, the Henderson Ranch property is currently vacant, and 

was formerly used by the COE to deposit materials dredged during maintenance of the Coos Bay 

navigation channel. Total land required for operation of the LNG terminal at Henderson Ranch, 

149 acres, is slightly larger than the 93 acres required for a smaller terminal at the Roseburg 

parcel. Construction of the storage and processing facilities at both Roseburg and Henderson 

Ranch would require removal and grading of existing sand dunes. While no upland wetlands 

would be disturbed during construction of the proposed LNG terminal at Henderson Ranch, it is 

possible that wetlands would be affected at the Roseburg site. Terminals at either location would 

require dredging in Coos Bay for the creation of an access channel and slip for LNG carriers. 

Jordan Cove believes that the portion of the bay at Roseburg contains habitat for oysters and 

other mollusks. The cryogenic transfer pipeline from a berth at Roseburg would be longer, at 

3,000 feet, than the current design at Henderson Ranch, which would have a transfer pipeline 

2,600 feet long. The single LNG storage tank at the Roseburg location would be outside of, but 

close to, the glide path for non-instrument runway 13/31 at the North Bend Airport. The two 

LNG storage tanks on the Henderson Ranch property would be farther away from the airport 

runways. 

3.3.2.2 Other LNG Storage Tank Design Alternatives 

Jordan Cove examined ways to design the LNG terminal to minimize the visibility of the LNG 

storage tanks. This design concept could best be accomplished by reducing overall tank height 

and increasing the diameter to height ratio, while still being constrained by the requirement that 

the maximum individual LNG tank would have a volume of 160,000 m3

. The possibility also 

existed that rather than employing two tanks to contain the necessary volumes, the 320,000 m3

 of 

storage could be spread between three or more tanks. This would have the potential to lower the 

overall height of each of the tanks, but would require an additional tank(s) and additional land 

area, with the trade-offs in this instance being both economic and aesthetic. The most 

economically efficient liquids storage methodology is established by basic solid geometric 

principles. The larger the tank, the smaller the tank materials required per volume contained 

(larger tanks use less materials per unit of volume than smaller tanks). Additionally, given the 

NFPA 59A thermal radiation and vapor dispersion exclusion zone distances, the use of fewer 

tanks would result in the smallest land area impact. 

Shorter tank heights, which require larger tank diameters, were evaluated to reduce visual 

impact. Jordan Cove deemed the use of shorter tanks infeasible, since larger tank diameters than 

those proposed began to strain the limits of proven construction techniques, while at the same 

time creating thermal exclusion and vapor dispersion exclusion zones that extended beyond the 

site property boundaries. 

An alternative of burying the LNG storage tanks was also considered. However, this approach 

was limited by local soils and geologic conditions. Geotechnical investigations at the proposed 

Jordan Cove terminal found the water table to be approximately 10 feet below the surface. In 

order to support a buried tank, the foundations would have to be below the water table, which 

would present difficult engineering and environmental problems. The groundwater would need 

to be continually pumped from the subsurface area in the vicinity of the LNG tanks to avoid the 
3-37 3.0 – Alternatives 

potential for contact with the underground tank heat coils, resulting in potential disruptions to 

groundwater flow, as well as, an additional water discharge. The high heat transfer coefficient of 

water would result in an excessive amount of power being used to energize the heat coils. The 

mobility of the water would exacerbate this problem because as the water was warmed it would 

flow away from the coils due to the natural groundwater migration pattern in this area. The 

warmed water would then be replaced by cold water resulting in still greater power consumption 

requirements. 

Jordan Cove also considered different ways of orienting the LNG storage tanks within the 

Henderson Ranch parcel. Relocation of the tanks to the east or west is constrained by property 

boundaries. The location of the Henderson Marsh along the entire western side of the site and 

the wetlands in the north eastern corner of the site property, the existing Roseburg facilities, and 

the Port’s concept for a slip dictated the primary north south axis on which the facility 

components could be oriented. Movement of the tanks to the south was limited by the required 

NFPA 59A distances from the slip. Although the tanks could be located slightly more northerly 

than presently planned, doing so would extend the length of the cryogenic transfer pipeline that 

connect the berth to the LNG storage tanks, and create a situation where the thermal exclusion 

and vapor dispersion exclusion zones would overlap the Trans-Pacific Parkway and the adjacent 

railroad line. 

3.3.2.3 Alternative Berth Configurations 

Jordan Cove compared placing a single berth for LNG carriers on the west side of the existing 

chip ship dock at Roseburg, to the current proposal for a slip at Henderson Ranch. An LNG 

carrier docking at Roseburg would be closer to the glide path for the 13/31 runway at the North 

Bend Airport than a ship at berth at the Henderson Ranch site. A berth at Roseburg would place 

an LNG carrier at dock within 600 feet of the Coos Bay navigation channel at the Jarvis Turn. In 

the event that another inbound vessel failed to properly negotiate the Jarvis Turn, there could be 

the possibility of a collision with an LNG carrier at the Roseburg berth location. The Coos Bay 

pilots and the Port, as well as engineering and safety consultants engaged by Jordan Cove, 

recommended that the Roseburg berth design be abandoned in favor of a berth at Henderson 

Ranch. 

Commenters on the FERC’s draft EIS for the JCE & PCGP Project asked if it were possible to 

make the proposed terminal slip smaller, because the Coast Guard WSR limited LNG carriers 

using the berth to 148,000 m3 or less in capacity. Jordan Cove addressed this issue in a filing on 

February 20, 2009, in response to the FERC staff’s February 10, 2009 data request. Jordan Cove 

clarified that it originally designed the terminal slip using a Moss Spherical LNG carrier of 

138,000 m3 capacity as a model, and this established the north to south slip dimensions. The 

width of the slip is independent of LNG carrier capacity, as enough space is needed to allow tug 

boats to maneuver the carrier into the berth. The slip geometry necessary to berth a 138,000 m3 

capacity Moss Spherical LNG carrier could also physically accommodate current configurations 

of LNG carriers up to 217,000 m3 in capacity (Q-Flex class ships). 

3.3.2.4 Vaporization Alternatives 

We considered if possible vaporization alternatives may reduce potential Project-related impacts 

on water and air quality. Vaporizers are used to warm the LNG and turn it back into natural gas. 

There are various technologies that could be used in the design of the re-gasification units. This 
3-38 3.0 – Alternatives 

includes ambient air vaporizers, open rack vaporizers, shell and tube vaporizers, and submerged 

combustion vaporizers. Vaporizers that burn natural gas to heat enclosed water baths to warm 

the LNG can produce air pollutants, including NOx, CO, CO2, and PM10. Estimated air 

emissions associated with SCVs, water baths, and STVs are presented in table 3.3.2.4-1. 

TABLE 3.3.2.4-1 

Estimated Air Emissions Associated with Vaporizer Combustion

Air Emissions (tpy) a/

Vaporizer Design NOx CO PM10

SCV b/ 121.9 199.3 13.4 

Water Bath c/ 310 261 24 

STV c/ 310 261 24 

a/ Tones per year. Based on a sendout rate of 1.0 Bscfd and 12-month operation of vaporizers. 

b/ Based on an SCV firing rate of 17 Mscfd, 120 MMBTU/he heat rate. 

c/ Based on large wall-fired boiler with flue gas recirculation and low NOx burners, assuming 17 Mscfd firing rate. 

 Estimated from EPA AP-42 guidelines for external combustion engines – boilers. 

In the cases where water is used to warm the LNG, there are various heat sources that could be 

used to heat the water. These include electric power, wood chips, natural gas, and waste heat 

from cogeneration. Technologies relying on electric power for heating were eliminated because 

of an unacceptable price. Burning of wood chips for a heating source was eliminated because of 

the large variability in wood chip costs over time, air emissions, lack of storage areas on site for 

the wood chips, and because of potential impacts associated with transporting large volumes of 

wood chips to the site. 

Ambient Air Vaporizers

At some locations with warm climates, it is possible to use ambient warm air or ambient warm 

water as a source of the heat needed to vaporize the LNG. The advantage of vaporizers that 

utilize ambient air or water vaporization systems is that air emissions tend to be lower than for a 

system that involves combustion of a hydrocarbon fuel. Air or water vaporizers can result in 

very small quantities of air emissions associated with electrical generation required to power fans 

or pumps, although the amount of power needed for the vaporizers is relatively minor (Coast 

Guard and MARAD 2003). 

Ambient air-heated vaporizers use air warming structures to warm and vaporize the LNG. 

Because the surface area of the heat exchangers needs to be large for efficient heat transfer, the 

structures would be large and require significant space for construction and operation. Because 

water would condense on the warming structures, ambient air vaporizers would produce about 

1.3 mgd of water during operation compared to approximately 0.4 mgd for operation of SCV 

units. 

Ambient air vaporizers are in use at the Sabine LNG terminal expansion in Cameron Parish, 

Louisiana and are proposed at the Oregon LNG terminal in Warrenton, Oregon. NorthernStar 

did a study of the technical feasibility of using ambient air vaporizers at its proposed Bradwood 

Project in Clatsop County, Oregon, and concluded that they would not be practical because of 

limitations associated with periods of cool weather along the Columbia River. Average monthly 

temperatures in Coos Bay and in the lower Columbia are similar. 
3-39 3.0 – Alternatives 

Water-Based Vaporization 

A water-based vaporization system would require withdrawing (and discharging) large volumes 

of water from an available source. In the case of the proposed Jordan Cove LNG terminal, that 

source would be Coos Bay. If the bay water temperature is above approximately 63°F, the water 

can typically serve as the sole heat source for LNG vaporization. When water temperatures drop 

to between 50°F and 63°F, supplemental heat is typically required. The water temperature in 

Coos Bay ranges from 46 to 58°F. This is too cold year-round to use for vaporization without 

supplementation from other sources. Also, the use of water-based vaporization, without another 

heat source, was not found viable because of concerns over potential impacts water withdrawals 

or discharges may have on aquatic resources. Water withdrawals for vaporizers may entrain fish. 

Additional concerns have been raised about the thermal plume associated with discharging cold 

water back into the affected waterbody. In the case of the bay, there may be concerns about the 

temperature of the discharge water. 

Water Bath 

Water baths use an open bath containing combustion tubes and LNG tubes. The fired gases 

transfer heat through the combustion tubes to the water bath and the water bath transfers heat to 

the LNG piping. The combustion gases and the water bath are not in direct contact with each 

other (unlike in SCVs). The combustion gases are discharged to the atmosphere. Approximately 

2 percent of the natural gas produced by the terminal would be used in this process resulting in 

more air emissions than SCVs. This system is less efficient than SCVs. 

Open Rack Vaporizer 

ORVs are commonly used at LNG terminals in Asia and Europe. The Sempra Costa Azul LNG 

terminal in Baja Mexico uses ORVs. Typically, ORVs use seawater as their sole source of heat. 

Seawater is supplied by intake pumps to an overhead distribution header and flows over the outer 

surface of long finned tube panels. LNG flows inside the tubes and is vaporized by the warm 

seawater. The seawater is cooled by the LNG exchange, and would be returned to the ocean by 

an outfall at temperatures lower than when it was withdrawn. Electric power is required to run 

the seawater intake pumps. As noted above, water withdrawals for vaporizers may entrain fish 

and concerns have been raised about the thermal plume associated with discharging cold water 

back into the bay. 

Shell and Tube Vaporizer 

STV systems involve a heat exchanger in which tubes containing LNG pass through a shell 

containing an external fluid counter-current of heat exchange media such as a water/glycol 

mixture. On the opposite end of the heat exchanger loop, the water/glycol mixture is typically 

heated by using direct-fired combustors burning natural gas. However, the source of heat may 

vary depending on the particular design. About 100,000 gallons of fresh water would be 

necessary to operate a closed-loop system. An advantage of the STV is that selective catalytic 

reduction systems and oxidation catalysts can be used on the heaters to reduce NOx and CO 

emissions. In an open loop system the external fluid could consist of sea water in a single-pass 

seawater system. Sea water would enter through the side of the exchanger at an upper and lower 

inlet where it would be circulated over the tubes with the LNG flowing inside and warming it to 

a gaseous state where it would exit at the top of the shell. STV technology using a single-pass 

seawater system requires an abundant supply of sea water. The primary disadvantages of this 
3-40 3.0 – Alternatives 

technology are fouling and maintenance of the shell and tube exchangers, frequent periods of 

downtime for maintenance, potential freezing of the shell and tubes, and impingement and 

entrainment of marine organisms. We do not recommend use of this alternative for these 

reasons. 

Submerged Combustion Vaporizer 

Based on its analysis of the various technologies and heat sources, Jordan Cove chose the SCV 

system with natural gas for vaporization, supplemented with heat exchanged from the proposed 

on-site power plant. SCVs are generally based around a concrete structure containing a water 

bath with submerged stainless steel pipe coils. LNG enters the coils and, as it is warmed by the 

water bath, the vaporized LNG (natural gas) exits the coils. The water bath is warmed by 

burning natural gas delivered through the BOG recovery system. SCVs typically consume about 

1.5 percent of the sendout natural gas from the terminal. Blowers provide combustion air at a 

pressure sufficient to force the combustion emissions up through the water bath where they heat 

the water. Electric power is required to run the combination of air blowers and water circulation 

pumps. The SCVs produce excess condensate water, on the order of several million gallons per 

day. Disposal of the excess water requires treatment with alkaline chemicals to neutralize the 

acidity caused by absorbed CO2. SCVs tend to have higher air emissions, particularly NOx, than 

other combustion units because the use of selective catalytic methods to control emissions has 

not proven reliable. 

3.3.3 Dredging and Dredged Material Placement Alternatives 

In order to create the access channel and slip for the proposed Jordan Cove import terminal, a 

total of about 5.6 mcy would need to be dredged and excavated by the Port. Jordan Cove and the 

Port determined that this was the minimum volume needed to construct the access channel and 

slip so that the terminal could safely accommodate LNG carriers. Therefore, we did not consider 

it feasible to reduce the volume or extent of dredging and still satisfy the objectives of the 

Project, and we did not evaluate alternatives for dredging and storing lesser amounts of material. 

The proposed Project would store excavated and dredged materials at three different locations 

(discussed in more detail in section 2.1.1.2): Jordan Cove site; Weyerhaeuser Linerboard site; 

and Port Sand Stockpile site. In addition, materials dredged during maintenance activities would 

be deposited at sea at Site F. In choosing these dredged material storage locations, Jordan Cove 

and the Port examined a number of alternative sites for dredge material disposal; as discussed 

below. In addition, Jordan Cove and the Port considered which dredging methods were likely to 

have the least environmental impacts. Therefore, alternative dredging methods are discussed 

below. 

Dredging and placement of structures within waters of the United States requires authorization 

from the COE under section 404 of the CWA and section 10 of the RHA. In addition, 

permission must be acquired to construct the access channel in Coos Bay on lands owned by the 

ODSL. As an element of its review, the COE is required to consider whether a proposed project 

represents the least environmentally damaging practicable alternative pursuant to the CWA 

section 404(b)(1) guidelines (40 CFR 230). The term practicable means available and capable of 

being done after taking into consideration cost, existing technology, and logistics in light of 

overall project purposes. As a cooperating agency, the COE has recommended that the 

alternatives analysis in this EIS consider project design, configuration, and construction 
3-41 3.0 – Alternatives 

alternatives that avoid or minimize effects on the aquatic environment. In this way, this EIS 

could be used to identify the COE’s least environmentally damaging practicable alternative. 

Ultimately, activities associated with dredging, as well as construction of the LNG carrier berth 

and unloading facility, would be conducted in accordance with COE permit stipulations as well 

as the requirements of state permits (see section 1.3). To avoid or minimize impacts on water 

quality or biological resources associated with these activities (see sections 4.3.2.2 and 4.5.2.1), 

alternative dredging methods and dredged material placement areas were considered. 

3.3.3.1 Alternative Dredging Methods 

There are two general types of dredging methods: mechanical dredging and hydraulic dredging. 

The methods vary by the process by which material is loosened and transported from the seafloor 

to the water surface. The type of dredging equipment that is used affects the characteristics of 

the dredged material. 

Mechanical Dredging 

Mechanical dredging excavates sediments with a grab or bucket. The most common type of 

mechanical dredge is the clamshell dredge, which is named for the type of bucket used in the 

operation. The dredging process consists of lowering the bucket to the seafloor, closing the 

bucket and raising it back to the water surface, and depositing the dredged material into a scow 

or, if appropriate, directly into an adjoining placement site. The efficiency and capacity of this 

type of dredging is determined by the capacity of the bucket, which varies between 1.5 and 25 

cy, scow capacity, which typically varies from 3,000 to 7,200 cy, the number of available scows, 

and sediment characteristics. 

Mechanical dredges are often used in tightly confined areas, such as harbors, around docks and 

piers, and in relatively protected channels. By using numerous scows with one dredge, 

mechanical dredging can proceed continuously. As one scow is being filled, another can be 

towed to the placement site. 

Hydraulic Dredging 

In hydraulic dredging, material is loosened and lifted in suspension through a pipe system 

connected to a centrifugal pump. Hydraulic dredging is most efficient when working with fine 

materials and sands since they are easily held in suspension. Coarser materials, including gravel, 

may be hydraulically dredged; however, these materials require a greater demand of pump power 

and can cause excessive wear on pumps and pipes. The two main types of hydraulic dredges are 

cutter suction (pipeline) and hopper dredges. 

Cutter Suction (Pipeline) Dredge 

A cutter suction dredge is a hydraulic dredge that uses a rotating cutting apparatus around the 

intake of a suction pipe, called a cutterhead, to break up or loosen bottom material. A large 

centrifugal pump removes the material from the bottom of the channel and pumps the sedimentwater slurry through a discharge pipeline. Cutter suction dredges are generally rated based on 

the size of the discharge pipe, which ranges from 6 to 30 inches. A typical 30-inch dredge has a 

production rate of up to 20,000 to 30,000 cy per day, depending on sediment characteristics and 
3-42 3.0 – Alternatives 

placement method. Pipeline dredges are often operated on a 24-hour, 7-day per week basis, but 

downtime due to maintenance and other factors are often 25 percent or more. 

Material dredged by a cutter suction dredge is directly placed into the placement area by the 

discharge pipeline or, less frequently, can be pumped into scows, which are then transported to 

the placement site and emptied via mechanical or hydraulic means. Discharge pipelines are 

usually floated on the water surface, but may be placed on land, submerged on the seabed, or 

buried. In a typical application, dredged material is pumped up to 25,000 feet. The addition of 

booster pumps, located on land, jack-up type rigs, or on moored barges, increases the distance to 

50,000 feet or greater. 

Cutter suction dredges operate continuously, and are cost effective if the placement site is in 

relative close proximity to the dredge area. However, booster pumps increase pumping cost and 

can decrease productivity. Cutter suction dredges are not recommended for areas with heavy 

debris that can clog pumps and impair efficiency. 

Hopper Dredge 

Hopper dredges have the shape of a conventional ship hull and are equipped with either single or 

twin trailing suction pipes. A hopper dredge operates much like a floating vacuum cleaner in 

that material is lifted through the trailing suction pipes by one or more pumps and then the 

mixture of water and solids is stored in a hopper contained within the hull of the dredger. This 

type of dredge is often used for rougher, open waters where mechanical and hydraulic/pipeline 

dredges cannot operate effectively. A hopper dredge operates best by skimming layers of 

material in long, narrow runs and is primarily used in open water, such as rivers, canals, and 

open sea. This type of dredge is unable to get into corners, difficult to maneuver in confined 

spaces, unsuitable for use in shallow water, and is not effective on hard materials such as stiff 

clays. A hopper dredge can move quickly to a placement area under its own power, but the 

operation loses efficiency as the transport distance increases. 

Once the hopper is full, material may be discharged onto an open-water placement site by 

opening the hopper doors located in the bottom of the ship’s hull or fluidized by jets and 

hydraulically pumped from the hopper. For bottom dumping, the entire contents of the hopper 

can be emptied in a matter of minutes. Upon discharge from the hopper dredge, the dredged 

material falls through the water column as a well-defined jet of high-density fluid. The descent 

and deposition of the slurry mixture is dependent on the material’s physical characteristics. 

Hydraulic pump out can take up to 30 to 60 minutes and discharge slurry is similar in density to 

cutter-head slurry. 

3.3.3.2 Dredged Material Placement Alternatives 

Initially, the Port evaluated 23 dredged material management alternatives, including 

conventional open water disposal, confined placement, and beneficial use. Disposal sites 

evaluated in the Excavated and Dredged Material Management Plan are shown on figure 3.3-3. 

In addition to the four sites chosen for the proposed Project, the Port seriously considered other 

options, including the Industrial Waste Pond, the North Spit beach nourishment site, and the 
3-43 3.0 – Alternatives

Figure 3.3-3. Potential Dredged Material Disposal Sites Evaluated by the Port 
3-44 3.0 – Alternatives 

North Spit Tsunami Protection Levee. These are discussed below, with an explanation about 

why they were not selected. Table 3.3.3.2-1 lists the 23 sites evaluated by the Port, and the 

explanation of which sites are considered by the Port to be suitable. 

TABLE 3.3.3.2-1 

Excavated and Dredged Material Placement Sites Evaluated by the Port for the Proposed Jordan Cove Energy Project a/

Feasibility ID No. 

(see Fig 3.1-3) Potential Site Available Capacity Technical Logistical Environmental 

12 Black Liquor Lagoon No - withdrawn 

by the owner 

 

3 Coos Bay Entrance 

Site E 

No No - site is closed and 

not accepting new 

material 

 

2 Coos Bay Entrance 

Site F 

Yes Yes – Jordan Cove 

proposes to deposit 

3.5 mcy of 

maintenance dredged 

material over 20 years 

Yes Yes Yes 

1 Coos Bay Entrance 

Site H 

 No - restricted 

to finer-grained 

sands and silt 

materials from 

above RM 12 

 

5 Crescent Bay 

Shoreline Stabilization 

 No - capacity limited 

to between 200,000 

and 500,000 cy 

 

15 Excavated Material 

Stockpile Site 

 No - wetlands are 

located on site. 

14 Grassland Industrial 

Development 

No - site is not 

available for 

dredge storage 

because of 

overlap with 

Jordan Cove 

terminal facilities 

 

13 Henderson Marsh 

(DMD-4X) 

 No - wetlands are 

located on site. 

10 Industrial Waste Pond 

– Area A (4CS) 

No - withdrawn 

by the owner due 

to wetland 

mitigation issues 

 No – wetlands and 

birds could be 

affected 

11 Industrial Waste Pond 

– Area B (3WD) 

No - withdrawn 

by the owner due 

to wetland 

mitigation issues 

Yes – capacity for 5.4 

mcy of dredged 

materials 

 No – wetlands and 

birds could be 

affected 

22 Island Disposal Facility 

(DMD-16A/B) 

No No – already at 

capacity and not 

accepting new 

material. 

 

16 Jordan Cove Energy 

Placement Site 

Yes Yes – capacity for 0.5 

mcy of dry materials 

Yes Yes Yes 

18 North Bend Municipal 

Airport Nearshore 

Disposal Facility 

(DMD-9X) 

 No - pier has 

been 

constructed 

that provides 

lighting for 

runway. 

 No – wetlands are 

located at site. 
3-45 3.0 – Alternatives 

TABLE 3.3.3.2-1 

Excavated and Dredged Material Placement Sites Evaluated by the Port for the Proposed Jordan Cove Energy Project a/

Feasibility ID No. 

(see Fig 3.1-3) Potential Site Available Capacity Technical Logistical Environmental 

19 North Bend Municipal 

Airport Upland 

Disposal Facility 

(DMD-9Y) 

 No – airport 

has extended 

runway on one 

end of site and 

an access road 

on the opposite 

side 

No - due to 

airport 

additions, 

access to 

open area of 

site is not 

available 

4 North Jetty Breach No No - site has not 

required additional 

material since the 

original repair to the 

breach in 2002 

 

20 North Point Island 

Disposal Facility 

No – property is 

owned by the Al 

Pierce Lumber 

Company and is 

currently for sale. 

Property is zoned 

for water 

dependent 

industrial 

developments 

No – dredged material 

was placed on the site 

in the 1980's creating 

wetland habitat, adding 

to the difficulties in 

trying to sell the 

property 

 

21 North Point Tsunami 

Zone Remediation 

No – property is 

owned by the Al 

Pierce Lumber 

Company and is 

currently for sale 

No – dredged material 

has been placed on 

site previously, but 

zoning changes 

preclude the 

placement of additional 

material 

 

7 North Spit Beach 

Nourishment 

No – BLM denied 

use of this land 

for dredge 

disposal 

Yes – capacity for 3.8 

mcy of dredged 

materials 

Yes Yes No – could impact 

snowy plovers 

8 Port Commercial Sand 

Stockpile Area 

Yes Yes – capacity for 3.3 

mcy of dredged 

materials 

Yes Yes Yes 

9 North Spit Tsunami 

Protection Levee 

Yes Yes – capacity for 2.3 

mcy of excavated 

materials 

Yes Yes No – may have 

impacts on 

wetlands and 

snowy plovers 

6 Western Snowy Plover 

Habitat 

 No – BLM 

restricted on 

acceptance of 

dredged 

material 

 No –Pink sand 

verbena, a state 

listed endangered 

plant species, is 

present 

17 Weyerhaeuser 

Linerboard Site 

Yes Yes – capacity for 1.8 

mcy of materials 

Yes Yes Yes 

23 White Point Upland 

Disposal Facility 

(DMD19B) 

No No - site is closed and 

not accepting new 

material 

 

a/ From Moffat & Nichol International 2007. 

North Spit Beach Nourishment

This dredged material site would consist of nourishment of 4.5 miles of the dune line along the 

North Spit starting at the North Jetty. Beach nourishment of the North Spit has the capacity to 

accommodate the 3.3 mcy of material that would be hydraulically dredged during construction of 

the slip and access channel. Dredged material would be placed above the MHH water line in a 
3-46 3.0 – Alternatives 

continuous dune fill. Dredged material would be transported hydraulically via pipeline behind a 

containment levee constructed at the seaward edge of the nourished dune profile. Existing beach 

material would be used to construct the levee. Return water would be discharged into the Pacific 

Ocean. Earth moving equipment would grade the containment levee and the dredged material to 

the desired slope. 

The North Spit Beach Nourishment alternative was not selected for two reasons. First, part of 

the land where this alternative was proposed is owned by the BLM, and the BLM would not 

allow this land to be used for dredged material disposal. Second, this activity would occur 

within an area that is critical habitat for the federally-listed threatened Western snowy plover, 

and it is possible that dredged material storage at this location could have adverse impacts on the 

Western snowy plover. 

North Spit Tsunami Protection Levee

This site would use excavated material to construct a levee that would provide some protection 

for the North Spit in the event of a tsunami. The possible location of the levee is approximately 

two miles west of the slip site. The levee would provide protection to the cities of Coos Bay and 

North Bend, as well as slip from the impacts of a tsunami striking the North Spit. The levee 

would cover approximately 60 acres and would be approximately 5,750 feet in length beginning 

at the southern end of the industrial wastewater pond and extending to the northeast. The 

excavated material (2.3 mcy) would be hauled to the disposal site by truck. The North Spit 

Tsunami Protection Levee alternative was not selected because it is possible that dredged 

material storage at this location could have adverse impacts on the federally listed threatened 

Western snowy plover. 

Industrial Waste Pond

The Industrial Waste Pond (IWP) on the North Spit was created by Weyerhaeuser to receive and 

treat effluent from the company’s former mill. The IWP is a 300-acre settling pond, with a 

20,000 gpm ocean outfall. The Port has an option to acquire the IWP as part of the large parcel it 

intends to purchase from Weyerhaeuser. 

The IWP is about one mile west of Jordan Cove terminal. The Port considered using about 205 

acres at the IWP for placement of excavated and dredged materials. The excavated materials 

could be transported by truck via the Trans-Pacific Parkway or the material could be transported 

in a slurry pipeline. Decant water would be returned to the bay through a separate pipeline 

between the IWP and the Jordan Cove terminal slip. The Port indicated that it would have to 

construct a 25-foot-high, 12-foot-wide containment berm around the portion of the IWP to be 

used for dredge storage. This berm would be 12,500 feet long, and constructed of 1.0 mcy of 

material excavated for the slip. Excluding the material used to construct the berm, the IWP 

would be able to handle about 5.4 mcy. 

Two main factors influenced the Port’s decision not to use the IWP for dredge disposal from the 

Jordan Cove terminal slip and access channel. First, this action would result in the filling of 

wetlands. Second, the IWP is important bird habitat. 
3-47 3.0 – Alternatives 

3.3.4 Alternative LNG Terminal off the Shore of Oregon 

We considered if it is possible to construct and operate an LNG import terminal in the Pacific 

Ocean off the shore of Oregon as an alternative to the Jordan Cove terminal. Offshore LNG 

import terminals located in federal waters fall under the jurisdiction of the MARAD and the 

Coast Guard (pursuant to the Deepwater Port Act of 1974, as amended by the Maritime 

Transportation Security Act of 2002). Currently, there are no deep water LNG terminals existing 

or proposed off the coasts of either Oregon or Washington. There are several proposed LNG 

terminals off-shore in southern California, and those proposals are discussed above in section 

3.2.4.3. 

The main advantage of an offshore LNG import terminal would be that it would probably not 

impact mainland populations. Also, impacts on other commercial and recreational users of the 

Coos Bay waterway would be avoided. However, there would still be a need for a sendout 

pipeline to connect the offshore LNG terminal with an onshore existing natural gas interstate 

system, to get the gas to its intended markets. Depending on the routing of that pipeline, there 

could be potential impacts on mainland populations and other environmental resources. In 

addition, there could also be impacts on aquatic resources related to the installation of the 

undersea portion of the pipeline from an offshore LNG import terminal. The length of the 

sendout pipeline from an offshore LNG terminal would have to be longer than the proposed 

Pacific Connector pipeline if it where to serve the same purposes and connect to the GTN, 

Tuscarora, and PG&E systems near Malin, Oregon. 

The main disadvantage of an LNG import terminal located off the coast of Oregon would be 

technological limitations related to typical ocean conditions in the region. In addition, an 

offshore LNG import terminal would have a smaller LNG storage and natural gas deliverability 

output than the terminal proposed by Jordan Cove, and may not be able to meet the objectives of 

the Jordan Cove terminal. For example, the only deep water LNG terminal currently operating 

off the coast of the United States, the Excelerate Gulf Gateway Deepwater Port facility in the 

Gulf of Mexico, can deliver up to 690 Mscfd. As discussed in more detail below, because of the 

ocean conditions off the coast of Oregon, and the limitations of current technologies for deep 

water LNG terminal, we do not think that an offshore LNG terminal would be a reasonable or 

feasible alternative to Jordan Cove’s proposed onshore LNG terminal to be located at Coos Bay. 

3.3.4.1 Offshore LNG Terminal Technologies and Strategies 

Companies that have proposed to construct and operate offshore LNG import terminals have 

advanced various technologies and strategies for platform construction, LNG carrier mooring, 

LNG transfer and storage, vaporization, and sendout (LNG Express 2003). These technologies/ 

strategies include: 

• offshore docking/onshore storage; 

• fixed offshore terminals (GBS or platforms); 

• transport/regasification vessels; or 

• floating, storage, and regasification units. 

Below we discuss these various technologies/strategies for offshore LNG import terminals, 

compare their potential environmental impacts, and analyze their feasibility as an alternative the 

onshore LNG import terminal facilities proposed by Jordan Cove. 
3-48 3.0 – Alternatives 

Offshore Docking/Onshore Storage

Where deepwater access to a coastal port or harbor is unavailable, LNG can be transported to 

onshore storage tanks from ships using specially designed cryogenic pipelines. Such facilities 

enable LNG carriers to berth and transfer their LNG cargo to the cryogenic pipeline at docking 

facilities in offshore areas where natural water depths exceed 40 feet. Although feasible, a 

number of technical factors related to transporting LNG in a pipeline place limits on the practical 

maximum length of such a pipeline. This approach has been used at the existing Cove Point 

LNG terminal where the ship docking/unloading platform is located in the Chesapeake Bay 

about 1 mile from the shoreline. Similar facilities have been proposed for the Irving Oil LNG 

site in New Brunswick, Canada, and the Keltic Petrochemicals LNG and Bear Head LNG 

facilities in Nova Scotia, Canada. No such facility has been proposed for the West Coast. 

While it would be possible to transfer LNG to shore through a cryogenic pipeline from an 

offshore docking structure, such a design would still require locating LNG storage tanks and 

process facilities at an onshore location, therefore resulting in similar environmental impacts as 

an onshore LNG import terminal, in addition to the disadvantages associated with an offshore 

docking structure and pipeline. Because of severe winter weather conditions and significant 

wave heights along the Oregon and Washington coasts (ABSG Consulting Inc. [ABSG] 2006), 

we did not identify a site where the use of this approach appeared practical. 

Fixed Offshore Terminals/Gravity-Based Structure

There are basically two different types of fixed structures that can be used as an offshore LNG 

import terminal, either a GBS located directly on the seafloor or a pile-based platform. A GBS 

would contain LNG storage tanks and vaporizers on a platform with foundations directly on the 

seafloor. LNG could be offloaded from conventional LNG carriers, placed in the storage tanks 

within the GBS, and then vaporized for delivery as natural gas to the onshore market via an 

undersea pipeline. A GBS is only feasible in areas of relatively shallow water, where depths 

range between 45 and 100 feet. Ocean depths off the coast of Oregon exceed 100 feet in depth at 

an average distance of 1.7 nautical miles from the coast line. Therefore, any proposed LNG 

terminal alternative using GBS technology off the coast of Oregon would need to be located 

relatively close to the shore. 

Chevron received approval from the Coast Guard to build an LNG import terminal in the Gulf of 

Mexico (the Port Pelican Project) using a GBS that would be anchored to the sea bottom in water 

83 feet deep. The Port Pelican Project has been put on hold indefinitely and license rescission is 

expected. The recently abandoned LNG Terminal GNL Mar Adentro de Baja, off the western 

coast of Mexico, also proposed by Chevron, would have used a GBS at a depth of about 65 feet. 

Given the costs associated with constructing and operating a GBS, it appears that these facilities 

are economical for projects with relatively large LNG storage (e.g., 250,000 to 330,000 m3

) and 

large natural gas sendout volumes (e.g., 800 to 2,000 Mscfd). Another limitation would be the 

articulation of the unloading arms between the GBS and a docked LNG carrier, whose 

movement would be affected by high winds and large waves. 

There are multiple environmental issues associated with construction of an offshore LNG 

terminal using a GBS. First, there would be environmental impacts from anchoring the GBS to 

the ocean floor. The GBS would have to be built in an onshore graving yard and towed out to 

sea. Associated with the graving dock would be the necessary channel that allows the GBS to be 
3-49 3.0 – Alternatives 

floated out to the ocean. The creation of the graving dock could have impacts on terrestrial 

resources. For example, the proposed graving dock to fabricate the GBS for the Port Pelican 

Project was estimated to require up to 174 acres of shoreline. There would also be logistical 

constraints of towing the GBS to a selected terminal site offshore in Oregon that would influence 

the location of the graving dock. 

Another strategy using a fixed offshore terminal involves constructing offshore platforms on 

piles or converting existing offshore platforms to LNG use. Such fixed-tower structures, could 

be located in deeper water than a GBS. The platforms could be fitted with docking, unloading, 

storage, and vaporization equipment. As with a GBS, LNG could be unloaded from a 

conventional LNG carrier, vaporized at the platform, and sent as natural gas to the onshore 

market via an undersea pipeline. A fixed platform would have limited space for LNG storage, 

and would need calm seas or protection from the elements (such as being located on the lee side 

of an island) to allow for safe LNG carrier docking. 

Depending on the specific design, offshore platforms may or may not include LNG storage 

facilities. The Clearwater Port proposed by NorthernStar Natural Gas, Inc. would retrofit an 

existing offshore platform off the coast of Ventura County, California as an LNG import 

terminal, but would not have any LNG storage on the platform, and instead would use 

underground gas storage onshore to compensate for irregular deliveries of gas (LNG Express 

2005). However, there are no known existing former oil or gas platforms off the coast of Oregon 

that could be retrofitted into an LNG import terminal. 

Transport/Regasification Vessels 

Several companies have proposed the installation of vaporization equipment on conventional 

LNG carrier ships, which would be called transport and regasification vessels. These ships 

would be able to dock at a floating unloading buoy and riser system where LNG could be 

vaporized onboard the LNG carrier and injected directly into offshore pipelines that interconnect 

with onshore natural gas transmission systems. The vaporization equipment located on the ships 

would use technology that is similar to land-based LNG terminals. 

Because LNG is vaporized on board the LNG carrier, this approach eliminates the need for fixed 

LNG storage. Some of the tradeoffs of this approach are that it requires a dedicated LNG fleet 

with vaporization equipment on all of the vessels. Additionally, it takes 6 to 10 days to unload a 

ship at a maximum design rate of about 0.5 Bscfd. 

In March 2005, the first project using this strategy began operation, and is the only existing 

offshore LNG import terminal of any type in North America. Excelerate’s Gulf Gateway 

Deepwater Port includes a submerged turret loading system and about 8 miles of 20-inchdiameter pipeline that connects to two existing subsea pipelines located about 116 miles south of 

Cameron, Louisiana (LNG Express 2002, 2003). Excelerate ordered three LNG carriers to be 

constructed to include onboard vaporization equipment. One of these ships is now in service and 

is delivering natural gas to the United States. Excelerate has indicated that it is exploring the 

installation of another offshore buoy and regasification vessel system to serve offshore northern 

California, known as the Pacific Gateway Project (see section 3.2.4.3). 

As described above in section 3.2.4.3, Woodside has proposed a project using a similar 

technology at an offshore location 22 miles southwest of Los Angeles, California. The Ocean 

Way LNG Terminal Project would consist of a ship mooring facility with a flexible connection 
3-50 3.0 – Alternatives 

to an underwater natural gas pipeline that would come onshore at the Los Angeles International 

Airport and connect to SoCal’s delivery network (CEC 2007). 

Floating, Storage, and Regasification Units

FSRUs are another approach being considered for importing LNG into the United States from 

offshore terminals. In essence, an FSRU would be an oversized LNG carrier vessel that is 

outfitted with LNG vaporizers and docking/unloading equipment. The FSRU would be up to 

1,200 feet long, 180 to 215 feet wide, and would be able to store between 250,000 and 350,000 

m3 of LNG, which is more than twice the capacity of typical LNG carriers that are currently 

available. These units would be anchored offshore of the proposed market area where 

conventional LNG carriers could dock next to and unload LNG to the FSRU. After the LNG is 

unloaded, it could be vaporized and the natural gas could be transported to onshore markets 

through an undersea pipeline. Depending on the vaporizers and the size of the pipeline, these 

units could have a natural gas sendout capacity ranging from 700 to 1,500 Mscfd. 

BHP Billiton’s Cabrillo Port Project, proposed to be located about 14 miles off the southern 

California Coast (see section 3.2.4.3), would use an FSRU. The Moss-Marine LNG terminal 

proposed off the coast of Baja, California would also use an FSRU, as would the Broadwater 

LNG Project proposed for the Long Island Sound between Connecticut and New York (see 

FERC Docket No. CP06-54-000). 

The perceived favorable attributes of an offshore LNG import terminal using FSRU technology 

would include its location, which would not be dependent on ocean depth, and it would have a 

lesser footprint on the sea bed from anchoring the unit in comparison to a GBS. Some of the 

negative aspects of an offshore LNG terminal using FSRU technology in comparison to Jordan 

Cove’s proposed onshore terminal would include more difficult construction at sea; problems 

with unloading cargos on rough seas because of the relative motion of two vessels riding on large 

waves, and the potential for LNG spills during unloading; lack of safety and security 

infrastructure in close proximity; limited space, restricted facilities layout, and working/living 

quarters close to processing units; and environmental impacts on aquatic resources associated 

with anchoring the FSRU and construction of the undersea pipeline. 

HiLoad LNG Regas Technology 

The HiLoad LNG Regas technology developed by TORP (Terminal Offshore Regas Plant) is a 

floating L-shaped terminal that docks onto LNG carriers using a patented friction-based 

attachment system. The HiLoad LNG Regas unit is equipped with LNG unloading arms, pumps, 

and vaporizers and accommodates any LNG carrier. This technology is remotely controlled from 

a support platform. The LNG carrier is moored to a Single Anchor Leg Mooring and the HiLoad 

LNG Regas unit docks to the ship’s hull for unloading. The unit’s regasification equipment has 

a design capacity of 1.4 Bscfd. Capital cost of the HiLoad LNG Regas unit by itself, without any 

connecting pipelines, is estimated to be $400 million. A HiLoad LNG Regas unit is proposed for 

the Gulf of Mexico with anticipated operation in early 2009. A brief description of a second 

project proposed with this technology, as well as the reasons why this technology is not a 

feasible alternative, is provided below. 

Esperanza Energy LLC is proposing use of TORP’s Hi Load Regas unit technology for an LNG 

terminal at a site located 15 miles off the coast of Long Beach, California. A formal application 

is expected sometime in late 2007. One of the shortfalls of the HiLoad LNG Regas technology is 
3-51 3.0 – Alternatives 

its lack of storage capacity. In addition, the technology has not been tested in wave heights 

typical in winter storms off the coast of the Pacific Northwest. Finally, this technology still 

requires a pipeline system having both offshore and onshore environmental effects. Therefore, 

this technology is not a practical alternative to the proposed Jordan Cove terminal. 

3.3.4.2 Conclusions about Offshore Technologies 

The Pacific Ocean off the coast of Oregon is subject to rough weather and high sea states. 

ABSG compared three wave characteristics (i.e., maximum significant wave heights, average 

significant wave heights, and average wave periods) for Oregon, the Gulf of Mexico, and 

Massachusetts. Relative to all three of these wave characteristics, conditions are less favorable 

for an LNG import terminal off the Oregon coast compared to the other regions. The coastline in 

this area provides no islands, reefs, or prominent headlands for protection from rough seas or 

adverse weather (ABSG 2006). 

Of the offshore technologies discussed above, the transport/regasification vessel alternative 

(Excelerate’s Energy Bridge technology) is the only one that would not be affected by rough sea 

conditions. For the other three technologies, LNG carriers would be able to unload only during 

calm sea conditions, thus leading to substantial operational limitations. While 

transport/regasification vessels would perform well in rough seas and weather, they generally 

have lower regasification rates (e.g., 0.5 Bscfd), require specially modified ships, and have no 

storage capabilities. These kind of offshore LNG import terminals, such as the concept for the 

Pacific Gateway project, are targeted for spot market deliveries, and not for long-term storage 

and constant delivery as contemplated by Jordan Cove. 

Locating an LNG terminal on an offshore fixed platform may have impacts on the ocean bottom 

and affect aquatic habitat. A GBS would need to be constructed onshore and then towed out to 

sea. The onshore graving dock for constructing the GBS would have associated environmental 

impacts that the other offshore technologies would not have. These might include impacts on 

terrestrial wetlands, wildlife and vegetation, and cultural resources. 

The kind of vaporizers used at an offshore LNG terminal would influence the kind of impacts the 

facility may have on the aquatic environment. For example, ORVs that use seawater may entrap 

or entrain small aquatic species and ichthyoplankton during intake. Further, once the water is 

run through the ORVs, it would be cooled, with the discharge changing sea temperature and 

perhaps impacting marine life and water quality. ORVs were proposed for the Port Pelican and 

Gulf Landing offshore LNG terminal projects in the Gulf of Mexico. However, neither of these 

projects is moving forward; as indicated above, the Port Pelican Project has been put on hold 

indefinitely, and Shell recently announced it was discontinuing plans for the Gulf Landing 

terminal off the shore of Louisiana (Reuters 2007). 

An offshore LNG import terminal alternative would avoid some of the environmental impacts of 

the proposed Jordan Cove terminal, such as effects associated with LNG marine traffic up the 

Coos Bay waterway, conflicts with existing commercial and recreational users of the waterway, 

potential impacts on communities along the waterway, visual effects, and impacts on aquatic 

resources and water resources related to the dredging of the access channel and slip. However, 

an offshore LNG import terminal would still require a sendout pipeline that would be longer than 

the one proposed by Pacific Connector in order to reach the target markets in northern Nevada 

and northern California. That sendout pipeline would have associated impacts on aquatic and 

terrestrial resources. We do not consider an LNG terminal off the coast of Oregon to be a viable 
3-52 3.0 – Alternatives 

alternative to the proposed project because of the rough sea and weather conditions and the 

additional environmental impacts associated with the longer sendout pipeline. 

3.4 PIPELINE ALTERNATIVES 

We assessed whether it might be possible to reduce environmental impacts associated with the 

construction and operation of the proposed Pacific Connector pipeline by following alternative 

routes. We evaluated major route alternatives that would have similar start and end points as 

portions of the proposed pipeline, but differ significantly for long portions of the route. We also 

evaluated minor route variations along specific segments of the proposed route to avoid or 

minimize impacts on specific, localized resources such as mature forest habitat, waterbodies, 

wetlands, cultural resources, or residences. Lastly, we considered if there were alternative 

locations for major aboveground facilities associated with the pipeline, such as the proposed 

compressor station, that would have lesser environmental impacts. Pipeline alternatives that we 

considered but eliminated from further analysis are listed in table 3.4-1 and discussed below. 

Pipeline alternatives that we considered and analyzed in further detail are listed in table 3.4-2 and 

discussed in section 3.4.2. 

TABLE 3.4-1. 

Pipeline Alternatives Considered but Eliminated from Further Analysis

Alternative Name Segment 

Coos County pipeline route 1A-1, 1A-2, 1A-2B, 1A-4, 1A-8B 

State Highway 42 1B, 1B-21 1B-2 

Powers Highway/Shasta Coster Road 1-C 

Williams Northwest, Grants Pass lateral 2A, 2A-1, 2A-2, 2A-3, 2A4-C 

Cow Creek 1B-5 

State Highway 138/GEN 3-A 

BPA powerline corridor 

Highway 227 3B 

Riddle to Butte Falls 

Grants Pass to Medford 3C-A, 3C-B, 3D, 3D-2, 3D3 

Butte Falls Highway and Highway 140 3B-1, 3B-3b-1 

Medford East 3B-2, 2C-1, 3C-4A, 3C-4B, 3C-3, 3C-6 

Butte Falls East 3B-6, 3B-7, 3B-8, 3B-9 

TABLE 3.4-2 

Pipeline Alternatives Considered and Analyzed in Detail

Alternative Name Section of EIS 

Begin 

Milepost End Milepost 

Length 

(miles) a/

Coos Bay Route Variations 3.4.2.1 0 8 9.4 – 13.37 

Blue Ridge Variations 3.4.2.2 9 22 13.63/14.53/15

.83 

Big Creek/Spirit Mountain Variations 3.4.2.3 36 39 3.08 /3.20 

Deep Creek Variation 3.4.2.4 46 48 1.8 

Camas Valley East Variations 3.4.2.5 51 53 2.7/2.8 

Olalla/Dillard Variation 3.4.2.6 57 67 9.8 

Miller Variation 3.4.2.7 59 60 1.0 

Hoover Hill Variation 3.4.2.8 61 61 - 

Mc Connell Variation 3.4.2.9 69 69 0.1 

Wood Creek/Days Creek Variation 3.4.2.10 82 89 5.3 
3-53 3.0 – Alternatives 

TABLE 3.4-2 

Pipeline Alternatives Considered and Analyzed in Detail

Alternative Name Section of EIS 

Begin 

Milepost End Milepost 

Length 

(miles) a/

Oregon Women's Land Trust Variation 3.4.2.11 85 86 1.0 

Umpqua National Forest Variations 3.4.2.12 105 112 6.4 

Rogue River Crossing Variation 3.4.2.13 122 122 0.1 

C-2 Cattle Company Variation 3.4.2.14 144 145 0.9 

Robertson Butte to Burton Butte/Forest Roads Variations 3.4.2.15 155 169 12.9/15.7 

Pacific Crest Trail Variation 3.4.2.16 167 168 0.6 

Buck Lake/Keno Road, and Clover Creek Road Variation 3.4.2.17 169 190 18.7/ 16.9 

a/ Lengths do not correspond to the difference between beginning milepost and end milepost, because the mileposts refer to the 

original baseline route. 

3.4.1 Alternative Pipeline Route Segments Considered but Eliminated from Detailed 

Analysis 

During the initial phase of the routing process, Pacific Connector attempted to identify potential 

corridors for the pipeline between the proposed Jordan Cove LNG terminal at Coos Bay and the 

proposed pipeline terminus near Malin, Oregon. The goal was to determine if there were 

existing rights-of-way, such as roads, railroads, pipelines and powerlines that could be paralleled 

by the proposed pipeline. More than 1,000 miles of route segments were reviewed. Criteria 

used during the route selection process included: 

• Utilization of existing rights-of-way corridors; 

• Minimization of the length of the pipeline; 

• Avoidance of towns, population centers, commercial areas, and residential subdivisions; 

• Avoidance of known designated sensitive natural resource areas, including national 

parks, wild and scenic rivers, scenic byways, wilderness areas, and ACECs; 

• Reduction of the number of waterbody and wetland crossings; 

• Avoidance of unstable geological areas, where there may be steep slopes, potential for 

landslides, or other issues that would make it difficult to install a natural gas pipeline; 

• Maximizing ridgeline alignments where possible in rugged topography; and 

• Construction feasibility, buildability, and stability for a large diameter underground 

welded steel pipeline, including the location of TEWAs. 

During scoping, some commentors raised the question as to whether it would be possible to route 

the pipeline entirely on federally owned land to avoid impacts on private property. Given the 

patchwork nature of federal land holdings in southern Oregon, with federal blocks scattered 

between private tracts, there is no route that could be identified between Coos Bay and Malin 

that would not cross private lands. Likewise, there are no alternatives that would not cross the 

Coast, Cascade, and Klamath Mountain ranges, and avoid forest. Using a route that followed 

U.S. Highway 101 north from North Bend to Reedsport, then east along State Highway 38 to I-5 

northwest of Drain was not considered, because this route would be in a direction too far north 

away from the proposed pipeline terminus near Malin. All route alternatives considered go 

southeast from Coos Bay. Another suggestion during scoping was to follow the I-5 corridor. 

Again, that corridor would only go part of the way between Coos Bay and Malin, but using the I5 corridor is discussed as part of several alternative routes considered below. 
3-54 3.0 – Alternatives 

The preliminary routes considered and then eliminated from further study by Pacific Connector 

are shown on figure 3.4-1. The figure and segment numbering are derived from environmental 

Resource Report 10 in Pacific Connector’s September 2007 application to the FERC. Segments 

1A, 1B, and 1C are alternative routes between Coos Bay and I-5. Segment 2A would parallel the 

I-5 corridor from Roseburg and Grants Pass, while Segment 3D would follow the I-5 corridor 

between Grants Pass and Medford, and Segment 3C-4A would parallel I-5 between Medford and 

Ashland. Segments 3A, BPA, 3B, 3C-3, 3C-4B, and 3C-6 are alternative routes located east of I5. The reasons why various alternative route segments were rejected as infeasible or undesirable 

by Pacific Connector are discussed below. We found Pacific Connector’s reasons for not further 

considering the preliminary route alternatives mentioned below to be convincing. Instead, we 

concentrated our pipeline route alternatives analysis on segments that may be feasible to 

construct and operate, and alternative routes that were raised by the public and government 

agencies for further discussion. 

3.4.1.1 Coos County Pipeline Route (Alternative Route Segments 1A-1, 1A-2, 1A-2B, 

1A-4, and 1A-8b) 

The Coos County pipeline provides gas service to the cities of Coos Bay and North Bend, 

Oregon from Williams Northwest Grants Pass lateral near Roseburg, Oregon. Initially, it 

appeared logical to follow this existing pipeline as a route between Coos Bay and Roseburg. 

Heading east from Coos Bay, this route segment would follow the old Coos Bay Wagon Road 

through the community of Sumner (now called Coos Sumner Lane). It would then follow a BPA 

powerline between Fairview and McKinley. East of Dora, the Coos County pipeline is laid in 

the roadbed of the Coos Bay Wagon Road through Brewster Canyon paralleling the East Fork of 

the Coquille River. Following field review of this potential route, it was determined that it 

would be infeasible to construct the Pacific Connector pipeline following the Coos County 

pipeline route because: 

• At its northwestern end, this route would run through residential and commercial areas in 

Coos Bay and Libby; 

• The existing pipeline alignment in Brewster Canyon is located in the “cut” portion of the 

Coos Bay Wagon Road immediately adjacent to the borrow ditch. The road is narrow 

and bounded by steep canyon walls (many with exposed bedrock) and the East Fork of 

the Coquille River; 

• Construction of the Pacific Connector pipeline along the Coos Bay Wagon Road would 

need to be done using stovepipe techniques that are time-consuming and expensive; 

• The sinuous character of portions of the road would require numerous factory bends for 

the pipeline. There is also a fiber-optic cable co-located in the road, further encumbering 

construction activities; 

• The road may need to be widened in places, with cutting and blasting of bedrock at 

currently exposed slopes. It may be difficult to stabilize the adjacent hillsides; and 

• Installation of the new pipeline would require the closing of the Coos Bay Wagon Road 

to traffic for extended periods, and the existing Coos County pipeline would need to be 

taken out-of-service, removed, and replaced in certain locations. 
3-55 3.0 – Alternatives 

Figure 3.4-1. Major Alternative Segments 
3-56 3.0 – Alternatives 

Alternative route segment 1A-8b was eliminated from further consideration because Pacific 

Connector did not believe it was feasible to do an HDD under Coos Bay parallel to the existing 

10-inch and 12-inch diameter natural gas pipelines. Limited workspace was available in this 

area, and the proposed alternative segment would pass through populated neighborhoods in the 

cities of North Bend and Coos Bay, requiring at least 0.8 mile construction in city streets. The 

City of North Bend filed a letter with the FERC opposing any route through residential areas. 

3.4.1.2 State Highway 42 (Alternative Route Segments 1B, 1B-1, and 1B-2) 

During preliminary route review, following State Highway 42 between Coos Bay and Roseburg 

was considered, and then eliminated from further analysis due to construction feasibility, cost, 

and significant environmental impacts. The highway heads west from I-5 near Roseburg, 

through the communities of Winston, Tenmile, Camas Valley, Remote, Bridge, Myrtle Point and 

Coquille. Highway 42 is a high volume, major access and truck route from I-5 to the coast. This 

route was rejected because: 

• The Middle Fork of the Coquille River is adjacent to the highway for much of the route. 

Steep side slopes prevent offsetting the pipeline from the highway, which means the 

pipeline would need to be installed in the roadbed in places; 

• In-highway construction would create a public safety issue and impede traffic for a 

substantial period of time; 

• Fiber optic cables are buried along the highway right-of-way, creating another restriction 

to installing the pipeline in or near the highway; 

• The Coquille River would be crossed multiple times (six or more); 

• There would be potential impacts on residential and commercial areas in the towns along 

this route; and 

• The route would cross through several parks and waysides. 

3.4.1.3 Powers Highway/Shasta Costa Road (Segment 1-C) 

Segment 1-C would follow an existing road network between Coos Bay and Grants Pass, 

Oregon. From Myrtle Point, the Powers Highway goes south to the community of Powers, then 

Powers South Road proceeds south to Agness, where the Shasta Costa Road heads west, to the 

Galice Creek Road to Galice. However, because of the following factors, this segment was 

eliminated from further analysis:

• Significantly increases overall pipeline length; 

• Parallels the South Fork of the Coquille River between Myrtle Point and Agness; 

• Crosses the Rogue River within an area designated as a Wild and Scenic Waterway; 

• Skirts the Wild Rogue Wilderness Area within the Siskiyou National Forest north of 

Agness; and 

• Constructability issues due to rugged topography and narrow river canyons. 
3-57 3.0 – Alternatives 

3.4.1.4 Williams Northwest Grants Pass Lateral Route (Alternative Route Segments 2A, 

2A-1, 2A-2, 2A-3 and 2A4-C) 

During initial route selection, Pacific Connector assumed that it could follow the existing 

Williams Northwest Grants Pass lateral parallel to I-5 between the cities of Roseburg and Grants 

Pass. However, upon review, this route was eliminated because: 

• Large volumes of rock would need to be removed to install a new pipeline along the 

ridges and through canyons following the lateral route; 

• The lateral is installed along narrow ridgelines in areas with steep slopes that would 

hinder the co-location of a new pipeline in the existing easement because of limited 

available workspace; 

• To avoid buildability issues in difficult terrain, several route realignments off of the 

existing lateral would be necessary, that may result in multiple crossings of I-5; 

• Locating the pipeline within the existing I-5 right-of-way was not thought feasible 

because construction may impede traffic, and there are restrictions on placing utilities 

within federal highway easements; and 

• There are commercial and residential areas along the I-5 corridor between Roseburg and 

Grants Pass, developed after the lateral was installed in 1963, that would need to be 

avoided by a new pipeline. 

3.4.1.5 Cow Creek Route (Alternative Route Segment 1B-5) 

Pacific Connector examined the possibility of following Cow Creek between the Camas Valley 

and I-5 south of Glendale, as a route alternative rather than a route parallel to the Grants Pass 

lateral. Alternative Route Segment 1B-5 could potentially provide this connection and shorten 

the route, but there is no existing right-of-way all the way through this area. The alternative 

could follow Burma Road south from the Camas Valley, then go cross-country to the existing 

Central Oregon Railroad and Riddle-Glendale Road adjacent to Cow Creek. This route 

alternative was rejected for the following reasons: 

• There is no existing right-of-way along the entire alternative, and the pipeline would need 

to blaze a new “green-field” cross-country route between Burma Road and RiddleGlendale Road; 

• Rugged topography would make construction difficult; 

• An open-cut crossing of Cow Creek would be necessary, due to geometric conditions on 

either side of the waterbody; 

• McCullough Creek would be closely paralleled for more than a mile within a steep 

narrow drainage, that would likely require that the pipeline be installed within an existing 

road; 

• Additional construction constraints with this route include exposed rock and limited 

available access; and 

• This alternative route segment would bisect a large area (20 miles) of critical habitat for 

NSO (OR-62). 

3.4.1.6 State Highway 138/GTN Route (Alternative Route Segment 3-A) 

Pacific Connector examined an existing road and pipeline corridor between Roseburg and Malin 

that it labeled Segment 3-A. This alternative route would follow State Highway 138 from 
3-58 3.0 – Alternatives 

Roseburg east, passing by the communities of Glide, Steamboat, and Diamond Lake to I-97, then 

follow the existing GTN pipeline south, passing by Bonanza to Malin. This route alternative was 

eliminated for the following reasons: 

• Increased the length of the pipeline compared to the proposed route; 

• State Highway 138 is adjacent to the North Umpqua River, which has been designated as 

a Scenic Byway and Scenic Waterway; 

• Extensive clearing and sidehill cutting necessary to install the pipeline would have visual 

impacts through areas of high recreational and scenic value; 

• The North Umpqua River is used for whitewater rafting and fishing, with numerous 

access to trails and campgrounds located off of State Highway 138; 

• Crosses a significant number of high-value tributaries that flow to the North Umpqua 

River; 

• Route along State Highway 138 would be close to the Boulder Creek Wilderness and the 

Mount Thielsen Wilderness within the Umpqua National Forest; and 

• Located in proximity (< 0.25 mile) to Crater Lake National Park. 

3.4.1.7 BPA Powerline Corridor Route Alternative 

During initial routing investigations, Pacific Connector evaluated following the existing BPA 

powerline corridor between Myrtle Creek and Medford. However, this route was determined to 

be infeasible and dropped from further consideration because the powerline spans severe side 

slopes and dissected topography that would require significant grading as well as increased cost 

for pipeline construction. Pipeline operation, maintenance and integrity issues were also a 

concern with this route. 

3.4.1.8 Highway 227 Route (Alternative Route Segment 3B) 

This alternative route would follow Highway 227 east of I-5 from Canyonville through the 

communities of Days Creek, Milo, Tiller, and Trail, to Shady Cove. This route was eliminated 

from serious consideration due to the following limitations: 

• Numerous residences are located along the highway, especially in the vicinity of the 

communities of Canyonville, Days Creek, and Shady Cove; 

• Steep canyon walls in the area between Trail, Drew, Tiller, and Milo would require that 

the pipeline be installed in the roadbed in places, creating a public safety hazard during 

construction and causing travel delays; 

• Extensive cuts would be necessary where the pipeline would be installed adjacent to but 

outside of the roadbed; 

• Substantial amounts of exposed rock are present along the route, affecting construction 

costs and schedules; and 

• This route would require several waterbody crossings including potentially eight 

crossings of the South Umpqua River, as well as Elk Creek and Trail Creek. 

3.4.1.9 Riddle to Butte Falls Route Variation (Sebesta Alternatives) 

In a letter dated March 20, 2007, Paul Sebesta suggested alternative routes between about MPs 

70 to 132, between Riddle and Butte Falls. In a June 2, 2008 data request, we asked Pacific 

Connector to evaluate Mr. Sebesta’s suggested route alternatives. In a response filed on June 23, 

2008, Pacific Connector indicated that these alternative routes were previously considered in its 
3-59 3.0 – Alternatives 

application, within Resource Report 10, under the BPA Powerline Route Alternative and the 

Highway 227 Route Alternative. As explained above, the BPA Powerline Route Alternative 

between Days Creek and Medford was eliminated from further study because it would not be 

feasible to follow the powerline due to dissected topography. The Highway 227 Alternative 

Route (Segment 3B) between Canyonville and Shady Cove was eliminated from consideration 

because it would pass through several communities and has the potential impact rural residences. 

One of Mr. Sebesta’s alternative routes would place the pipeline too close to the COE’s Lost 

Creek Lake Dam, which Pacific Connector thought would not be viable. 

3.4.1.10 Grants Pass to Medford Routes (Alternative Route Segments 3C-A, 3C-B, 3D, 

3D-2, and 3D3) 

Pacific Connector examined several different alternative route combinations trying to find a link 

between its Segments 1B-5 and 1C west of I-5 and the Williams Northwest Grants Pass lateral 

corridor heading east to Medford. The 3C segments would leave I-5 south of Glendale. It appears 

that Segment 3C-A would follow Placer Road west from Sunny Valley, while Segment 3C-B would 

follow Jump-off Joe Creek Road west from Oxyoke to Winona. It appears that Segment 3C would 

continue east from the Josephine/Jackson County line along Ditch Creek Road to Evans Creek Road 

north of Starvation Heights. Segments 3C, 3C-A, and 3C-B were eliminated from further 

consideration by Pacific Connector because they would pass through populated or developing areas 

in Jackson County in the vicinity of the communities of White City, Eagle Point, and Wimer. Pacific 

Connector wanted to avoid congested residential areas, and it could not find a feasible way to link 

these alternative segments with portions of the proposed route either to the west or east. The 3D 

segments would parallel I-5 heading southeast from Grants Pass, passing by the communities of 

Rogue River, Rocky Point Gold Hill, Central Point, Jacksonville, Phoenix, and Talent. This route 

would be adjacent to the Rogue River, and would be in the vicinity of the Valley of the Rogue State 

Recreation area east of the community of Rogue River, and the Ben Hur Lapman State Scenic 

Corridor south of Gold Hill. There are numerous residential and commercial areas along these 

segments. It would not be feasible to install the proposed pipeline within the existing I-5 right-ofway because construction could impede traffic, and there are restrictions imposed by the Federal 

Highway Administration that exclude utilities from federal highway easements and access. 

3.4.1.11 Butte Falls Highway and Highway 140 Routes (Alternative Route Segments 3B-1 

and 3B-3b-1) 

North of Medford, Pacific Connector considered alternative routes that followed the Butte Falls 

Highway and Highway 140 in a southeasternly direction. These alternatives were rejected because 

they were longer than the proposed route, and there are numerous houses along the highways, 

especially in the vicinity of the community of Butte Falls, along the South Fork of Butte Creek, 

and near Derby along the South Fork of Reese Creek. 

3.4.1.12 Medford East Routes (Alternative Route Segments 3B-2, 3C-1, 3C-4A, 3C-4B, 

3C-3, and 3C-6) 

Pacific Connector evaluated various potential routes heading east of I-5 from the vicinity of 

Medford. Segments 3B-2 and 3C-1 would skirt the east side of Medford, from Butte Falls Road 

south to Talent. A number of existing roads could be followed in this area, including Reese Creek 

Road south from Butte Falls Road, to Bickham and Brown Roads, Foothill Road, and North 
3-60 3.0 – Alternatives 

Phoenix Road. This route would be near the Agate Lake Recreation Area south of Highway 140. 

There are numerous residential and commercial areas along these route segments. 

Segment 3C-4A is shown on the north side of I-5 between Medford and Ashland. It was 

eliminated from further study because it would pass through populated and developing areas in the 

vicinity of the communities of Ashland, Talent, Phoenix, Medford, and Central Point. It would 

also cross through a number of orchards and specialty crops. Segment 3C-4B would follow Dead 

Indian Memorial Highway east from Ashland to Keno Road. Segment 3C-3 would follow Green 

Springs Highway No. 22 (State Route 66) eastward from south of Ashland, passing by the small 

communities of Lincoln, Mt. View, Pinehurst, and King Cole. This route would be in the vicinity 

of Emigrant Lake, Tub Springs State Wayside, and Cascade Siskiyou National Monument. 

Segment 3C-6 would continue east along Green Springs Highway to Keno, crossing the Klamath 

River along the way. Alternative route segments 3C-3, 3C-4B, and 3C-6 were also eliminated 

from further consideration by Pacific Connector in order to avoid residential and commercial areas. 

3.4.1.13 Klamath Falls East Routes (Alternative Route Segments 3B-6, 3B-7, 3B-8, and 

3B-9) 

During initial route selection, Pacific Connector evaluated numerous potential routes for the 

southeastern end of the pipeline. Segment 3B-6 heads east from I-97, south of the city of Klamath 

Falls. There are several existing roads that could be followed, including Cross Road to Dehlinger 

Lane to Crystal Springs Road. Segment 3B-7 would continue eastwardly following Poe Valley 

Road and the existing Klamath Falls Lateral. The existing pipeline route (3B-7) traverses steep 

slopes with surface rock. Segment 3B-9 would follow Highway 39 east from Merrill, then parallel 

the Klamath Falls – Malin Highway and the existing Northern Santa Fe Railroad corridor to Malin. 

This alternative would go through residential and commercial areas. Pacific Connector selected 

the proposed route between Klamath Falls and Malin because it would maximize the use of 

existing pipeline and powerline corridors, avoid residential areas, and the Kingsley Airport, and 

avoid steep slopes with exposed bedrock. The proposed pipeline route is also shorter than the 

alternative routes. 

3.4.1.14 West-wide Energy Corridor Routes 

We received comments that the EIS should evaluate routes established by the DOE and BLM in 

the Programmatic Environmental Impact Statement, Designation of Energy Corridors on Federal 

Land in the 11 Western States (DOE 2008). These corridors are commonly referred to as the 

West-wide Energy Corridors. The final EIS for the West-wide Energy Corridors identified only 

one corridor in the Project area, which consists of the BPA powerline between Roseburg and 

Medford, and discontinuous segments of the powerline and Northwest Pipeline’s Grants Pass 

Lateral north of Roseburg. The West-wide Energy Corridors final EIS identified no west-east 

corridors in the Project area. The West-wide Energy Corridors in the Project area are evaluated 

above as the Williams Grants Pass Lateral Route Alternative (section 3.4.1.4) and the BPA 

Powerline Corridor Route Alternative (section 3.4.1.7). These alternatives were eliminated from 

detailed analysis in this EIS. 

3.4.2 Pipeline Route Variations 

During finalization of the proposed pipeline route, a number of route variations were identified by 

Pacific Connector, either as a result of more detailed analysis of existing data, results of field 

analysis, or requests from landowners. Route variations were identified in an effort to avoid or 
3-61 3.0 – Alternatives 

minimize potential impacts on specific localized resources, including residences, timber, 

waterbodies, and sensitive habitats. In addition, members of the public and government land 

managing agencies suggested pipeline route alternative segments that we believed warranted 

further analysis. We examined a number of these route alternatives using desktop data, to 

determine if any had clear environmental advantages over the proposed routes. Where possible, 

Pacific Connector conducted on-the-ground studies of alternative routes. Elements we considered 

during these analyses included pipeline length, use of existing rights-of-way, forest clearing, 

agricultural land, waterbody and wetland crossings, residences, known cultural resources, habitat 

for federally listed threatened or endangered species, and geological hazards and slope stability. 

In the draft EIS we recommended several route variation segments as environmentally preferable 

to the route filed by Pacific Connection in its September 2007 application. In its December 4, 

2008 comments on the draft EIS, Pacific Connector stated that it revised its proposed route and 

incorporated the pipeline route variations recommended in the draft EIS. The accepted route 

variations are now part of the proposed route, and the corresponding September 2007 application 

route segments are analyzed below as alternative variations in this final EIS. In a January 21, 2009 

filing, Pacific Connector provided additional environmental information comparing the newly 

proposed pipeline route segments with the alternative route variations, and these data are 

summarized below. The route segments that changed between the draft and final EIS and have 

been adopted as the currently proposed route are listed in table 3.4.2-1. 

TABLE 3.4.2-1 

Variations from the Draft EIS Adopted into the Proposed Route for the Pacific Connector Pipeline a/

Mileposts Draft EIS Route Variation Reasons Variation Adopted 

0.0 to 11.36 Coos Bay Route Variation WC1A-2A Avoids impacts on aquatic resources and cultural resource of the inwater route alternative in Coos Bay, in accordance with 

recommendation 22 in the draft EIS. 

29.78 to 30.08 Crossing of the East Fork Coquille 

River 

Avoids marbled murrelet (MAMU) habitat and MAMU Stands G46 and 

G47. 

30.34 to 30.71 Reduces impacts on MAMU Stand G50. 

31.70 to 32.33 Reduce impacts on MAMU Stand C3088 

36.10 to 36.29 Big Creek/Spirit Mountain Variation Reduce impacts on MAMU Stand B07. 

45.24 to 45.70 Reduce impacts on MAMU Stand C3070 

51.54 to 52.06 Southern Route Variation Avoid impacts on MAMU Stands R2027 and B12 in accordance with 

recommendation 23 in the daft EIS. 

57.84 to 57.92 Avoids populations of Kimcad’s lupine in accordance with 

recommendation 39 in the draft EIS. 

85.37 to 86.46 Oregon Women’s Land Trust 

Variation 

In accordance with recommendation 25 in the draft EIS. 

95.05 to 95.60 Reduces impacts on old growth forest and northern spotted owl (NSO) 

nest patch 094-8 in accordance with recommendation 36 in the draft 

EIS. 

108.57 to 

110.94 

Peavine Route Variation Avoids Peavine Quarry and NSO nest patch, as requested by USFS in 

November 19, 2008 letter, and in accordance with recommendation 26 

in draft EIS. 

127.35 to 

128.58 

Reduces impacts on old growth forest within NSO range, in 

accordance with recommendation 36 in the draft EIS. 

144.20 to 

145.13 

C-2 Cattle Company Variation Avoids irrigated fields and conservation easements on the C-2 Ranch, 

in accordance with recommendation 27 in the draft EIS. 

161.09 to 

161.55 

Big Elk NSO Variation Avoids impacts on Big Elk NSO next patch, as requested by USFS in 

November 14, 2008 letter, and in accordance with recommendation 36 

in the draft EIS 
3-62 3.0 – Alternatives 

TABLE 3.4.2-1 

Variations from the Draft EIS Adopted into the Proposed Route for the Pacific Connector Pipeline a/

Mileposts Draft EIS Route Variation Reasons Variation Adopted 

167.67 to 

168.17 

Pacific Crest Trail Variation Reduces visual impacts on PCT, as requested by USFS in November 

14, 2008 letter, and in accordance with recommendation 28 in the draft 

EIS. 

171.10 to 

187.40 

Clover Creek Road Variation Reduces impacts from side hill construction, as requested by USFS in 

November 26, 2008 letter, in accordance with recommendation 29 in 

the draft EIS. 

195.45 to 

196.52 

Avoids impacts on populations of Applegate milk-vetch, in accordance 

with recommendation 37 in the draft EIS. 

a/ These variations are incorporated into the proposed route and evaluated in this final EIS as the proposed route. 

3.4.2.1 0.0 to 11.35 - Coos Bay Route Variations (In-Water Route, WC-1, WC-1A, WC2, WC-3, WC-4, WC-5, and WC-6A) 

The draft EIS considered several route alternatives that could be followed to take the pipeline 

from the proposed Jordan Cove LNG terminal to the southeastern side of Coos Bay. In its 

comments on the draft EIS Pacific Connector also identified a modification to a route alternative 

evaluated in the draft EIS. Route alternatives in the Coos Bay area that are evaluated in detail in 

this final EIS are shown on figure 3.4-2. 

Route Variation WC-1 (also called the “Land Route”) was the original pipeline route identified 

by Pacific Connector in its first draft environmental Resource Reports filed in May of 2006 

during the FERC’s NEPA Pre-filing phase. This variation would have crossed Haynes Inlet 

from the North Spit using an HDD just north of the U.S. Highway 101 McCullough Bridge. It 

would have continued eastward over the Glasgow peninsula, turned south to cross Kentuck 

Slough and the Kentuck Country Club golf course, over Villanch Slough, and through the lower 

portion of Echo Valley to Graveyard Point and the currently proposed crossing of the Coos 

River. 

Dr. Steven Shimotakahara, a resident of the neighborhood of Glasgow Heights, filed a letter 

dated June 27, 2006 proposing two potential alternative routes. One alternative would go up 

Haynes Inlet making landfall at an unpopulated portion of North Bay Drive beyond Route WC-1 

MP 2. The second alternative would place the pipeline in the mudflats on the east side of the 

Coos Bay estuary south of the Glasgow peninsula. Pacific Connector incorporated Dr. 

Shimotakahara’s first suggested alternative in its Route Variation WC-1A filed February 14, 

2008. The second suggested alternative was incorporated into Route Variation WC-2 as shown 

in Resource Report 10 of Pacific Connector’s application. 

Pacific Connector eliminated Route Variations WC-2 and WC-3 from further study because 

these alignments on the east side of the Coos Bay estuary would go through commercial oyster 

leases. These route variations would also impact eelgrass beds in the bay. Additionally, it was 

thought that where Route Variations WC-2 and WC-3 would traverse across the mouths of 

Kentuck and Willanch Sloughs, respectively, would have a high potential for archaeological 

resources. 

 
3-63 3.0 – Alternatives 

Figure 3.4-2 Coos Bay Alternatives 
3-64 3.0 – Alternatives 

Route Variations WC-4 and WC-5 on the east side of the Coos Bay estuary were also eliminated 

from further consideration by Pacific Connector because these alignments would impact oysters 

and eelgrass beds. WC-5 was aligned along the Ross Slough floodplain and that alternative 

would cross the slough seven times. It was also thought that these route variations had the 

potential to affect unrecorded cultural resources and would encounter shallow groundwater. 

As a result of comments received during the Pre-filing scoping process concerned about Route 

Variation WC-1’s potential impacts on residential areas, and difficulties Pacific Connector would 

have in executing a HDD under Haynes Inlet, the company changed the route in its September 

2007 application to place the pipeline in Coos Bay between about MPs 0.5 and 7.5. The 

September 2007 route segment in Coos Bay was called the “proposed route” in the draft EIS, and 

is referred to as the “in-water” route variation in this final EIS. 

In a letter dated November 11, 2007, the Coquille Tribe requested that we analyze another route 

alternative on the west side of the Coos Bay estuary, south of the in-water route between MPs 4 

and 8. The tribe claims that a route on the west side of the bay, south of the in-water route, 

would have less impacts on known Native American fishing weir archaeological sites. Pacific 

Connector provided information on that route, called Route Variation WC-6A, filed February 14, 

2008. The Coquille Tribe indicated to Pacific Connector that either Route Alternatives WC-6A 

or WC-1A would satisfy the tribe’s concerns, and were preferred over the in-water route. 

In a letter dated March 29, 2008, Richard Heaney stated his opposition to Route Variation WC6A, claiming it would impact a residential area of the city of Coos Bay, cross three roads 

including an Oregon State Highway, cut rock above a new bridge approach, potentially breech a 

road dike, and cross reclaimed tidelands with high water tables. Mr. Heaney suggested an 

alternative route that would follow the existing Bonneville powerline right-of-way. In a data 

request dated June 2, 2008, we asked Pacific Connector to evaluate Mr. Heaney’s route 

alternative. Pacific Connector responded with a filing on June 23, 2008 that indicated that the 

Heaney alternative route would probably require a 4,000-foot-long HDD under Marshfield 

Channel, Bull Island, and Cooston Channel that may not be geotechnically feasible. The Heaney 

Variation would be almost 0.6 mile longer than Route Variation WC-6A, and would require 

more acres of TEWAs. Pacific Connector stated that the Heaney Variation may be constructible, 

but would be more costly, and more time consuming than Route Variation WC-6A. We do not 

believe that the Heaney Variation is clearly environmentally superior to the other Coos Bay route 

alternatives. 

Responding to recommendation 22 in our draft EIS, Pacific Connector filed a new proposed route 

between MPs 0.0 and 11.35 (which it labeled WC-1A-2A in its filing). This is now the proposed 

route, as discussed below. Environmental variables along the May 2006 land route (Route 

VariationWC-1), the September 2007 in-water route (FERC-filed route), and several other 

alternative route variations are compared to the currently proposed pipeline route in table 3.4.2.1-1. 

The primary advantages of the upland route alternatives, including Route Variations WC-1 and 

WC-1A and the proposed route are that these routes would reduce impacts to aquatic and cultural 

resources in Coos Bay. However, geotechnical studies indicated that it may not be possible to 

cross Haynes Inlet using an HDD along Variation WC-1 (original Land Route) north of the 

McCullough Bridge. Route Variation WC-1 may have other geotechnical problems related to 

slope stability and potential for landslides. Pacific Connector also was concerned about reported 

nesting sites for bald eagles in the vicinity of Route Variation WC-1. Route Variation WC-1 
3-65 3.0 – Alternatives 

TABLE 3.4.2.1-1 

Comparisons of the Proposed Route With Coos Bay Route Variations

Alternatives 

Analysis 

In-Water 

Route 

Variation* 

WC-6A 

Variation Heaney Variation 

WC-1A 

Variation 

WC-1 

Variation 

(Land Route) 

Proposed 

Route (MP 

0.0 – 11.36) 

General 

Length (miles) 9.68 a/ 9.40 9.98 13.11 12.07 13.37 

Estuary Crossing 

Length (miles) 

6.87 5.99 6.51 2.07 Similar to WC1A 2.48 

Construction 

Right-of-Way 

(acres) b/

245.8 220.8 227.5 b/ 189.9 b/ 77.66 196.95 

TEWAs (acres) 179.0 Not designed but 

expected to be 

similar to the inwater route. 

Not designed but 

expected to require 

more than the in-water 

route. Would require 

TEWAs for HDD 

crossings of Marshfield 

Channel, Bull Island, 

Cooston Channel to 

Grave Yard Point. 

TEWAs would also be 

required along the BPA 

powerline in the Coos 

River floodplain 

because of wetland and 

saturated soils. 

TEWAs for offshore portion 

of alternative 

not designed 

but would be 

less than the 

in-water route 

based on 

length. Approx 

34.11 acres of 

TEWAs would 

be require for 

land portion. 

231.11 204.8 

Permanent 

Easement 

(acres) c/

82.6 89.8 d/ 84.5 96.0 104.0 81.03 

Number of 

Landowner 

Parcels Crossed 

19 26 18 50 53 46 

Number of 

Residences 

within 50 feet of 

Construction 

Right-of-Way e/, 

f/, g/

0 2 e/ 1 f/ 1 g/ 2 3 

Land Ownership (miles) 

2.61 2.89 2.84 10.25 11.25 10.51 

7.07 6.51 7.14 2.86 0.87 2.86 

 Private Land 

 State 

 Federal 0.00 0.00 0.00 0.00 0.00 0 

Geotechnical 

Steep or Difficult 

Terrain (miles) h/

0.00 0.00 0.00 1.38 0.29 1.38 

Highly Erosive 

Soils (miles) i/

0.76 0.38 0.38 4.65 0.77 4.66 

Waterbodies and Wetlands 

Number of 

Waterbodies 

Crossed j/

13 106 15 j/ 19 20 21 

Total Waterbody 

Crossings 

(miles) 

6.20 6.29 6.44 2.20 1.0 2.65 

Number of 

Wetlands 

Crossed 

8 4 (NWI) 6 (NWI & Jones and 

Stokes) 

8 (NWI) 15 14 

Wetland 

crossings (miles) 

1.37 1.58 1.52 0.48 1.39 0.96 
3-66 3.0 – Alternatives 

TABLE 3.4.2.1-1 

Comparisons of the Proposed Route With Coos Bay Route Variations

Alternatives 

Analysis 

In-Water 

Route 

Variation* 

WC-6A 

Variation Heaney Variation 

WC-1A 

Variation 

WC-1 

Variation 

(Land Route) 

Proposed 

Route (MP 

0.0 – 11.36) 

Land Use 

Agricultural 

Lands Crossed 

(miles) 

0.41 1.16 0.96 1.31 1.35 10.32 

Forest Lands 

Crossed (miles) 

0.00 0.00 0.00 4.07 4.90 

Regenerating 

Forest Crossed 

(feet) k/

1.01 0.58 0.58 3.34 1.01 1.01 

Oyster Leases (# 

parcels/total 

feet) l/

1/72.53 2/3,110.47 2/3,110.47 1/3,411.67 Similar to WC1A 0/0 

Miles Parallel or 

Adjacent to 

Existing Rightsof-Way m/

0.73 0.66 1.36 4.4 l/ 5.81 4.8 

Cultural Resources 

Number of 

Previously 

Recorded 

Cultural 

Resources 

2 0 2 1 4 3 

Number of 

Newly Identified 

Cultural 

Resources n/

8 0 0 0 1 0 

Biological Resources 

Eelgrass (acres) 

o/

16.83 Not surveyed; 

expected to be 

similar to inwater route 

Not surveyed; expected 

to be similar to in-water 

route 

Not surveyed Not surveyed 4.48 

Eelgrass (acres) 

o/

(Clinton 2007) 

40.05 19.32 19.32 15.22 Not surveyed 0 

Eelgrass (acres) 

o/

(ODLCD 1998) 

2.81 11.84 11.84 17.17 Not surveyed 14.01 

NSO Suitable 

Habitat Crossed 

(feet) p/

0.00 383.39 383.39 4,385.25 Not surveyed 47.7 

Marbled Murrelet 

Suitable Habitat 

Crossed (feet) q/

0.00 0.00 0.00 0.00 Not surveyed 0 

*Referred to as the proposed route or FERC-filed route in the draft EIS.

a/ Mileage length cannot be calculated by subtracting milepost ranges because of engineering station equations included in route 

segment between MPs 0.00 to 9.68. 

b/ WC-6A, Heaney Variation, and WC-1A construction right-of-way acreage calculations assumed a 95-foot on-shore width and a 

250-foot off-shore width. Construction right-of-way areas that would be associated with HDDs crossings were assumed to be 95 

feet in width for calculation purposes. The construction right-of-way configuration for the current proposed route across Hynes Inlet 

varies between 225 and 300 feet. 

c/ Acres of permanent easement calculated based on crossing length on private and state lands. Pacific Connector proposes a 53-

foot permanent easement on federal lands; a 60-foot permanent easement on private timber lands; and a 75-foot permanent 

easement on private lands. 

d/ The 63.77-acre figure previously submitted was incorrect. 

e/ Two residences are approximately 100 feet from the centerline of WC-6A along the HDD alignment of Catching Slough. 

Although site visit reviews expect the HDD to be feasible, geotechnical studies have not been completed for design purposes. 

f/ One structure (industrial/non-residential) is located along the alignment that would require an HDD crossing between Sec. 25, T. 

25S., R.13W., across the Marshfield Channel, Bull Island and Cooston Channel to Graveyard Point in Sec. 30, T25S., R12W. 
3-67 3.0 – Alternatives 

TABLE 3.4.2.1-1 

Comparisons of the Proposed Route With Coos Bay Route Variations

Alternatives 

Analysis 

In-Water 

Route 

Variation* 

WC-6A 

Variation Heaney Variation 

WC-1A 

Variation 

WC-1 

Variation 

(Land Route) 

Proposed 

Route (MP 

0.0 – 11.36) 

Geotechnical studies have not been completed to determine potential HDD feasibility; however, based on the site visit conducted

for WC-6A, an HDD is likely feasible. 

g/ One residence is located approximate 200 feet from the centerline of WC-1A at the off-shore/on-shore approach. The TEWA for 

staging of these activities has not been designed; therefore, work area requirements may be required within 50 feet of the 

residence. 

h/ Based on Soil Mapping Units that have slopes of 50-75 percent and have a water erosion rating of high or severe. NRCS. 1989. 

Soil Survey of Coos County, Oregon. U. S. Department of Agriculture. 

i/ Based on Soil Mapping Units that have a water erosion rating of high or severe. NRCS. 1989. Soil Survey of Coos County, 

Oregon. U. S. Department of Agriculture. 

j/ Assessment made using Jones and Stokes field surveys for in-water route and where available along WC-6A, WC-6A (Heaney 

Variation) and WC-1A. Waterbody information was supplemented for WC-6A, WC-6A (Heaney Variation) and WC-1A using 2005 

county aerial photo coverage (Surdex); waterbodies from PNW Hydrography Framework Clearinghouse and using USGS 

topographic quads. 

k/ Includes recent clear-cut forests and areas of in-road construction where forest clearing would be reduced. 

l/ Assessment based on number of subtidal land parcels crossed and crossing length. Determination of oyster lease productivity 

has not been determined. 

m/ Assessment made using 2005 county aerial photo coverage (Surdex), BLM and Weyerhaeuser GIS road data. Assessment on 

WC-1A includes mostly private logging gravel or native surface logging roads. 

n/ Cultural resource surveys have not been completed on the entire routes for WC-1A, Heaney Variation and WC-6A. WC-6A can 

still be adjusted during detailed design to avoid, or at the least, minimize impacts to pristine weirs identified in the bay. Upon further 

review and replotting of WC-6A, it appears that this route misses the newly identified sites and is a correction from 1 to 0 newly 

identified sites. 

o/ Based on Clinton 2007 and ODLCD 1998. According to Ellis Ecological surveys in the fall of 2007, the in-water route would 

affect: Low Density = 1.21 ac, Medium Density = 13.58 ac, High Density = 2.04 ac. Total = 16.83 ac. The in-water route would 

also affect 19.88 acres of High Marsh habitat (Bull Island). Alternatives WC-6A, WC-1A (Heaney Variation), and WC-1A would 

avoid High Marsh habitat. 

p/ USFS 2004: PNW-GTR-648. 

q/ Martin et al. 2006; General Technical Report PNW-GTR-65. 

would go through residential areas in the Glasgow and Echo Valley neighborhoods. In a letter 

dated August 15, 2006, the North Bend City Council requested that the pipeline avoid all 

residential areas in the city. Likewise, the Mayor of the City of Coos Bay, in a letter to the 

FERC dated September 29, 2006, requested that the pipeline avoid residentially zoned areas. In 

a filing on July 27, 2006, 14 citizens of the Echo Valley community petitioned the FERC to 

consider an alternative to the original Coos Bay Land Route through their neighborhood. For 

these reasons, we do not find Variation WC-1 to be environmentally superior to the proposed 

route, or to the other Coos Bay route alternatives. 

Route Variation WC-6A would be the shortest of all the Coos Bay alternatives. It would have a 

shorter crossing of the Coos Bay estuary than the in-water route or the Heaney Variation; but not 

as short as Route Variation WC-1A or the proposed route. Route Variation WC-6A would avoid 

Bull Island, and some of the known Native American fish weir archaeological sites in the bay, 

but would require an HDD under Catching Slough for which there is no geotechnical data about 

feasibility. 

Route Variation WC-1A would impact the fewest acres during construction, estimated at about 

224 acres, including only upland TEWAs. In comparison, the in-water route filed with Pacific 

Connector’s application would impact a total of about 425 acres during construction, including 

TEWAs. This assumes a 95-foot-wide construction right-of-way onshore, and a 250-foot-wide 

construction right-of-way in the bay because of extra space needed for vessels to support the lay 

barge. Route Variation WC-1A would impact the most amount of potential NSO habitat, and 

result in the most forest being cleared, but cross the least amount of wetlands. Both Route 

Variation WC1-A and the proposed route would cross difficult upland terrain, with the most 
3-68 3.0 – Alternatives 

erodible soils. According to the 2007 eelgrass study, the proposed route would have the least 

impact on eelgrass in the bay. 

In the draft EIS, we determined that Route Variation WC-1A, would be environmentally 

preferable to the in-water route filed with Pacific Connector’s application, and Route 

Alternatives WC-6A, WC-1, and the Heaney Variation. All of the route alternatives with 

extensive crossings of the Coos Bay estuary (in-water route and Variation WC-6) have the 

potential to impact Native American fishing weir archaeological sites and other aquatic 

resources. Eight weir sites were recorded along the in-water route. Pacific Connector is 

concerned that it may not be able to obtain a negotiated easement with the ODSL for any 

alternative that has an extensive crossing of the Coos Bay estuary. The members of the 

Waterbody Crossing Methodologies Subgroup of the Federal and State Task Force on ESArelated issues for the JCE & PCGP Project appeared to favor Route Variation WC-1A, as it 

would avoid impacts on aquatic resources (including listed species) and cultural resources 

associated with the in-bay alternative routes. Although Route Variation WC-1A would be longer 

than the other alternative Coos Bay routes considered in the draft EIS, it would impact the fewest 

acres during pipeline construction Therefore, we recommended in the draft EIS that Pacific 

Connector incorporate Route Variation WC-1A into its proposed route, 

On December 4, 2008, Pacific Connector filed a revised proposed route between MPs 0.0 and 

11.36 that is similar to Route Variation WC-1A as analyzed in the draft EIS. This new proposed 

route, which Pacific Connector labeled WC-1A-2A, slightly modified the WC-1 Route Variation 

between approximately MPs 0.9 and 3.8 based on several cultural, environmental, and 

construction issues encountered along route variation WC-1A that include: 

• A possible historic Native American cemetery along WC-1A (although the proposed 

route may encounter two previously recorded sites); 

• Construction issues associated with the multiple crossings of existing above and below 

ground utilities and the waste treatment ponds and monitoring wells located along or in 

proximity to the access road utilized by the Project, which WC-1A would follow north of 

MP 1.3; 

• A known population of Point Reyes bird’s-beak (State Endangered species) that occurs 

along the shore where WC-1A entered Haynes Inlet (ORNHIC 2006); 

• Impacts to highly productive silver point oyster beds in Hayes Inlet between MPs 1.9 and 

2.5; and 

• Minimization of impacts to high-density eel grass beds suspected to be present within the 

oyster leases. 

The proposed route alignment modification on the north spit between approximately MPs 0.9 

and 2.4 basically follows the original land route (variation WC-1). Pacific Connector consulted 

with Clausen Oysters as well as the Port of Coos Bay about the modification to the WC-1A route 

variation. Although this route would avoid direct effects to the oyster beds, Clausen Oysters has 

expressed concerns about the potential for turbidity from pipeline installation in the bay between 

MPs 1.7 and 4.1 along the proposed route. The Port also indicated that the new proposed route 

would cross more areas that are within the Port’s future development plans than the original WC1A route. Pacific Connector has stated that they would work with the Port and potentially 

affected oyster growers to minimize easement encumbrances and impacts from installation of the 

pipeline in the bay along the proposed route. 
3-69 3.0 – Alternatives 

We approve of the new proposed pipeline between MPs 0.0 and 11.36 (Route WC-1A-2A). 

None of the other route variations we analyzed in the Coos Bay area appear to be 

environmentally superior to the new proposed route. However, to ensure that impacts on 

resources are minimized to the extent possible, we recommend that: 

• Pacific Connector should continue to consult with the Port and potentially affected 

oyster growers regarding measures that should be implemented during pipeline 

installation in Coos Bay to minimize impacts on Port activities and oyster raising. 

The results of this consultation should be filed with the Secretary prior to pipeline 

construction. 

The Coos Watershed Association, in a letter to the FERC dated December 4, 2008, commenting 

on the draft EIS, indicated concerns about Route Variation WC-1A. This variation would cross 

Kentuck, Wilanch, Catching, and Stock Sloughs, and Boone Creek, which the Association 

claims are of value to coho salmon. The route down Lilienthal Creek would cross the 

Brunschmid Wetland Reserve Project, which has an easement held by the USDA Farm Services 

Agency. These concerns would also apply to the currently proposed route because Variation 

WC-1A and the proposed route share the same location at the crossings of these waterbodies and 

wetlands. Each of the other pipeline route variations evaluated in the Coos Bay area would also 

potentially affect salmon as a result of in-water construction within Coos Bay or other waterbody 

crossings, therefore potential impact on salmon could not be avoided by using one of the other 

Coos Bay alternative routes. Members of the Waterbody Crossing Methodologies Subgroup of 

the Federal and State Task Force on ESA-related issues for the Project appeared to favor Route 

Variation WC-1A over the in-water route, for the reason that variation WC-1A (and also the 

proposed route) would reduce the length of pipeline within aquatic habitat. 

We address impacts on waterbodies and wetlands in section 4.3 of this final EIS. Pacific 

Connector intends to use a bore to cross under both Kentuck and Catching Sloughs, thus 

avoiding direct impacts on those waterbodies and the fish species that may inhabit those streams. 

We believe that measures proposed by Pacific Connector for construction and restoration within 

wetlands would adequately minimize impacts on wetlands along Lilienthal Creek and the 

Brunschmid Wetland Reserve Project. However, we have recommended in section 4.3 that 

Pacific Connector work with the Coos Watershed Association and the USDA Farm Services 

Agency during finalization of design plans to ensure that impacts on the Wetland Reserve Project 

and adjacent wetlands are properly mitigated. We address impacts to federally listed salmon in 

section 4.6, and outline measures that would be used to avoid, reduce, or mitigate those impacts. 

3.4.2.2 MPs 9 to 22 - Blue Ridge Route Variations 

In filings made on October 4, 2007, both Fred Messerle & Sons, Inc. (Messerle) and the Coos 

County Sheep Company proposed what they called the Blue Ridge Alternative Route between 

about MPs 9 and 22 (figure 3.4-3). They contend that this route, shifting the pipeline further 

east, would place the pipeline over tracts mainly owned by the federal government and large 

timber companies. They state that their alternative route would be further removed from the 

Coos Bay estuary, and farther away from areas that would be more likely to be developed in the 

future for residential and commercial purposes. Their suggested route alternative would mostly 

follow ridgelines. They claim that their alternative route would only have one waterbody 

crossing, of Steinnon Creek, and would avoid crossings of Catching and Stock Sloughs, and 
3-70 3.0 – Alternatives 

Figure 3.4-3. Blue Ridge Route Variation (MP 8.9 to MP 21.6) 
3-71 3.0 – Alternatives 

Boone Creek, Catching Creek, and Cunningham Creek along the proposed route. Pacific 

Connector believes that the alternative route would cross five waterbodies. The variation would 

be about 0.8 mile shorter than the corresponding segment of the proposed route. 

In a November 21, 2007 filing, responding to a November 2, 2007 data request from the FERC, 

Pacific Connector provided the results of its desktop comparison of the Blue Ridge Route 

Variation with the September 2007 proposed route between about MPs 9 and 22. Pacific 

Connector contends that there are constructability issues along the Blue Ridge Route Variation, 

as two areas susceptible to landslides were identified with LiDAR. The proposed route would 

follow the exiting BPA powerline corridor for 5.9 miles, while the Blue Ridge Route Variation 

would follow a one-lane asphalt road for 4.1 miles. Pacific Connector believes it would have to 

install its pipeline in Blue Ridge Road along the route variation, resulting in traffic delays due to 

road closures, potentially impacting residences along the route, limiting access for timber 

extraction and recreational activities in the area, and increasing expenses related to rebuilding the 

road after pipeline installation. Pacific Connector is also concerned that the Blue Ridge Route 

Variation would follow Razor Back Ridge Top, requiring slow and expensive stove-pipe 

construction techniques that could add a year to the installation schedule, with limited access for 

construction vehicles, limited turn around space, and limited work space. 

In a November 29, 2008 letter to the FERC, Laurie and Richard Potts supported the finding in 

the draft EIS that the proposed route was environmentally preferable to the Blue Ridge 

Variation. They point out that the Blue Ridge Route Variation was promoted by Messaerle to 

avoid impacts on his property. The variation merely shifts the burden of the pipeline route onto 

other landowners. Potts state that Blue Ridge is narrow, with steep drop offs, and residents 

driving along Blue Ridge Road have to use pullouts to avoid oncoming traffic. They are 

concerned about safety and buildability issues if the pipeline was rerouted along the road. 

A December 1, 2008 letter to the FERC from Mark Sheldon of Coos Bay argued in favor of the 

Blue Ridge Route Variation because it would affect fewer landowners (by two) and cross fewer 

creeks (by two) in comparison to the proposed route. Messerle, in a December 1, 2008 letter, 

proposed the use on an Amended Blue Ridge Alternative Route between about MP 9.2 along 

Route Alternative WC-1A and MP 21.6. Messerle claims this new alternative route would avoid 

the wetland habitat restoration project on the Brunschmid property, avoid potential cultural 

resources at Grave Yard Point, eliminate crossings of Stock Slough and Catching Slough, and 

instead move the pipeline to a route within the Vogel Creek drainage. Messerle asserts that the 

new alternative route would reduce the length of the pipeline and reduce impacts on private 

property by increasing the distance crossing BLM land. The Coos Watershed Association, in a 

December 4, 2008 letter commenting on the draft EIS, requested a more thorough analysis of the 

Amended Blue Ridge Alternative Route. In a December 29, 2008 data request, we asked Pacific 

Connector to provide the results of a desk-top environmental analysis of the Amended Blue 

Ridge, and additional information was filed on January 21, 2009. Figure 3-4-3 illustrates the 

proposed route, Messerle’s October 2007 Blue Ridge Route Variation, and his December 2008 

Amended Blue Ridge Alternative Route. Table 3.4.2.2-1 compares environmental elements 

between the proposed route, Blue Ridge Route Variation, and Amended Blue Ridge Alternative 

Route. The proposed route would be longest, and affect the most landowners, while the 

Amended Blue Ridge Alternative Route would be 2.2 miles shorter and affect 18 fewer tracts. 

The proposed route would maximize following existing rights-of-way, and would cross less 

steep terrain.
3-72 3.0 – Alternatives 

TABLE 3.4.2.2-1 

Comparison of Pacific Connector’s Proposed Route and Blue Ridge Route Variation and Amended Blue Ridge Variation 

(MP 9.45 to 21.6) a/

Impact/Issue 

Proposed 

Route 

Blue Ridge 

Variation 

Landowner Amended 

Blue Ridge Variation 

Individual Land Tracts 58 48 40 

Total Length (miles) b/ 15.83 14.53 13.63 

Parallel/Adjoining Existing Disturbances (miles) c/ 6.85 5.05 4.22 

Timbered Land (miles) 10.63 10.73 10.75 

In-Road Lay – Dirt (Gravel) – Rebuild road post-construction 

(miles) 

1.07 1.17 0.69 

In-Road Lay – Paved (Asphalt) – Rebuild road postconstruction (miles) None 4.1 d/ 4.1 d/

Road Closure During Construction – Flaggers, Traffic Control 

& Detours (miles) 

None 4.1 d/ 4.1 d/

River Crossings HDD HDD HDD – not feasible e/

Creek/Ditch Crossings f/ 60 f/ 12 f/ 17 f/

Slough Crossing – Dry Open Cut 1 None None 

Slough Crossing – Bore (feet) 400 None None 

Unpaved Road Crossings – Cut 33 20-33 20-25 

Paved Road Crossings – Cut 7 4 4 

Steep Up & Down Slopes – Tie-Off Equipment, etc. (miles) 1.1 1.2 1.3 

Narrow Ridge Top Construction – Only access is along 

easement (miles) 

None 9.5 g/ 9.5 g/

Razor – Back Ridge Top Construction – Stove-pipe, Sections, 

End haul, etc. (miles) h/

None 4.5 h/ 4.5 h/

Concrete Weight Coating of Pipe Required (miles) i/ 1.58 1.08 0.93 

Work off Hardwood Mats/Dewater Ditch, etc. (miles) 1.58 1.08 0.93 

a/ To provide a common comparison of all routes, the routes begin at MP 9.45 of the proposed route. 

b/ Lengths measured Using ArcMap GIS Software. 

c/ The proposed route would parallel 5.9 miles of BPA rights-of-way, whereas both variations would follow 4.1 miles of single-lane 

paved road as noted in Footnote 4. 

d/ 4.1 miles ridge top construction is within & above a light-duty single-lane paved road; 0.50 mile of which is populated on both 

sides of the road. 

e/ Potential Coos River HDD not feasible on Landowner Amended route because of steep slopes and lack of suitable HDD entry or 

exit point on north side of the Coos River. 

f/ Based on Pacific Connector’s wetland and waterbody surveys conducted by Jones and Stokes on the Proposed Route and from 

Pacific Northwest Hydrography Framework Clearinghouse (PNHFC) data layers (http://hydro.reo.gov/) for the variations. The 

Proposed Route includes 12-ditches, 11-intermittent waterbodies and 37-perennial waterbodies. 

g/ Only 4 access points in 9.5 miles ridge top - Extended In/Out Travel Time for all operations along ridge top easement means 

short work production days. 

h/ 4.5 miles razorback ridge top - extremely narrow, limited work space, limited access, limited turnaround space available. 

i/ Based on Pacific Connector’s wetland and waterbody surveys conducted by Jones and Stokes on the Proposed Route and NWI 

mapping on the variations where wetland and waterbody surveys have not been completed. 

Pacific Connector identified additional areas of potentially rapidly moving landslides on slopes 

immediately south of MP 9.45 and north of Echo Valley, as well as on the slopes on the north 

side of the Coos River along the Amended Blue Ridge Alternative Route. Pacific Connector also 

believes that an HDD under the Coos River would not be possible along the Amended Blue 

Ridge Alternative Route because of the topographic conditions on the north side of the river. 

Therefore, a wet open-cut crossing would be required.

Because there are questions about safety and buildability along the alternative routes, we do not 

believe that either the Blue Ridge Route Variation or the Amended Blue Ridge Alternative Route 

are clearly environmentally superior, and do not recommend either. While the proposed route 

would follow more existing rights-of-way and less steep terrain, the alternative routes would 

encounter difficult construction conditions, landslide areas, access issues, and most likely result 

in delays for users of Blue Ridge Road. While any of the routes would cross streams that 
3-73 3.0 – Alternatives 

provide habitat for salmon, we are concerned about increased impacts caused by an open-cut 

crossing of the Coos River along the Amended Blue Ridge Alternative Route. The desk-top 

analysis is adequate to support our finding that the proposed route is environmentally preferable, 

and we do not agree that on-the-ground surveys of the alternatives routes or additional analyses 

are necessary. 

3.4.2.3 MPs 36 to 39 - Big Creek/Spirit Mountain Route Variations 

On December 9, 2007, the BLM Coos Bay District requested that the FERC analyze three 

potential alternative routes between about MP 36 to 39 to avoid newly identified habitat for 

MAMU nesting sites. In a December 14, 2007 data request, the FERC asked Pacific Connector 

to provide desktop data comparing the suggested alternative routes (northern, southern, and 

intermediate variations) with the corresponding segment of proposed route (figure 3.4-4 and 

table 3.4.2.3-1). 

The northern route variation would leave the proposed route just east of MP 36, heading 

northeast towards Spirit Mountain, following in a part an existing road or trail for about 1.5 

miles, then rejoining the proposed route just east of MP 38. This variation would be about 0.5 

mile longer than the corresponding segment of proposed route. The route variation would 

transverse rugged topography with steep slide-slopes (greater than 50 percent) and cross several 

waterbodies. The geologic hazard evaluation determined that this variation is not a reasonable 

alternative due to the high risk of landslides and construction difficulties on the steep slideslopes. 

The southern route variation would head southeast from the proposed route east of MP 36, 

crossing Big Creek, following existing roads or trails for about 1.3 miles, and rejoining the 

proposed route just east of an existing quarry east of MP 39. This variation would be about 0.33 

mile longer than the corresponding segment of proposed route. It would require less clearing of 

mature forest, and would cross an area with more regenerating forest. This variation would cross 

Big Creek, which would be avoided by the proposed route. It would also cross tribal lands 

associated with the Coquille Forest that would be avoided by the corresponding segment of 

proposed route. 

The intermediate route variation would roughly follow the first mile of the southern variation, 

but then turn north and rejoin the proposed route near MP 38.1. This variation was eliminated 

from further evaluation because it would require crossing unstable slopes composed of a 

landslide complex mapped and described in the Geologic Hazards Report submitted with the 

Pacific Connector’s FERC application. This alternative would also cross Big Creek, which 

would be avoided by the corresponding segment of proposed route. 
3-74 3.0 – Alternatives 

Figure 3.4-4. Big Creek/Spirit Mountain Route Variations (MP 36 to MP 39) 
3-75 3.0 – Alternatives 

TABLE 3.4.2.3-1 

Comparison of Big Creek/Spirit Mountain Route Variations to the 

Corresponding Segment of Proposed Route (MP 36 to MP 39)

Alternatives Analysis 

Proposed Route 

(MPs 36.14 to 39.15) 

BLM Northern Variation T8S, 

R10W, 

Sec. 21,22,27,28 & 29 

BLM Southern Variation T8S, 

R10W, 

Sec. 26,27,28,29,33 & 34 

Length (miles) 2.75 a/ 3.20 3.08 

Construction right-of-way 

(acres) 

31.67 36.85 35.47 

TEWA (acres) 21.46 Not designed. Estimated to require 

more temporary work areas that the 

proposed route because of 

increased length, length of steep 

side slope and steep slope 

construction and the increased 

number of waterbody crossings. 

Not designed. Estimated to 

require more temporary work 

areas that the proposed 

alignment because of increased 

length, length of steep side slope, 

and the increased number of 

waterbody crossings. 

Permanent Easement 

(acres) b/

19.81 21.58 21.61 

Number of residences 

within 50 feet of 

construction right-of-way 

0 0 0 

Number of waterbodies 

crossed 

4 c/ 10 d/ 6 d/

Length of waterbody 

crossings (feet) 

25.34 c/ Unknown d/ Unknown d/

Number of wetlands 

crossed 

0 c/ 0 e/ 0 e/

Length of wetland crossings 

(feet) 

0 c/ 0 e/ 0 e/

Agricultural lands affected 

(acres) 

0.00 0.00 0.00 

Forest clearing (acres 

construction right-of-way) 

24.52 f/ 24.06 f/ 13.60 f/

Regenerating forest 

clearing (acres construction 

right-of-way) 

7.15 f/ 12.78 f/ 21.87 f/

Number of previously 

recorded cultural resources 

None None None 

Miles of right-of-way parallel 

or adjacent to existing 

rights-of-way (percent 

alternative length) 

1.31 (48 percent) 1.50 (47 percent) 1.29 (42 percent) 

a/ Mileage length cannot be calculated by subtracting milepost ranges because of engineering station equations included in route

segment between MPs 36.14 and 39.15. 

b/ Acres of permanent easement calculated based on crossing length on private and federal timber lands. Pacific Connector 

proposes a 53-foot permanent easement on federal lands and a 60-foot permanent easement on private timber lands. 

c/ From Pacific Northwest Hydrography Framework Clearinghouse data layers (http://hydro.reo.gov/). No waterbody widths are 

provided. 

d/ No wetlands are crossed on the proposed alignment based on field surveys (see Table 2A-3 in Appendix 2A to Resource 

Report 2). 

e/ No wetlands are crossed on either the BLM’s northern or southern alternatives based on NWI mapping. 

f/ Includes recent clear-cut forests and areas of inroad construction where forest clearing would be reduced. 

The Big Creek/Spirit Mountain route variations do not appear to be environmentally superior to 

the corresponding segment of proposed route. However, the BLM may require the use of one of 

these alternatives to avoid MAMU on BLM land, if further on-the-ground investigations prove 

that one of these variations could be constructed without compromising safety and long-term 

pipeline stability by avoiding potential geological hazards. 

In a filing on December 4, 2008, Pacific Connector did make a small route adjustment between 

MPs 36.1 and 36.29 to reduce impacts on MAMU Stand B07. Portions of the forest within the 

boundaries of MAMU Stand B07 have been harvested. Therefore, Pacific Connector 
3-76 3.0 – Alternatives 

reconfigured its pipeline route and TEWA locations in this area, to utilize the harvested areas. 

To further lessen potential impacts on MAMU habitat, the pipeline would be installed along an 

existing road, in an area of gentle topography, between MPs 35.33 and 36.14. We find this new 

proposed route segment environmentally acceptable. 

3.4.2.4 MPs 46 to 48 - Deep Creek Route Variation 

On November 30, 2007, the BLM requested that the FERC study an alternative route between 

MPs 46 and 48 to avoid habitat for MAMU nesting sites and core areas for NSOs. In a 

December 14, 2007 data request, the FERC asked Pacific Connector to provide desktop data 

comparing the BLM suggested alternative route with the corresponding segment of proposed 

route (table 3.4.2.4-1 and figure 3.4-5). 

The Deep Creek Route Variation would leave the proposed route just east of MP 46, follow 

existing 4-wheel drive trails for about 0.8 mile, go south of Deep Creek, and rejoin the proposed 

route just west of MP 48. This alternative would be 0.23 mile longer than the proposed route. It 

would cross one additional waterbody. Pacific Connector’s geologic hazard evaluation 

determined that this alternative segment is not reasonable due to the high risk of landslides and 

surface erosion where the alignment descends the eastern flank of Weaver Ridge through 

convergent slopes above a stream. 

TABLE 3.4.2.4-1 

Comparison of the Deep Creek Route Variation with the Corresponding Segment of Proposed Route (MP 46 to MP 48)

Alternatives Analysis Proposed Route BLM Alternative 

Length (Miles) 1.57 1.80 

Construction right-of-way (acres) 18.08 20.73 

TEWAs (acres) 

14.63 

Not designed – estimated to be 

similar to proposed alignment based 

on topography. 

Permanent Easement (acres) a/ 10.70 12.79 

Number of residences within 50 feet of construction right-of-way 0 0 

Number of waterbodies crossed 1 b/ 2 c/

Length of waterbody crossings (feet) 4.03 b/ Unknown c/

Number of wetlands crossed 1 b/ 0 d/

Length of wetland crossings (feet) 35.42 b/ 0 d/

Agricultural lands affected (acres) 0 0 

Forest clearing (acres construction right-of-way) e/ 9.67 9.33 

Regenerating forest clearing (acres construction right-of-way) e/ 8.41 11.40 

Number of previously recorded cultural resources 1 – historic transportation 

feature 1 – historic transportation feature 

Miles of right-of-way parallel or adjacent to existing rights-of-way 

(percent of alternative length) 0.38 (28 percent) 0.77 

(43 percent) 

a/ Acres of permanent easement calculated based on crossing length on private and federal timber lands. Pacific Connector proposes a 

53-foot permanent easement on federal lands and a 60-foot permanent easement on private timber lands. 

b/ Based on field surveys (see Table 2A-2 in Appendix 2A to Resource Report 2) 

c/ From Pacific Northwest Hydrography Framework Clearinghouse data layers (http://hydro.reo.gov/). No waterbody widths are 

provided 

d/ No wetlands are crossed on the BLM’s proposed alternatives based on NWI mapping. 

e/ Includes recent clear-cut forests and areas of inroad construction where forest clearing would be reduced. 
3-77 3.0 – Alternatives 

Figure 3.4-5. Deep Creek Route Variation (MP 46 to MP 48) 
3-78 3.0 – Alternatives 

3.4.2.5 MPs 51 to 53 - Camus Valley East Route Variations 

On November 30, 2007, the BLM requested that the FERC study an alternative route near MP 52 to 

avoid habitat for MAMU nesting sites and core areas for NSOs. In a December 14, 2007 data 

request, the FERC asked Pacific Connector to provide desktop data comparing the suggested BLM 

alternative route with the corresponding segment of the route filed in September 2007. 

The BLM suggested variation would turn southeast from the September 2007 route just east of 

MP 51 and follow section lines and existing rights-of-way for about 1.2 miles, before rejoining 

the proposed route just west of MP 53. This variation would be about the same length as the 

corresponding segment of the September 2007 route, but would follow an existing right-of-way 

for a longer distance. The variation would require less clearing of regenerating forest, and cross 

one less waterbody than the corresponding segment of September 2007 route. The route 

variation would be closer to one residence. Pacific Connector’s geologic hazard evaluation did 

not identify significant differences between either route; however, the BLM identified route 

variation includes a Highway 42 crossing that would not be viable according to Pacific 

Connector. The highway crossing would be located in the midpoint of a mile-long section of 

highway fill approximately 80 feet deep. The highway crossing would also be at the same 

location as a tributary to Jim Bilieu Creek, which passes beneath the highway in a culvert. 

In the draft EIS, we also discussed another route alternative in this area identified by Pacific 

Connector, which we labeled the Southern Route Variation. This route would begin east of MP 

50 and would rejoin the September 2007 route near MP 53. It would cross Highway 42 in a level 

area and is constructible using conventional boring methods in an area with very little timber. In 

the draft EIS, we recommended that Pacific Connector incorporate the Southern Route Variation 

into its proposed route. Pacific Connector agreed to this route change in a December 4, 2008 

filing. Therefore, the Southern Route Variation is now the proposed route analyzed in this final 

EIS. The three Camus Valley East Route Variations are illustrated on figure 3.4-6. In table 

3.4.2.5-1, we compare the proposed route to the September 2007 route, which we now label the 

Northern Variation, and the BLM Alternative Route Segment. 

We found the proposed route to be environmentally preferable because it would avoid the 

occupied MAMU stand, and would not cross any known geological hazards. According to 

Pacific Connector, the proposed route has an acceptable crossing of Highway 42. It would 

require the clearing of less forest, and avoid a wetland identified along the Northern Variation. 

The proposed route is slightly longer than the other route alternatives, and would be closer to 

several standing structures. 

We received comments on the draft EIS from a landowner that would be affected by the revised 

proposed route, concerned about impacts on his buildings and livestock. Pacific Connector has 

made minor adjustments to the alignment shown in the draft EIS to avoid a structure as well as 

an old growth forest stand, and has filed detailed alignment drawings showing the location with 

respect to buildings. Pacific Connector would also work with the affected landowner during 

easement negotiations, as with other affected properties, to identify specific landowner needs 

such as livestock fencing during construction. We have not changed our conclusion from the 

draft EIS, and believe the new proposed route has environmental and construction advantages 

over the BLM-identified variation and the Northern Variation, and it appears to address the BLM 

resource concerns. 
3-79 3.0 – Alternatives 

Figure 3.4-6. Camus Valley East Route Variations (MP 52.2 to 53.0) 
3-80 3.0 – Alternatives 

TABLE 3.4.2.5-1 

Comparison of Camus Valley East Route Variations with the Corresponding Segment of Proposed Route 

(MP 52.2 to MP 53)

Alternatives Analysis 

Northern Variation 

(MPs 50.2 – 53.0) 

BLM Alternative Segment 

(MPs 50.2 – 53.0) 

New Proposed Route 

(MPs 50.2 – 53.0) 

General 

Length (miles) 2.72 2.7 2.85 

Construction right-of-way (acres) 31.20 31.6 32.68 

Number of TEWAs (acres) 19 estimated to be similar to 

northern variation 

19 

Acres of TEWAs 17.01 estimated to be similar to 

northern variation 

18.07 

Permanent easement (acres) a/ 16.48 estimated to be similar to 

northern variation 

17.27 

Land Use 

Land Ownership (miles) 

Private 1.96 similar to northern variation 2.27 

State 0 0 0 

Federal (BLM/NFS lands) 0.76 similar to northern variation 0.58 

Number of landowner parcels crossed 8 Unknown 15 

Number of residences within 50 feet of 

construction right-of-way 

0 1 0 b/

Miles of right-of-way parallel or adjacent to 

existing rights-of-way (percent of alternative 

length) 

0.11 1.2 0.13 

LSR - Federal land use designation (acres) 0.0 Unknown 4.85 c/

Riparian Reserves - federal land use 

designation (acres) 

3.14 Unknown 1.37 

Waterbodies and Wetlands 

Number of waterbodies crossed 5 d/ 3 4 e/

Length of waterbody crossings (feet) 131.32 d/ Unknown 110 e/

Number of wetlands crossed 1 d/ 0 0 e/

Length of wetland crossings (feet) 2.09 d/ 0 0.00 e/

Vegetation 

Agricultural lands affected (acres) 1.87 1.9 7.6 

Total forest clearing (acres) 38.67 13.9 27.60 

 Acres Clearcut/Regenerating (0 to 40 

years) f/

22.44 13.3 13.64 

 Acres Mid-Seral Forest (40 to 80 years) 10.28 8.46 

Acres Late-Successional Forest (80 to 175 

years) 

2.09 5.50 

Old-Growth Forest (175 +) 3.85 0 

Biological Resources 

MAMU suitable habitat crossed (feet) g/ 18.13 Unknown 4.69 

MAMU stands Occupied Alignment crosses 

1,043 feet of 

Occupied Stand 

R3027 

Unknown No known stands 

Presumed Alignment crosses 

350 feet of 

Potential MAMU 

Stand B12 that is 

not likely to be 

occupied based 

on the 2-year 

survey protocol. 

Unknown No known stands 
3-81 3.0 – Alternatives 

TABLE 3.4.2.5-1 

Comparison of Camus Valley East Route Variations with the Corresponding Segment of Proposed Route 

(MP 52.2 to MP 53)

Alternatives Analysis 

Northern Variation 

(MPs 50.2 – 53.0) 

BLM Alternative Segment 

(MPs 50.2 – 53.0) 

New Proposed Route 

(MPs 50.2 – 53.0) 

MAMU critical habitat (acres) 0.00 Unknown 4.83 Pacific Connector 

made a minor adjusted to 

the Southern Route 

Variation to avoid crossing 

approximately 175 feet of 

the old growth forest (250 

years old based on BLM 

FOI coverage) within this 

Critical Habitat Unit.) 

NSO suitable habitat crossed (acres) h/ 33.35 Unknown 19.98 

NSO nest patch/cores None Unknown No known nest 

patch/cores 

NSO critical habitat crossed (feet) 0.00 Unknown 0.00 

1 5.43 Unknown 1.74 

2 4.56 Unknown 12.50 

3 15.18 Unknown 16.65 

4 18.27 Unknown 16.31 

5 2.45 Unknown 1.81 

Habitat category(acres) i/

6 2.32 Unknown 3.18 

Kincaid’s lupine Approximately 2.2 miles of 

potential habitat crossed; 0.8 mile 

surveyed of which 0.3 mile was 

considered suitable; no plants 

located in 2007. 

Unknown Based on proportion of 

suitable habitat present in 

proposed route, 

approximately 1.1 miles of 

habitat may be suitable for 

Kincaid’s lupine. 

ESA fish species present/habitat j/ 1 Stream crossing none 3 stream 

crossings unknown. 1 stream 

crossing - Oregon Coast ESU 

Coho, assumed. 

unknown 1 Stream crossing none 3 

stream crossings 

unknown. 1 stream 

crossing - Oregon Coast 

ESU Coho, assumed. 

StreamNet – anadromous fish distribution k/ None None None 

Geotechnical 

Steep or difficult terrain (miles) l/ 0.00 Unknown 0.00 

Highly erosive soils (miles) m/ 0.19 Unknown 0.17 

Cultural Resources 

Number of previously recorded cultural 

resources 

3 - Isolated finds 2- sites 1 site 2 sites 

Number of newly identified cultural resources n/ N/A Unknown 1- isolated find 

a/ Acres of permanent easement calculated based on a 50-foot width. 

b/ There are 2 outbuilding structures (barns/sheds) in the vicinity of the Southern Route Alternative that are within 50 feet of the construction right-of-way (MP 51.4 

and MP 51.9). Neither of these structures is suspected of being residences; however during the right-of-way acquisition phase, Pacific Connector would attempt to 

locate the construction right-of-way 50 feet from any residences, where feasible. 

c/ A total of 4.85 acres of federal LSR would be affected with 2.94 acres occurring within clear- cut/regenerating forests (0 to 40 years) and 1.91 acres occurring 

within mid-seral forest (40 to 80 years). 

d/ Based on field surveys. 

e/ Wetlands and waterbody surveys were not completed. From Pacific Northwest Hydrography Framework Clearinghouse (PNHFC) data layers 

(http://hydro.reo.gov/), review of county aerial photo coverage (Surdex) and USGS Quad maps. Stream widths were estimated based on aerial photo interpretation. 

4b wetlands and waterbody surveys were not completed. From NWI mapping. Based on NWI mapping, no wetlands are crossed on the proposed route or the 

Southern Route Alternative. 

f/ Forest Age Classes: Includes recent clearcut forests and areas of inroad construction where forest clearing would be reduced. 

g/ Martin et al. 2006; General Technical Report PNW-GTR-65. 

h/ USFS 2004: PNW-GTR-648. 

i/ See Section 3.4.1.4 of Pacific Connectors Resource Report 3 filed with its September 2007 application to the FERC. 

j/ FWS, NMFS, and StreamNet (http://www.streamnet.org). 

k/ ODFW, 2000a; ODFW, 2006b; StreamNet. 

l/ Based on Soil Mapping Units that have slopes of 50-75 percent and have a water erosion rating of high or severe. NRCS. 2004. Soil Survey of Douglas County 

Area, Oregon. U. S. Department of Agriculture. 

m/ Based on Soil Mapping Units that have a water erosion rating of high or severe. NRCS. 2004. Soil Survey of Douglas County Area, Oregon. U. S. Department of 

Agriculture. 

n/ The new proposed route would avoid 1 site and 3 isolated finds on the Northern Alternative. One site would be affected regardless of the route selection. This 

route was not completely surveyed. 
3-82 3.0 – Alternatives 

3.4.2.6 MPs 57 to 67 - Olalla/Dillard Route Variation 

The Olalla/Dillard Route Variation was the original route (May 2006) evaluated by Pacific 

Connector in the Olalla/Dillard area. During public scoping during the Pre-filing Process, and 

during meetings between Pacific Connector and some affected landowners, issues were 

identified in this area related to easement encumbrances, agricultural lands, domestic water 

supplies, and a proposed reservoir and subdivision. Pacific Connector evaluated a route change 

to avoid or minimize these issues by following forested ridgelines south of its original route. 

Pacific Connector has subsequently incorporated this route change into its September 2007 

proposed route. 

We evaluated the May 2006 original route in this area as the Olalla/Dillard Route Variation. The 

variation would begin at approximately MP 57 of the proposed route and be located to the north 

of the proposed route (figure 3.4-7). It would closely follow the proposed route east and then 

northeast, crossing McNabb Creek near MP 59.1. At approximately MP 61.3, the variation 

would turn generally southeast. At this point it would be approximately 1.3 miles north of the 

proposed route. The Olalla/Dillard Route Variation would cross Kent Creek at approximately 

MP 63.1, Rice Creek near MP 64.4, and Willis Creek near MP 65.3. Shortly after crossing 

Willis Creek, the variation would connect with the proposed route near MP 67. The 

Olalla/Dillard Route Variation and the corresponding segment of the proposed route are 

compared in table 3.4.2.6-1. 

The primary advantage of the Olalla/Dillard Route Variation is that it would be straighter and 

slightly shorter (0.2 mile) than the corresponding segment of proposed route, therefore affecting 

less acreage during construction. The primary disadvantage of the variation is that it would 

potentially conflict with land uses in the Dillard area, including a planned reservoir and 

subdivision, and residential water supplies, and would cross 20 more land parcels than the 

corresponding segment of the proposed route. The variation would also cross 21 more 

waterbodies and about 2,000 more feet of wetlands than the corresponding segment of the 

proposed route. We believe the disadvantages of the variation outweigh any advantages, and that 

the variation would not be environmentally preferable to the corresponding segment of proposed 

route. Therefore, we do not recommend use of the Olalla/Dillard Route Variation. 
3-83 3.0 – Alternatives 

Figure 3.4-7. Olalla Dillard Route Variation (MP 57 to MP 67) 
3-84 3.0 – Alternatives 

TABLE 3.4.2.6-1 

Comparison of the Olalla/Dillard Route Variation With the 

Corresponding Segment of Proposed Route (MP 57 to MP 67) a/

Impact/Issue Proposed Route 

Olalla/Dillard Route 

Variation 

General

Total length (miles) 10.0 9.8 

Acres of construction right-of-way b/ 114.6 113.0 

Number of TEWAs 63 Not designed c/

Acres of TEWAs 32.7 Not designed c/

Total acres of construction disturbance 147.3 113.1 c/

Acres affected during operations (permanent easement) d/ 90.5 89.3 

Landowner parcels crossed 51 71 

Number of residences within 50 feet of construction right-of-way 0 0 

Land ownership (miles) Private 8.9 9.6 

 State 0.0 0.0 

 Federal (BLM/NFS lands) 1.1 0.3 

Geotechnical 

Miles of steep or difficult terrain to be crossed e/ 0.4 0.8 

Waterbodies and Wetlands f/

Number of waterbodies crossed g/ 18 39 g/

Total waterbody crossing length h/ 410 N/A f/

Number of wetlands crossed 11 11 i/

Total wetland crossing length (feet) 743 2,763 

Total wetland disturbance during construction (acres) 1.2 1.6 

Land Use 

Agricultural land affected (miles) 2.6 4.8 

Forest lands affected (miles) j/ 5.2 3.9 

Miles of right-of-way that would be parallel or adjacent to existing rights-of-way 3.9 1.6 

Cultural Resources 

Number of previously identified cultural resources along route 0 0 

Number of newly identified cultural resources along route 5 1 f/

Critical Habitat 

Acres of critical habitat for federal or state listed threatened or endangered 

species 

0 0 

a/ Mileposts were computed from topographic maps. 

b/ The construction right-of-way for both the proposed route and Olalla/Dillard Route Variation is 95 feet. 

c/ TEWAs for the Olalla/Dillard Route Variation have not been designed and are not included in the total acres of disturbance. The 

need for these TEWAs would be similar to the proposed route. 

d/ The assumed permanent easement for both the proposed route and Olalla/Dillard Route Variation is 75 feet. 

e/ Based on slopes that are greater 50 percent (based on 10-meter DEM). However, Pacific Connector has routed the alignment to 

ensure constructability, safety and long-term stability by avoiding side slopes and approaching slopes with the alignment obliquely 

or perpendicularly to the slope. 

f/ Surveys are incomplete. 

g/ Waterbodies from PNW Hydrography Framework Clearinghouse. 

h/ Based on review of aerial photos, topographic maps, and LiDAR data. 

i/ Based on NWI coverages and photo interpretation. 

j/ Includes all forestland types: Evergreen Forest, Mixed Conifer, Regenerating Forests and Clearcuts. 

3.4.2.7 MPs 59 to 60 - Miller Route Variation 

In a letter dated January 28, 2007, Barbara Miller requested a re-route across property owned by 

Bernadeane Perron because of concerns about the proposed route crossing steep terrain prone to 

mass-wasting and landslides. In a June 2, 2008 data request, we asked Pacific Connector to 

address Ms. Miller’s concerns. Pacific Connector responded with a filing on June 23, 2008 that 

indicated that its originally proposed pipeline route in May 2006 (Olalla/Dillard Variation 

discussed above) was mainly aligned along the bottom of Olalla Valley. However, in response 

to public comments, Pacific Connector changed the route between MPs 57 and 67 in its 

September 2007 application. The current proposed route minimizes impacts on easement 
3-85 3.0 – Alternatives 

encumbrances by traversing through timberlands along ridgelines away from agricultural fields 

and rural residences. Pacific Connector did not indicate that the proposed route was unbuildable, 

or that it could not mitigate for any potential landslide hazards. The proposed pipeline has been 

routed along stable toeslopes of the Olalla Valley between MPs 59 and 60. Pacific Connector 

provided a Geologic Hazards Report with its application that indicated that the potential RML 

deposits traversed by the proposed alignment between MPs 59 and 60 (as mapped in Hofmeister 

et al. 2002) would be within depositional zones of less than 16 percent slopes that should not be 

a hazard to the construction and operation of the buried pipeline. As stated above, we do not 

recommend the use of the Olalla/Dillard Route Variation. 

3.4.2.8 MP 61 - Hoover Hill Route Variation 

In a letter dated October 19, 2006, the City Council of the city of Winston, Oregon requested that 

the FERC consider alternative pipeline routes to avoid visual impacts on Hoover Hill, which is 

considered a prominent local topographic landmark. We asked Pacific Connector to address this 

issue in a June 2, 2008 data request. In response, on June 23, 2008, Pacific Connector made a 

filing that indicated that the proposed route over Hoover Hill, included as part of its September 

2007 application, was developed in response to public comments on the original route filed in 

May 2006 (Olalla/Dillard Route Variation). The pipeline in the vicinity of Hoover Hill would be 

about 4 miles away from the city of Winston. The alignment traverses a forested ridge crest 

perpendicular to Winston, and Pacific Connector contends that pipeline should not be visible 

from within the city limits. Pacific Connector claims that traffic traveling on Hoover Hill Road 

north of Hoover Hill, and traffic on a private dead-end drive south of Hoover Hill would not 

have clear unobstructed views of the pipeline right-of-way because the roads parallel the pipeline 

route, and are about 700 feet below the crest of Hoover Hill. Visibility of the pipeline from 

private McNabb Creek Road west of Hoover Hill would be limited due to turns in the proposed 

alignment. 

We disagree with Pacific Connector, and think that the pipeline right-of-way would be visible 

from Highway 42 and I-5, as well as local roads such as Hoover Hill Road, Olalla Road, and 

McNabb Road. As explained in section 4.7.3.4, the pipeline would be compatible with BLM 

visual classifications for federal lands at Hoover Hill (VRM Class IV - Major Modification of 

Character), and therefore we do not believe that the pipeline would have adverse visual impacts 

in this area. 

The Hoover Hill Route Variation falls within the longer Olalla/Dillard Route Variation. As 

mentioned above, we do not recommend use of the Olalla/Dillard Route Variation. 

3.4.2.9 MPs 69 to 69 - McConnell Route Variation 

In filings made on January 29, 2007, Marc and Dea McConnell proposed that the pipeline route 

be moved off their property, which they state is being developed into 2-acre parcels for 

residential homes. They suggest that one alternative would be to route the pipeline across the 

property directly south of their land because it is zoned for grazing. They contend that a pipeline 

is better suited to land zoned for grazing than it is to their property, which is zoned for rural 

residential, 2-acre minimum parcels. The landowners contend that the proposed route would 

permanently affect three of the 2-acre parcels, negatively affecting their market value. The 

Douglas County Planning Department indicates that the McConnells submitted a request to 

subdivide their property into three parcels (4.81, 2.00, and 2.00 acres respectively) and that this 
3-86 3.0 – Alternatives 

request was finalized on June 13, 2007. However, the Planning Department also indicates that 

development plans have not been submitted (personal communication, June 30, 2008). While 

the property is zoned Rural Residential, these parcels do not contain residences. 

To ensure that impact on potential future development of this property is minimized to the extent 

possible, in the draft EIS we recommended that Pacific Connector consult with the landowners 

on ways to reduce potential impacts to future development of their property and submit the 

results to the Secretary. Accordingly, Pacific Connector attempted to discuss route adjustments 

with the landowners and submitted a summary of contacts with the landowners to the FERC. 

The summary of contacts with the McConnells documents that the landowners have informed 

Pacific Connector that only completely rerouting the pipeline off their property would be 

satisfactory and stated that they were not interested in a meeting. We found no compelling 

environmental reasons for moving the pipeline off the McConnell property. To do so would only 

shift the burden of the pipeline easement to other landowners. No development plans for this 

property have been filed with the county. We expect that during easement negotiations, Pacific 

Connector can work out a route realignment across the McConnell tract that minimizes impacts 

on the landowners future development plans. Therefore, we do not recommend use of the 

McConnell Route Variation. 

3.4.2.10 MPs 82 to 89 - Wood Creek/Days Creek Route Variation 

The Wood Creek/Days Creek Route Variation is the original route (May 2006) evaluated by 

Pacific Connector in the Wood Creek/Days Creek area. A number of potential issues were 

identified along this route segment during centerline surveys, as well as comments received 

during the Pre-filing scoping process. Issues included potential impacts to shallow ground and 

surface water systems in the Days Creek areas and Green Gulch area, and well as easement 

encumbrances on residences in the Days Creek area. As a result, Pacific Connector identified a 

route change in this area to minimize these potential impacts by traversing primarily timberlands 

and minimizing the crossing of rural pasture lands and rural residences. Pacific Connector 

subsequently revised the proposed route in its September 2007 application to the FERC. We 

evaluated the May 2006 original route in this area as the Wood Creek/Days Creek Route 

Variation. 

The variation would begin at approximately MP 82.7 of the proposed route and be located to the 

south of the proposed route. The variation would follow a generally southern route for 

approximately 0.5 mile and then turn southeast, crossing Wood Creek, and then turn northeast 

and then turn southeast, and east before crossing Days Creek. The variation would rejoin the 

proposed route shortly after crossing Days Creek at MP 89.2 (figure 3.4-8). The alternative and 

the corresponding segment of the proposed route are compared in table 3.4.2.10-1. 

The primary advantage of the Wood Creek/Days Creek Route Variation is that it would be 

straighter and slightly shorter (0.5 mile) than the corresponding segment of proposed route, 

therefore affecting less acreage during construction. The variation would also cross about 2 

miles less federally administered land, 1.6 miles less forested land, would not cross the Oregon 

Women's Land Trust (OWL) Farm, and would cross four less identified cultural resource sites 

than the corresponding segment of proposed route. The primary disadvantage of the variation is 

that it would potentially impact private water supplies in the Wood Creek and Days Creek area, 
3-87 3.0 – Alternatives 

Figure 3.4-8. Wood Creek/Days Creek Route Variation (MP 82.7 to MP 89.2) 
3-88 3.0 – Alternatives 

TABLE 3.4.2.10-1 

Comparison of the Wood Creek/Days Creek Route Variation with the 

Corresponding Segment of Proposed Route (MP 82.7 to MP 82.2) a/

Impact/Issue Proposed Route 

Wood Creek/Days Creek 

Route Variation 

General

Total length (miles) 5.8 5.3 

Acres of construction right-of-way b/ 67.3 60.9 

Number of TEWAs 33 Not designed c/

Acres of TEWAs 50.6 Not designed c/

Total acres of construction disturbance 117.8 60.91 c/

Acres affected during operations (permanent easement) d/ 53.1 48.1 

Landowner parcels crossed 21 28 

Number of residences within 50 feet of construction right-of-way 0 0 

Land ownership (miles) Private 3.8 5.2 

 State 0.0 0.0 

 Federal (BLM/NFS lands) 2.1 0.1 

Geotechnical

Miles of steep or difficult terrain to be crossed e/ 0.3 0.3 

Waterbodies and Wetlands f/

Number of waterbodies crossed 6 14 g/

Total waterbody crossing length h/ (feet) 101.9 N/A f/

Number of wetlands crossed 1 4 

Total wetland crossing length (feet) 0 2,060 i/

Total wetland disturbance during construction. (acres) 0.0 2.2 

Land Use

Agricultural land affected (miles) 0.4 1.2 

Forest lands affected (miles) j/ 4.8 3.2 

Miles of right-of-way that would be parallel or adjacent to existing 

rights-of-way 

2.7 1.5 

Cultural Resources

Number of previously identified cultural resources along route 0 0 

Number of newly identified cultural resources along route 5 2 f/

Critical Habitat

Acres of federally listed critical habitat for the NSO 0 0 

NSO activity center 1 - BLM delineated 

1 - 1⁄2 mile buffer of site 

1 - BLM delineated 

a/ Mileposts correspond with topographic maps provided in Appendix D. 

b/ The construction right-of-way for the preferred route and route alternative is 95 feet. 

c/ TEWAs for the route alternative have not been designed and are not included in the total acres of disturbance. Pacific Connector 

assumes that the need for these TEWAs would be similar to the proposed route. 

d/ The assumed permanent easement for both the proposed route and route alternative is 75 feet. 

e/ Based on slopes that are greater 50 percent (based on 10-meter DEM). However, Pacific Connector has routed the alignment to 

ensure constructability, safety, and long-term stability by avoiding side slopes and approaching slopes with the alignment obliquely 

or perpendicularly to the slope. 

f/ Surveys are incomplete. 

g/ Waterbodies from PNW Hydrography Framework Clearinghouse. 

h/ Based on review of aerial photos, topographic maps, and LiDAR data. 

i/ Based on NWI coverages and photo interpretation. 

j/ Includes all forestland types: Evergreen Forest, Mixed Conifer, Regenerating Forests, and Clearcuts. 

 
3-89 3.0 – Alternatives 

We believe the disadvantages of the variation outweigh any advantages, and that the variation 

would not be environmentally preferable to the corresponding segment of proposed route. 

Therefore, we do not recommend use of the Wood Creek/Days Creek Route Variation. 

3.4.2.11 MP 85 to 86 - Oregon Women’s Land Trust Route Variation 

The route proposed by Pacific Connector in its September 2007 application to the FERC would 

cross land owned by the Oregon Women’s Land Trust. We received numerous comments from 

individuals concerned with the impact of the proposed pipeline on this property. The Oregon 

Women’s Land Trust requested that Pacific Connector consider rerouting the pipeline to a ridge 

on the northern side of its property. Our draft EIS discussed the northern route alternative as the 

Oregon Women’s Land Trust Variation, between MPs 85.37 and 86.46 along the September 

2007 proposed pipeline route. 

In the draft EIS, we directed Pacific Connector to consult with the Oregon Women’s Land Trust 

and to provide the results of these consultations to the FERC. In its December 4, 2008 

comments on the draft EIS, Pacific Connector filed a copy of a letter dated October 8, 2008 from 

the company to Francis Earthington representing the Oregon Women’s Land Trust, answering 

questions from the trust. Kristen Brandt, Secretary for the Oregon Women’s Land Trust, filed a 

letter with the FERC, dated December 3, 2008, stating that the trust does not support either the 

northern or southern routes through its land. 

In its December 4, 2008 filing, Pacific Connector stated that use of the Northern Route Variation 

was feasible. Therefore it revised its proposed route to incorporate what was labeled the Oregon 

Women’s Land Trust Variation in the draft EIS. In this final EIS we call the September 2007 

route in this area the OWL Southern Variation. The new proposed route and the variation are 

shown in figure 3.4-9 and environmental elements are compared in table 3.4.2.11-1. 

Since permission has not been granted to Pacific Connector to survey the area, only a desktop 

review was done. The new proposed route would be 0.6 mile longer than the OWL Southern 

Variation, and would cross an historical NSO activity center; however, this activity center has 

been inactive for more than a decade and has been retired by resource and land management 

agencies. Other disadvantages of the new proposed route are that it would affect two additional 

landowners, and result in cutting an additional 4.7 acres of forest. Environmental advantages of 

the new proposed route include following an existing right-of-way for 0.4 mile, and avoiding two 

tributaries of Wood Creek. The proposed route would be a shorter crossing of the Oregon 

Women’s Land Trust property, and would avoid its guest house. Although either route would 

affect trust lands, we believe that the new proposed route would result in the least amount of 

impact on the property, and we do not recommend use of the OWL Southern Variation. 
3-90 3.0 – Alternatives 

Figure 3.4-9. Oregon Women’s Land Trust Route Variation (MP 85.3 to MP 86.4) Figure 3.4-9 Oregon Women’s Land Trust Route 

Variation (MP 85.4 to 86.4) 
3-91 3.0 – Alternatives 

TABLE 3.4.2.11-1 

Comparison of the OWL Southern Variation with the Corresponding Segment of Proposed Route (MPs 85.4 to 86.5)

Alternatives Analysis OWL Southern Variation * 

Corresponding Segment of 

Proposed Route ** 

General 

Length (miles) 1.36 1.96 

Construction right-of-way (acres) 15.55 22.44 

Number of TEWAs 10 6 

Acres of TEWAs 4.75 2.43 

Permanent easement (acres) a/ 8.24 11.89 

Land Use 

Private 1.20 1.48 

State 0.00 0.00 

Land 

Ownership 

(miles) Federal (BLM/NFS Lands) 0.16 0.48 

Number of landowner parcels crossed 6 8 

Number of residences within 50 feet of construction 

right-of-way 

1 0 

Miles of right-of-way parallel or adjacent to existing 

rights-of-way (percent of alternative length) 

0.00 (0 percent) 0.41 (21 percent) 

LSR – Federal Land Use Designation (acres) 0.00 0.00 

Riparian Reserves - Federal Land Use Designation 

(acres) 

0.00 0.00 

Waterbodies and Wetlands 

Number waterbodies crossed 2 b/ 0 c/

Length waterbody crossings (feet) 16.53 b/ 0 c/

Number of wetlands crossed None b/ None d/

Length of wetland crossings (feet) None b/ None d/

Vegetation 

Agricultural lands affected (acres) 0.00 0.00 

Total forest clearing (acres) 20.15 24.84 

 Acres Clearcut/Regenerating (0 to 40 years) 4.59 3.88 

 Acres Mid-Seral Forest (40 to 80 years) 2.43 0.73 

Acres Late-Successional Forest (80 to 175 years) 9.25 14.79 

Old-Growth Forest (175 +) 3.88 5.44 

Biological Resources 

Northern spotted owl suitable habitat crossed (acres) 

e/ 

19.08 23.51 

Northern spotted owl nest patch/cores (NSO) 1 1 

Northern spotted owl critical habitat crossed (feet) 0.00 0.00 

1 3.95 7.27 

2 9.27 12.97 

Habitat category 

(acres) f/ 

3 6.98 4.60 

4 0 0 

5 0 0 

6 0.11 0.02 

ESA fish species present/ habitat g/ 1 stream Oregon Coast ESU 

Coho, assumed habitat T, CH 

None 

StreamNet –anadromous fish distribution h/ 1 stream – assumed None 

Geotechnical 

Steep or difficult terrain (miles) i/ 0.00 0.00 
3-92 3.0 – Alternatives 

TABLE 3.4.2.11-1 

Comparison of the OWL Southern Variation with the Corresponding Segment of Proposed Route (MPs 85.4 to 86.5)

Alternatives Analysis OWL Southern Variation * 

Corresponding Segment of 

Proposed Route ** 

Highly erosive soils (miles) j/ 0.92 1.35 

Cultural Resources 

Number of previously recorded cultural resources 0 0 

Number of newly identified cultural resources k/ N/A N/A 

* Called the proposed route in the draft EIS. 

** Called the Oregon Women’s Last Trust Variation in the draft EIS. 

a/ Acres of permanent easement calculated based on a 50-foot width. 

b/ Based on field surveys. 

c/ Pacific Northwest Hydrography Framework Clearinghouse data layers (http://hydro.reo.gov/). 

d/ From NWI mapping - access was denied on the majority of the parcels crossed by this route. 

e/ USFS 2004: PNW-GTR-648. 

f/ See description in Pacific Connector’s Resource Report 3 in its September 2007 application. 

g/ FWS, NMFS, and StreamNet (http://www.streamnet.org). 

h/ ODFW 2000a; ODFW 2006b; StreamNet. 

i/ Based on Soil Mapping Units that have slopes of 50 to 75 percent and have a water erosion rating of high or severe (NRCS 

2004). 

j/ Based on Soil Mapping Units that have a water erosion rating of high or severe (NRCS 2004). 

k/ This route has not been surveyed. 

3.4.2.12 MPs 105 to 112 - Umpqua National Forest Route Variations 

Pacific Connector’s original pipeline route (May 2006) followed Wildcat Ridge in a generally 

southeastern direction from about MP 105.6 until approximately MP 108.5, where it would turn 

east along the edge of an LSR for approximately 0.5 mile before turning southeast and crossing 

Long Prairie. The Umpqua National Forest proposed an alterative route through this area that 

would generally follow existing Forest Road 3200. In the opinion of the USFS, following this 

existing road corridor would minimize forest fragmentation and other effects on the South 

Umpqua River/Galesville LSR RO223, as well as NSO critical habitat units (CHUs), and would 

also avoid cultural resource concerns at Long Prairie, and minimize impacts on Riparian 

Reserves. This routing would also avoid crossing the East Fork of Cow Creek, as well as the 

streams and wetlands at its headwaters. 

Pacific Connector studied the USFS alternative, and for the reasons discussed below identified a 

compromise route, that was filed as the proposed route in Pacific Connector’s September 2007 

application to the FERC, and analyzed as the proposed route in the draft EIS. In the draft EIS we 

analyzed the original May 2006 route (called the Wildcat Ridge/Long Prairie Route Variation) 

and the USFS’s suggested route along Forest Road 3200 (called the Forest Road 3200 Route 

Variation) as potential alternatives to the corresponding segment of proposed route. 

We do not recommend use of the original May 2006 route (Wildcat Ridge/Long Prairie Route 

Variation). The USFS and the Cow Creek Tribe indicated that this route variation had the 

potential to impact an important traditional cultural property, and USFS also raised issues related 

to the crossing of an LSR. We also do not recommend use of the Forest Road 3200 Route 

Variation, because of Pacific Connector’s concerns about its constructability, including: 

• High risk of landslide occurrence due to headwall swales and from constructed fill 

slopes; 
3-93 3.0 – Alternatives 

• Earthwork necessary to construct a 95-foot-wide construction right-of-way on side slopes 

exceeding 70 percent along the variation is considered infeasible for geotechnical 

reasons; 

• Steep side slopes (greater than 50 percent) would require significant excavations to 

construct a 95-foot-wide construction corridor. Based on anticipated range of excavation, 

the cutslope would be between approximately 100 and 135 feet in height, and the 

excavation would extend at least 50 feet upslope of the existing cutslope; and 

• Up to 25,000 cy of excavation material would be generated for every approximately 100 

feet of right-of-way along the steep slopes. 

Subsequently, the USFS commented that the compromise route (filed in September 2007) would 

cross an area planned for expansion of the Peavine rock quarry, and issues were raised about the 

crossing of the East Fork of Cow Creek. The Peavine quarry is the largest and most extensively 

developed quarry within the upper reaches of the watershed and is of strategic importance to the 

Umpqua National Forest. The USFS also requested that the pipeline avoid a known NSO nest 

patch, as recommended during interagency working group meetings on endangered species. The 

USFS asked that Pacific Connector complete the necessary environmental and engineering field 

investigations to accommodate this shift, and we recommended in the draft EIS that Pacific 

Connector continue to work with the USFS to identify a preferred route for the segment of the 

pipeline in the area of Peavine quarry between about MPs 109 to 111. Pacific Connector 

consulted with the USFS about sensitive resources along the route, conducted site visits with the 

USFS and additional field studies, and identified a new routing in this area. In a letter to the 

FERC dated November 19, 2008, the Umpqua National Forest found the Peavine quarry reroute 

acceptable, and requested that the final EIS discuss it as the preferred alternative. 

In a filing on December 4, 2008, Pacific Connector adopted the Peavine Quarry Route Variation 

as part of its proposed route. The new proposed route and route variations in this area are shown 

on figure 3.4-10 and table 3.4.2.12-1 includes a comparison of environmental variables between 

the variations and the corresponding segment of proposed route. 

The proposed route would avoid the Peavine quarry; avoid crossing the known NSO nest patch; 

provide better crossing locations of the East Fork Cow Creek; and avoid the Peavine Camp, a 

dispersed recreation site. The proposed route is environmentally preferable, and we do not 

recommend any of the other route variation between MPs 105 and 111. 
3-94 3.0 – Alternatives 

Figure 3.4-10. Umpqua National Forest Route Variations (MP 105 to MP 112) Figure 3.4-10 

Umpqua National Forest Route 

Variations (MP 105 to MP 112) 
3-95 3.0 – Alternatives 

TABLE 3.4.2.12-1 

Comparison of the Umpqua National Forest Route Variations with the Corresponding Segment of Proposed Route (MP 

104.8 to MP 111.5) a/

Impact/Issue 

New 

Proposed 

Route 

Compromise Route – 

filed September 4, 

2007 

Wildcat Ridge/Long 

Prairie Variation 

(Original May 2006 

Route) Forest Road 3200 Variation 

General 

Total length (miles) 6.4 6.7 6.4 7.5 

Acres of construction 

right-of-way b/ 

73.4 76.8 73.2 86.1 

Number of TEWAs 51 55 Not designed but 

estimated to be less 

than the proposed 

route c/ 

Not designed. Pacific 

Connector determined this 

alternative to be unreasonable 

because of the significant 

pipeline integrity risks 

associated with steep side hill 

construction along the road, 

geologic hazards and because 

of the grading requirements 

(25,000 cy/100 feet). 

Acres of TEWAs 35.0 39.8 Not designed but 

estimated to be less 

than the proposed 

route c/ 

Not designed. Pacific 

Connector determined this 

alternative to be unreasonable 

because of the significant 

pipeline integrity risks 

associated with steep side hill 

construction along the road, 

geologic hazards and because 

of the grading requirements 

(25,000 cy/100 feet). 

Total acres of construction 

disturbance 

110.1 116.6 73.2 c/ See TEWA comment 

Number of UCSAs 2 2 Not designed c/ See TEWA comment 

Acres of UCSAs 1.7 5.1 Not designed c/ See TEWA comment 

Acres affected during 

operations (permanent 

easement) d/ 

45.3 40.61 38.5 86.1 

Land Ownership (miles) 

USFS 6.4 6.7 6.4 7.5 

Private 0.0 0.0 0.0 0.0 

State 0.0 0.0 0.0 0.0 

Geotechnical 

Miles of steep or difficult 

terrain to be crossed e/ 

0.15 0.4 0.1 Pacific Connector determined 

this alternative to be 

unreasonable because of the 

significant pipeline integrity 

risks associated with steep 

side hill construction along the 

road, geologic hazards and 

because of the grading 

requirements (25,000 cy/100’). 

Waterbodies and Wetlands f/ 

Number of waterbodies 

crossed g/ 

5 6 0 0 

Total waterbody crossing 

length h/ (feet) 

64 45 0 N/A 

Number of wetlands 

crossed h/ 

1 5 0 0 

Total wetland crossing 

length (feet) i/ 

13 328 0 0 

Total wetland disturbance 

during construction (acres 

0.1 0.3 0 0 

Land Use 

Land allocations (miles) 

Matrix 2.9 3.3 3.1 3.3 
3-96 3.0 – Alternatives 

TABLE 3.4.2.12-1 

Comparison of the Umpqua National Forest Route Variations with the Corresponding Segment of Proposed Route (MP 

104.8 to MP 111.5) a/

Impact/Issue 

New 

Proposed 

Route 

Compromise Route – 

filed September 4, 

2007 

Wildcat Ridge/Long 

Prairie Variation 

(Original May 2006 

Route) Forest Road 3200 Variation 

LSR 3.5 3.4 3.3 4.2 

Riparian Reserves 0.5 0.2 0.0 0.3 

Evergreen Forest, Mixed 

conifer (miles) 

4.2 3.9 3.4 5.6 k/ 

Regeneration Forest 

(miles) 

1.8 2.3 2.7 1.8 k/ 

Clearcuts (miles) 0.0 0.0 0.1 0.0 k/ 

Total forest lands affected 

(miles) 

6.0 6.2 5.9 7.4 k/ 

Other land use types 0.4 0.5 0.4 0.1 k/ 

Miles of right-of-way that 

would be parallel or 

adjacent to existing rightsof-way 

5.6 5.1 5.4 7.3 

Cultural Resources 

Number of previously 

identified cultural 

resources along route 

0 1 – site 

2 – isolated finds 

3 0 

Number of newly identified 

cultural resources along 

route 

1 – site 

2 – isolated 

finds 

N/A 1 N/A 

Critical Habitat 

Acres of federally listed 

critical habitat for NSO j/ 

52.1 33.4 33.8 40.3 (95-foot row only) 

Miles of federally listed 

critical habitat for NSO 

crossed 

6.4 6.7 6.3 7.5 

NSO core area (0.5 mile 

buffer of nest site) 

3 4 3 3 

a/ Mileposts correspond with topographic maps provided in Appendix 2-1. 

b/ The construction right-of-way for the proposed route and alternative route is 95 feet. 

c/ TEWAs for the alternative route have not been designed and are not included in the total acres of disturbance. Pacific 

Connector estimates that the number and acres of these would be less than those required for the proposed route because the 

alternative route does not cross any streams or have the length of slope crossings as does the proposed route. 

d/ The assumed permanent easement for both the proposed route and alternative route is 50 feet; however, Pacific Connector 

will only maintain vegetation within 15 feet of the pipeline centerline for a total of 30 feet in the long-term. 

e/ Based on slopes that are greater than 50 percent (based on 10-meter DEM). However, Pacific Connector has routed the 

alignment to ensure constructability, safety, and long-term stability by avoiding side slopes and approaching slopes with the 

alignment obliquely or perpendicularly to the slope. 

f/ Surveys are incomplete. 

g/ Waterbodies determined from field surveys on the proposed and draft EIS revised route. Waterbodies from both field surveys

(where available) and PNW Hydrography Framework Clearinghouse in areas where surveys incomplete. Ditches were excluded. 

h/ Based on review of aerial photos, topographic maps and LiDAR data. 

i/ Based on NWI coverages and photo interpretation. 

j/ Includes acres of impact associated with the construction right-of-way and TEWAs. This analysis used the final revised critical 

habitat designation (2008). 

k/ The proposed USFS route follows existing Forest Road 3200. Construction of the USFS proposed route would require 

extensive side-cuts; therefore, miles crossed considered habitat adjacent to the road. 

3.4.2.13 MP 122 – Rogue River Crossing Variation 

Pacific Connector proposes to cross the Rogue River just east of MP 122.6 using the HDD 

crossing method (refer to section 2 for a description of this method). We received comments 

expressing concern about potential project-related effects on the Rogue River and its aquatic 

resources, and to recreation use during construction. A successful HDD crossing would not 

affect river use during construction, would not affect scenery on or near the riverbank, would 
3-97 3.0 – Alternatives 

avoid the removal of riparian vegetation, and would avoid impacts on aquatic resources in the 

waterbody. However, there is a chance that during an HDD crossing there could be a release of 

drilling mud (called a frac-out) into the river, that may affect salmon and other aquatic species 

There is also the possibility that an attempted HDD crossing could fail, in which case Pacific 

Connector has indicated in its contingency plan that one alternative may involve an open-cut 

crossing of the Rogue River (see additional discussion of potential effects of a frac-out and the 

open cut contingency plan in sections 4.5.2.3 and 4.3.2.5). 

In its comments on the draft EIS, the ODFW requested that an overhead crossing of the Rogue 

River be considered as an alternative to an HDD crossing, to avoid the possibility of a frac-out 

and its potential impact on fish. Overhead river crossings for high pressure natural gas pipelines 

are rarely used and are generally restricted to waterbodies in very narrow, steep canyons. Pacific 

Connector has stated that an overhead crossing is not feasible at this location due to aesthetic and 

security issues. 

The advantage of an overhead crossing of the Rogue River would be avoidance of in-stream 

construction disturbance, and avoidance of the possibility of a drilling mud release during an 

HDD crossing. Provided that earth disturbance and concrete work required for the installation of 

abutments was properly isolated from the river, an overhead crossing would avoid entirely any 

in-water disturbance unless the span is wide enough that mid-river supports are needed. 

However, we believe that an overhead crossing, i.e., a bridge across the river, would have more 

impact on the river, both during construction and in the long term than an HDD crossing. 

Recreational use of the river would have to be suspended during construction. The crossing 

point is at a major bend in the river. Abutments for the structure would need to be placed well 

back from the river banks, preferably out of the 100-year floodplain. This would affect private 

property along both sides of the river. The overhead crossing would create a long-term, adverse 

visual impact for homeowners adjacent to the river and for recreationists floating the river. An 

overhead crossing would also require trenching across additional private property and crossing 

Ragsdale Road, Old Trial Creek Road, and State Highway 62. In addition, an overhead crossing 

would create a nuisance. There would be a long-term risk that, in spite of barriers and warning 

signs, some people would try to walk the pipe across the river. The overhead pipe would also be 

more susceptible to vandalism than a buried pipe. We do not feel that the risks of a temporary 

frac-out during construction, and the impact that this could have on fish, outweigh the 

environmental and safety concerns that an overhead crossing would entail. Therefore, we do not 

recommend using the overhead crossing method. 

3.4.2.14 MPs 144 to 145 – C2 Cattle Company Variation 

On February 8, 2008, the C-2 Cattle Company (C-2) filed a motion for late intervention. In that 

filing, C-2 indicated that although they thought they had negotiated an acceptable pipeline route 

across 7 miles of their lands that would avoid adverse impacts to irrigated fields and 

conservation easements, the proposed route filed by Pacific Connector in September 2007 did 

not reflect those negotiated changes. Therefore, C-2 identified two potential route variations. 

One route variation would follow Salt Creek Road to Highway 140 and avoid C-2’s ranch lands 

and conservation easements entirely. The other route variation would still be on C-2 ranch lands, 

but would avoid most forested lands, irrigated fields, and conservation easements. 

On March 4, 2008, Pacific Connector filed a new route alternative across the C-2 ranch, based on 

desktop data, that it believes would reduce impacts on irrigated pasture, forest, and conservation 
3-98 3.0 – Alternatives 

easements. Pacific Connector states that this route was based on the route negotiated with C-2 

Cattle Company that was erroneously not incorporated into the proposed route filed with the 

Commission in September 2007. We analyzed the March 2008 alternative route in the draft EIS 

as the C-2 Cattle Company Variation. Our draft EIS recommended that Pacific Connector 

incorporate the C-2 Cattle Company Variation as its proposed route. 

Once survey permission was granted, Pacific Connector met with C-2 representatives to discuss 

the alternative alignment. Based on its discussions with the company, Pacific Connector adopted 

the negotiated route into its proposed route between MPs 144.21 and 145.12. The environmental 

variables are compared between the proposed route and the C-2 West Variation in table 3.4.2.14-

1 and the currently proposed route and the September 2007 route (now called the C-2 West 

Variation) are illustrated in figure 3.4-11. Because the proposed route minimizes impacts on 

irrigated pasture and conservation easements within the C-2 ranch, we find it environmentally 

preferable to the alternative route variation segment. 

TABLE 3.4.2.14-1 

Comparison of the C2 Cattle Company with the Corresponding Segment of Proposed Route

Alternatives Analysis 

C-2 West Variation 

(September 2007 route) Proposed Route 

General 

Length (miles) 0.93 1.31 

Construction right-of-way (acres) 10.67 15.08 

Number of TEWAs 4 10 

Acres of TEWAs 2.82 3.84 

Permanent easement (acres) a/ 5.64 7.94 

Land Use 

Private 0.93 1.31 

State 0.00 0.00 

Land 

Ownership 

(miles) Federal (BLM/NFS Lands) 0.00 0.00 

Number of landowner parcels crossed 1 1 

Number of residences within 50 feet of construction 

right-of-way 0 0 

Miles of right-of-way parallel or adjacent to existing 

rights-of-way (percent of alternative length) 0.14 (15 percent) 0.08 (6 percent) 

LSR – Federal land use designation (acres) 0.00 0.00 

Riparian Reserves - federal land use designation (acres) 0.00 0.00 

Waterbodies and Wetlands 

Number of wetland and waterbodies crossed b/ 5 (2 perennial/3 ditches) 2 perennial 

Length of wetlands and waterbody crossings (feet) b/ 39.24 6 

Number of wetlands crossed c/ 1 0 

Length of wetland crossings (feet) c/ 0.03 0 

Vegetation 

Agricultural lands affected (acres) 1,631 1,558 

Total forest clearing (acres) 5.71 6.42 

 Acres Clearcut/Regenerating (0 to 40 years) 0.00 0.00 

 Acres Mid-seral Forest (40 to 80 years) 5.42 6.07 

Acres Late-Successional Forest (80 to 175 years) 0.29 0.35 

Old-Growth Forest (175 +) 0.00 0.00 

Biological Resources 

Northern spotted owl suitable habitat crossed (feet) d/ 4.44 1.76 

Northern spotted owl nest patch/cores (NSO) 0 0 
3-99 3.0 – Alternatives 

TABLE 3.4.2.14-1 

Comparison of the C2 Cattle Company with the Corresponding Segment of Proposed Route

Alternatives Analysis 

C-2 West Variation 

(September 2007 route) Proposed Route 

Northern spotted owl critical habitat crossed (feet) 0 0 

Habitat 1 0 0 

2 12.58 18.04 

3 0.00 0.61 

4 0.00 0.00 

5 0.07 0.01 

category(acres) e/ 

6 0.84 0.26 

ESA fish species present/habitat f/ 1 Stream SONCC Coho 

assumed habitat T, CH 

1 Stream SONCC Coho assumed 

habitat T, CH 

StreamNet – anadromous fish distribution g/ 1 stream assumed 1 stream assumed 

Geotechnical 

Steep or difficult terrain (miles) h/ 0.00 0.00 

Highly erosive soils (miles) h/ 0.43 0.49 

Cultural Resources 

Number of previously recorded cultural resources 1 – site 1 – site 

Number of newly identified cultural resources i/ N/A 2 - isolated finds 

a/ Acres of permanent easement calculated based on a 50-foot width. 

b/ From wetland and waterbody surveys and Pacific Northwest Hydrography Framework Clearinghouse data layers 

(http://hydro.reo.gov/). 

c/ No wetlands are crossed based on field surveys. 

d/ USFS 2004: PNW-GTR-648. 

e/ From Pacific Connector’s Application filed in September 207, Resource Report 3. 

f/ FWS, NMFS, and StreamNet (http://www.streamnet.org). 

g/ ODFW 2000a; ODFW 2006b; StreamNet. 

h/ Based on Soil Mapping Units that have slopes of 50-75 percent and have a water erosion rating of high or severe (Soil 

Conservation Service 1993). 

i/ Based on Soil Mapping Units that have a water erosion rating of high or severe (Soil Conservation Service 1993). 
3-100 3.0 – Alternatives 

Figure 3.4-11. C-2 Cattle Company Route Variation (MP144.2 to MP 145.1) Figure 3.4-11 

C-2 Cattle Company Route Variation 

(MP 144.2 to MP 145.1) 
3-101 3.0 – Alternatives 

3.4.2.15 MPs 155 to 169 - Robinson Butte to Burton Butte/Forest Service Roads Route 

Variations 

In August 2006, the USFS requested that the FERC study an alternative route over portions of 

the Rogue River-Siskiyou and Fremont-Winema National Forests. Our analysis below discusses 

the original route identified by Pacific Connector in May 2006 (Alternative 1), the USFS 

suggested route variation, mostly following existing Forest Service roads (Alternative 2), and the 

corresponding segment of proposed route, which is a compromise route subsequently identified 

by Pacific Connector. Each of these routes is shown on figure 3.4-12. Alternatives 1 and 2, and 

the corresponding segment of the proposed route, are compared in table 3.4.2.15-1. 

The route originally identified by Pacific Connector in May 2006 would deviate from the 

currently proposed route at about MP 155, and remain south of it on the south side of Robinson 

Butte near MP 159. From that point southeastwardly, Alternative 1 would closely follow the 

proposed route but would be straighter and cross through older forests, which provide spotted 

owl habitat. As with the proposed route, Alternative 1 would cross Big Elk Road, cross 

northeast of Cox Butte, and would cross Daley Prairie. The original route would cross into 

Klamath County and rejoin the proposed route near MP 169. 

Alternative 1 would be about a mile shorter than the corresponding segment of proposed route. 

The route variation would cross more waterbodies and wetlands, and would affect more forest. 

The corresponding segment of proposed route would be adjacent to existing rights-of-way to a 

greater extent. 

The USFS suggested route variation, labeled Alternative 2, would leave the proposed route 

within the Rogue River National Forest in Jackson County, Oregon at about MP 155, north of 

Grizzly Canyon, and head east along Forest Service Roads 410 and 300, around the south side of 

Robinson Butte along Forest Service Road 3730, south of Big Elk Guard Station along Forest 

Service Road 3705, across the South Fork Little Butte Creek, turn east along Forest Service 

Road 3720, entering Klamath County, to Forest Service Road 700, cross the PCT several miles 

south of Brown Mountain, then head southeast cross-county into the Winema National Forest, 

across Dead Indian Memorial Highway, and would rejoin the proposed route along Clover Creek 

Road north of Burton Butte just east of MP 169. The variation would avoid clearing a new 

corridor, reducing forest fragmentation and habitat loss in the Dead Indian LSR RO227. Also, 

this alternative would cross the PCT along an existing road, reducing potential impacts to trail 

users by eliminating a separate crossing. The USFS suggested variation would be about 3 miles 

longer than the original route and would require widening the existing roads, which are generally 

between 20 and 30 feet wide. This would require cutting mature forest in portions of the rightof-way. 

Pacific Connector studied the USFS suggested variation and determined that the alignment was 

feasible for the most part, except where it followed tight radius road curves. In late September 

2006, Pacific Connector met with the USFS to discuss the variation, as well as to explain project 

construction requirements. As a result of consultations with the USFS, Pacific Connector 

modified its original May 2006 route to adopt segments of the USFS suggested variation, and 

incorporated the modified route into its proposed route as filed with the Commission on 

September 4, 2007. The compromise route made further adjustments to the alignment to 

minimize side slope construction and extra work area requirements, and to avoid a wetland 
3-102 3.0 – Alternatives 

Figure 3.4-12. Robinson Butte to Burton Butte Route Variations (MP 155 to MP 169) 3.4-12 
3-103 3.0 – Alternatives 

TABLE 3.4.2.15-1 

Comparison of Robinson Butte to Burton/Forest Service Roads Variations with the 

Corresponding Segment of Proposed Route (MP 155 to MP 169) a/

Impact/Issue

Original Route 

(Alternative 1) 

USFS Suggested Variation 

(Alternative 2) Proposed Route 

General

Total Length (miles) 12.9 15.7 13.8 

Acres of construction right-of-way b/ 148.0 180.4 159.4 

Number of TEWAs Not designed, but estimated 

to require more than the 

proposed route c/

Not designed d/ 61 

Acres of TEWAs Not designed, but estimated 

to require more than the 

proposed route c/

Not designed d/ 49.7 

Total acres of construction disturbance 148.0 c/ 180.4 d/ 209.1 

Number of UCSAs Not designed e/ Not designed e/ 45 

Acres of UCSAs Not designed e/ Not designed e/ 73.0 

Acres affected during operations (permanent 

easement) f/

77.9 95.0 83.9 

Land Ownership (miles) USFS 11.5 14.3 12.5 

 Private 0.5 0.6 0.5 

 State 0.0 0.0 0.0 

Geotechnical

Miles of steep or difficult terrain crossed g/ 0.00 0.00 0.00 

Waterbodies and Wetlands

Number of waterbodies crossed h/ 11 8 6 

Total waterbody crossing length (feet) i/ 1,317 j/ N/A k/ N/A k/

Number of wetlands crossed 3 N/A k/ 1 

Total wetland crossing length (feet) l/ 422 N/A k/ 56 

Total wetland disturbance during construction 

(acres) 

0.7 N/A k/ 0.1 

Land Use

Land allocations (miles) Matrix 0.0 0.0 0.0 

 LSR 11.5 14.3 12.5 

Riparian 

Reserves 

1.5 1.1 0.4 

Evergreen Forest, Mixed Conifer 6.8 6.0 6.1 

Regeneration Forest (miles) 5.9 5.4 5.6 

Clearcuts (miles) 0.1 0.0 0.3 

Total Forest lands affected (miles) 12.8 11.4 12.0 

Other land use types (including 

Transportation) 

0.1 4.3 1.8 

Miles of right-of-way that would be parallel or 

adjacent to existing rights-of-way 

1.6 14.0 4.4 

Recreation

Pacific Crest Trail (PCT) Mitigation required – See 

section 4.7.4.3 

PCT would be crossed within 

existing Forest Road (FR# 

700) corridor 

Mitigation required - 

See section 4.7.4.3 

Brown Mountain Trail and Trailhead No impacts During construction, trailhead 

area and trail section would be 

relocated or closed and later 

reconstructed and mitigated. 

No impacts 
3-104 3.0 – Alternatives 

TABLE 3.4.2.15-1 

Comparison of Robinson Butte to Burton/Forest Service Roads Variations with the 

Corresponding Segment of Proposed Route (MP 155 to MP 169) a/

Impact/Issue

Original Route 

(Alternative 1) 

USFS Suggested Variation 

(Alternative 2) Proposed Route 

South Brown Mountain Shelter No direct impacts – 

construction activities would 

be audible from the shelter. 

No direct impacts – 

construction activities would 

be audible from the shelter. 

This alternative is closer than 

the other two routes. 

No direct impacts – 

construction activities 

would be audible from 

the shelter. 

Visual Impacts along existing Forest roads Minimal except at existing 

road crossings 

Existing road corridors 

expected to be significantly 

altered from 95-foot 

construction footprint along 

13.6 miles of Forest roads. 

Minimal except where 

parallel to existing 

roads (i.e., 4.4 miles) 

Cultural Resources

Number of previously identified cultural 

resources along route 

1 0 k/ 1 

Number of newly identified cultural resources 

along route 

0 k/ 0 k/ 0 

Critical Habitat

Acres of federally listed critical habitat for the 

NSO m/

148.0 180.3 159.4 

NSO activity center 2 - 1⁄2 mile buffer of site 2 - 1⁄2 mile buffer of site 2 - 1⁄2 mile buffer of site

a/ Mileposts were calculated from topographic maps. 

b/ The construction right-of-way for the proposed route and original proposed alignment is 95 feet. 

c/ Pacific Connector estimates that the original route would likely require more TEWAs compared to the proposed route because of

side slope construction between approximately MPs 149.0 and 152.9, and because of the increased number of stream crossings 

along the original route. 

d/ TEWAs have not been designed for this route and are not included in total construction work area requirements. 

e/ TEWAs for the original route have not been designed and are not included in the total acres of disturbance. 

f/ The assumed permanent easement for all routes is 50 feet. However, Pacific Connector will only maintain vegetation within 15

feet of the pipeline centerline for a total of 30 feet in the long term. 

g/ Based on slopes that are greater 50 percent (based on 10-meter DEM). However, Pacific Connector has routed the alignment to 

ensure constructability, safety, and long-term stability by avoiding side slopes and approaching slopes with the alignment obliquely 

or perpendicularly to the slope. 

h/ Waterbodies from PNW Hydrography Framework Clearinghouse. 

i/ Based on ground survey and review of aerial photos, topographic maps, and LiDAR data. 

j/ Crossing distance based on parallel alignment with waterbody feature (i.e., intermittent stream) 

k/ Surveys are incomplete or in progress on the proposed route and will be completed late summer of 2007. 

l/ Based on ground survey, NWI coverages and photo interpretation. 

m/ Includes acres of impact associated with the construction right-of-way and TEWAs. 

(Riparian Reserve) identified during the Project’s wetland and waterbody surveys. This 

adjustment utilized an existing forest road and regenerating clear-cut area to minimize impacts to 

mature forest. 

The USFS suggested variation along Forest Roads would be the longest pipeline route through 

this area and result in the largest construction footprint. In concept, acreage of construction 

impact would be mitigated by the fact that most of the route (14.0 of 15.7 miles) would be along 

existing forest road. However, Pacific Connector has determined that the pipeline would not be 

constructable along some portions of the roads due to terrain and tight radius turns. All three 

routes would cross LSR and Riparian Reserve, with the original route crossing the least distance 

of LSR, and the corresponding segment of proposed route crossing the least distance of Riparian 

Reserve. Of the three routes, the USFS suggested variation would cross the PCT along an 

existing road and would likely have the least impact on visual character of the trail in the 

immediate vicinity of the pipeline crossing. We have also identified a route variation 

specifically for the PCT crossing (see below). We believe that the compromise route in this area, 
3-105 3.0 – Alternatives 

which Pacific Connector has incorporated into its proposed route, would avoid or minimize 

environmental impacts, and neither the May 2006 route, nor the USFS suggested variation would 

be environmentally preferable to the proposed route. 

In a letter to the FERC dated November 14, 2008, the Rogue River-Siskiyou National Forest 

recommended a reroute between MPs 161.23 and 161.38 to avoid the Big Elk NSO patch located 

in a NSO core area. This route alternative would be about 0.5 mile south of Big Elk Meadow 

and Guard Station. In a filing on December 4, 2008, Pacific Connector adopted this variation 

into its proposed route. We find this new proposed route segment acceptable. 

3.4.2.16 MPs 167 to 168 - Pacific Crest Trail Variation 

The pipeline route Pacific Connector filed with its September 2007 application to the FERC 

would cross the PCT at MP 167.8. The September 2007 route for the pipeline crossing of the 

PCT was a straight alignment. The USFS pointed out that this would create an unnatural tunnellike visual effect through the forest that would not meet the USFS standards for Retention or 

Partial Retention Visual Quality Objective (VQO) for the PCT crossing. Pacific Connector 

proposed measures to reduce the width of the construction right-of-way at the crossing, as well 

as other measures to minimize impacts on users of this trail (see section 4.7.3.6). However, in 

order to further reduce the long-term visual impact on users of the trail, we identified a minor 

route variation at the crossing of the PCT. 

In the draft EIS we evaluated a variation, called the Pacific Crest Trail Variation, that would begin 

at about MP 167.6, where it would turn east from the September 2007 route for about 0.2 mile, 

then back south for about 0.2 mile before rejoining the September 2007 route at MP 168.15. In the 

draft EIS we recommended that Pacific Connector incorporate the variation into its proposed route. 

The PCT Variation would cross lands managed by the Rogue River-Siskiyou and FremontWinema National Forests. In letters to the FERC dated November 14 and 26, 2008, the National 

Forests indicated that the variation would reduce the sight distance of viewing the pipeline right-ofway from the trail, and requested that it be analyzed as the preferred alternative in the final EIS. 

In its December 4, 2008 filing, Pacific Connector adopted the PCT Variation into its proposed 

route. In this final EIS we call the September 2007 route the PCT Variation South. The 

environmental variables are compared in table 3.4.2.16-1 and the new proposed route and 

variation are shown on figure 3.4-13. 

TABLE 3.4.2.16-1 

Comparison of the PCT Variation South with the 

Corresponding Segment of Proposed Route (MP 167.6 to MP 168.2) 

Impact/Issue PCT South Variation * Proposed Route 

Length (miles) 0.48 0.57 

Construction right-of-way (acres) 5.6 6.4 

TEWAs (acres) 0 2 

Permanent easement (acres) a/ 3.0 3.5 

Number of residences within 50 feet of the construction right-of-way 0 0 

Number of waterbodies crossed b/ 0 0 

Length of waterbody crossings (feet) b/ 0 0 

Number of wetlands crossed c/ 0 0 
3-106 3.0 – Alternatives 

TABLE 3.4.2.16-1 

Comparison of the PCT Variation South with the 

Corresponding Segment of Proposed Route (MP 167.6 to MP 168.2) 

Impact/Issue PCT South Variation * Proposed Route 

Wetlands affected (acres) 0 0 

Agricultural lands affected (feet) 0 0 

Forest/woodland clearing (acres of construction right-of-way) 5.6 7.1 

Regenerating forest clearing (acres of construction right-of-way) 2.1 4.1 

Old-growth forest cleared (acres) 3.5 2.8 

NSO habitat crossed (acres) 5.6 6.8 

NSO nest patches/cores (acres) 0 0 

NSO critical habitat crossed (acres) 2.7 3.6 

Number of previously recorded cultural resources 0 0 

Miles of right-of-way parallel or adjacent to existing rights-of-way 0 0 

* Referred to as the Proposed Route in the draft EIS.

a/ Acres of permanent easement calculated based on crossing length on federal timber lands.. Pacific Connector proposes a 

53-foot permanent easement on federal lands. 

b/ From Pacific Connector wetland and waterbody surveys (Table 2A-3 in Appendix 2A to Resource Report 2) and Pacific 

Northwest Hydrography Framework Clearinghouse data layers (http://hydro.reo.gov). 

c/ No wetlands are crossed on the proposed alignment based on field surveys (Table 2A-3 in Appendix 2A to Resource Report 

2). 

The new proposed route would be slightly longer (about 0.1 mile), and construction would affect 

about 0.9 acre more than the PCT Variation South. It would require three more bends at pointsof-intersection, resulting in the clearing of additional land for TEWAs. These TEWAs would be 

located within regenerating forest. Based on a desktop analysis, Pacific Connector concluded 

that the new proposed route would be buildable. Pacific Connector indicated that the proposed 

route would reduce visual impacts on the trail, and would minimize the crossing length through 

old-growth forest within Ichabod Quarry South NSO Home Range. 

The advantage of the new proposed route is that it would reduce the length of the permanently cleared 

pipeline right-of-way that would be visible from the trail. It is estimated that for the PCT Variation 

South, about 4,000 feet of cleared right-of-way would be visible from the trail/right-of-way 

intersection. The visible right-of-way would be reduced to about 1,000 feet by using the new proposed 

route. Because the visual impact of the pipeline crossing of the PCT would be a long term impact, we 

believe the new proposed route would be environmentally preferable to the PCT Variation South. 
3-107 3.0 – Alternatives 

Figure 3.4-13. Pacific Crest Trail Route Variation (MP 167.6 to MP 168.1) Figure 3.4-13 

Pacific Crest Trail Route Variation 

(MP 167.6 to MP 168.1) 
3-108 3.0 – Alternatives 

3.4.2.17 MPs 169 to 190 - Buck Lake/Keno Road and Clover Creek Road Route 

Variations 

Pacific Connector’s original Pre-filing (May 2006) pipeline route would leave the proposed route 

at about MP 171 and head southeast across Buck Lake to Keno Road, which it would follow for 

about five miles. The May 2006 route would have then turned east from Keno Road cross 

country, and then southeast along trails to the existing GTN pipeline (1994 PGT Expansion II 

route). It would then follow the GTN pipeline corridor eastward, on the north side of the 

Klamath River, to where it would rejoin the proposed route near MP 190. The May 2006 

pipeline route is labeled the Buck Lake/Keno Road Variation in the discussion below (figure 3.4-

14). 

During the Pre-filing process, the BLM and USFS recommended an alternative route to follow 

Clover Creek Road because it would avoid known habitat for the Oregon spotted frog in the 

vicinity of Buck Lake, an extensive wet meadow; and trout spawning area. In addition, in a 

letter filed February 5, 2007, the attorney for the owner of Buck Lake objected to the May 2006 

route and requested a route re-alignment. Therefore, Pacific Connector identified the route 

proposed in its September 2007 application. This route was analyzed in the draft EIS as the 

proposed route. In this final EIS it is called the Clover Creek Road Offset Variation (see figure 

3.4-14). 

Subsequently, the USFS requested that Pacific Connector evaluate an alternative alignment to 

the route along Clover Creek Road between MPs 170.9 and 187.7 that would be directly adjacent 

to the road, rather than off-set, to eliminate the strip of trees that would be left between the road 

and cleared right-of-way. The USFS believes a route that would locate the pipeline directly 

adjacent to Clover Creek with no tree buffer would reduce ground disturbance and reduce 

impacts on land management for owners of the buffer strip. In the draft EIS this route alignment 

was called the Clover Creek Road Variation. We recommended in the draft EIS that Pacific 

Connector incorporate the Clover Creek Road Variation into its proposed route, except in places 

where there were topographic constraints. In a letter to the FERC dated November 26, 2008, the 

Fremont-Winema National Forest indicated that the Clover Creek Road Variation was 

acceptable, with minor adjustments for topography, and requested that this final EIS consider 

this route as the preferred alternative. 

In its December 4, 2008 comments on the draft EIS, Pacific Connector stated that it had adopted 

the Clover Creek Route Variation into its proposed route between MPs 171.1 and 187.4. The 

alignment had to deviate from the road in a few places (MPs 172.3 to 172.5, 173.0 to 173.7, 

182.3, and 184.2 to 184.9) to avoid areas of steep slope or road cuts with fill slopes. In addition, 

the alignment separated from the road where it was immediately adjacent to a waterbody, and to 

avoid wetlands (at MPs 172.5 and 173.5 to 174.5). The new proposed route and variations are 

shown on figure 3.4-14, and table 3.4.2.17-1 compares the variations to the corresponding 

segment of the new proposed route. 

The Buck Lake/Keno Road Route Variation would be nearly 1.8 miles longer and disturb 

approximately 26 additional acres on all ownerships compared to the corresponding segment of 

proposed route. The primary advantage of the variation is that it would cross about 2.1 fewer 

miles of federal lands, and cross 0.2 mile less NSO critical habitat than the corresponding 
3-109 3.0 – Alternatives

Figure 3.4-14 Buck Lake/Keno Road and Clover Creek Road 

Route Variations (MP 170.9 to MP 188.8) 
3-110 3.0 – Alternatives 

TABLE 3.4.2.17-1 

Comparison of the Buck Lake/Keno Road and Clover Creek Road Route Variations with the Corresponding Segment of 

Proposed Route (MP 169 to MP 190) a/

Impact/Issue 

Clover Creek Road Offset 

Variation (called Proposed 

Route in draft EIS) 

Buck Lake/Keno Road 

Route Variation Proposed Route 

General 

Total length (miles) 16.9 18.7 16.9 

Acres of construction right-of-way a/ 187.4 215.3 287.5 

Number of TEWAs 51 103 87 

Acres of TEWAs 16.7 83.0 27.0 

Acres affected during operations 

(permanent easement)/

98.7 140.4 98.7 

Landowner parcels crossed 9 16 9 

Number of residences within 50 feet of 

construction right-of-way 

0 0 0 

Private 11.7 15.7 11.7 

State 0 0.2 0 

Federal (BLM/NFS lands) 4.6 2.8 4.7 

Geotechnical 

Miles of steep or difficult terrain to be 

crossed 

0 0 0 

Waterbodies and Wetlands 

Number of wetlands and waterbodies 

crossed 

9 23 9 

Length of wetlands and waterbodies 

crossed (miles) 

0.2 2.1 0.2 

Land Use 

Agricultural land affected (miles) 0 9.5 0 

Forest lands affected (acres) 161 71 172 

Regenerating forest clearing (acres) 54 85.2 53 

Miles of right-of-way that would be 

parallel or adjacent to existing rights-ofway 

16.9 - 16.8 

Biological Resources 

Oregon spotted frog habitat crossed b/ Avoided Yes Avoided 

Klamath red band trout habitat crossed c/ Avoided Yes Avoided 

Critical habitat miles crossed d/ 0 1.6 0 

Critical habitat acres within 1 

mile of route d/

Similar to original Clover 

Creek Road route variation 

4238 2,514 

Suitable habitat within 1 mile of 

route e/

Similar to original Clover 

Creek Road route variation 

6547 5,534 

NSO 

Number Similar to original Clover 

Creek Road route variation 

3 NSO within 1 mile of 

route (1 historical) 

2 NSO within 1 mile of 

route (1 historical) 

Bald eagle f/ Similar to original Clover 

Creek Road route variation 

2 active nests within 

0.3 mile of route 

1 active nest within 0.6 

mile of route 

a/ The construction right-of-way for the proposed route and the alternative is 95 feet. 

b/ Known Habitat of the Oregon spotted frog would be crossed on the proposed route between MPs 171.29 and 191.34 in Wetland AW 

182. Pacific Connector would utilize conservation measures to minimize impacts to the spotted frog such as seasonal construction 

windows to avoid critical breeding periods and life stages. The alternative route would avoid the known Oregon spotted frog habitat. 

c/ The proposed route crosses Spencer Creek above River Mile 12 in areas of known red band trout spawning habitat. Pacific 

Connector would use conservation measures to minimize impacts to the red band trout, including using the “dry” open cut crossing 

method (flume or dam and pump) within the ODFW-specified crossing window to protect the trout. The Offset Alternative crosses 

Spencer Creek above River Mile 12 where red band trout is not documented. Pacific Connector would also use the “dry” open cut 

crossing method within the ODFW-specified crossing windows to minimize impacts to aquatic species. 

d/ NSO critical habitat coverage obtained from FWS Critical Habitat Portal [online: http://criticalhabitat.fws.gov/]. 

e/ NSO suitable habitat determined through GIS analysis using a BioMapper product created by the USFS Pacific Northwest Research 

Station and further refined based on consultation with FWS using aerial photo reconnaissance and GIS Neighborhood Analysis to 

determine areas with at least 30 percent suitable habitat. 

f/ Bald eagle documented sites from bald eagle nest locations and history of use in Oregon and the Washington portion of the Columbia 

River Recovery Zone, 1971 through 2006 (Isaacs and Anthony 2007). 

segment of proposed route. The variation would also avoid visual impact that would result from 

construction of about 16.5 miles of the corresponding segment of proposed route parallel to 

Clover Creek Road (see section 4.7.3.7 of this EIS). The disadvantages of the variation are that 
3-111 3.0 – Alternatives 

it would affect 2.8 more miles of private land, five more landowners, 11 more waterbodies, 1.9 

miles of wetlands, and 9.5 miles more agricultural land than the corresponding segment of 

proposed route. Although the variation would cross less NSO critical habitat, it would be within 

1 mile of 1,724 more acres of NSO critical habitat and 1,014 more acres of NSO suitable habitat 

than the corresponding segment of proposed route. We believe the disadvantages of the 

variation outweigh any advantages, and that the variation would not be environmentally 

preferable to the corresponding segment of proposed route. Therefore, we do not recommend 

use of the Buck Lake/Keno Road Route Variation. 

3.4.3 General Discussion of Pipeline Alternatives Over Federal Lands 

Both the BLM and the USFS requested that that the FERC consider alternatives that would avoid 

or minimize disturbance to LSRs. In 1994, the Secretaries of Agriculture and Interior signed the 

Record of Decision for Amendments to the Forest Service and Bureau of Land Management 

Planning Documents with the Range of the Northern Spotted Owl (ROD). The ROD amended 

LRMPs for all National Forests within the range of the NSO in California, Oregon, and 

Washington states, and created new land use allocations known as LSRs and Riparian Reserves. 

The ROD indicated that LSRs are to be managed to protect and enhance old-growth forest 

conditions. 

All of the NFS lands on the Rogue River-Siskiyou National Forest lie within the Dead Indian 

LSR RO227, while about half of the proposed pipeline route across the Umpqua National Forest 

would be within the South Umpqua River/Galesville LSR RO223. There are no designated 

LSRs where the pipeline would be located within the Fremont-Winema National Forest. 

The ROD stipulates that non-silvicultural activities in LSR, such as the installation of a pipeline 

or other utilities, would only be allowed where those activities could be demonstrated to be 

neutral, or may have benefits for the creation and maintenance of late-successional habitat. New 

developments, such as a pipeline, may be allowed if it would have a public benefit and if adverse 

effects on the LSR could be minimized or mitigated. 

The USFS indicated that the Pacific Connector pipeline through NFS lands may conflict with 

resource management directions in the NWF, LRMPs, and specific LSRs and Watershed 

Assessments. The USFS indicated that it may have to amend its LRMPs for the Umpqua, Rogue 

River-Siskiyou, and Fremont-Winema National Forests to allow for a crossing of NFS lands by 

the pipeline, but have not yet provided details about those amendments. The USFS could tier its 

environmental analysis for its plan amendments off of this EIS. The alternatives analysis 

contained in this EIS could be adopted by the federal land managing agencies to maintain 

consistency with applicable agency standards and guidelines. Resource issues that are addressed 

in this EIS include avoiding or mitigating impacts on federally designated NSO CHUs, ACS and 

stream temperatures, MIS, existing and developing habitat in LSRs, Riparian Reserves, cultural 

resource sites, recreation, and visual impacts landform stability. In designing its pipeline project, 

Pacific Connector followed the principles outlined in the Regional Interagency Executive 

Committee memorandum dated January 3, 2001, regarding New Developments in LSRs. 

3.4.3.1 Public Need 

To verify that the Pacific Connector pipeline has a public need, Pacific Connector must apply for 

and receive a Certificate of Public Convenience and Necessity from the FERC. A FERC 
3-112 3.0 – Alternatives 

Certificate would verify that the Pacific Connector pipeline has a public need and provides 

significant public benefit. 

3.4.3.2 Avoidance of LSRs 

Because the proposed Pacific Connector pipeline is a linear, large-diameter, high-pressure 

natural gas pipeline that must be routed to ensure safety, stability and integrity, it is 

unreasonable, impractical, and infeasible to entirely avoid all designated LSRs for the following 

reasons: 

• The overall extent of the designated LSR land allocation in the area crossed by the 

pipeline on NFS lands makes it unrealistic to completely avoid LSRs; 

• Long re-routes around LSRs would be impractical because of other determining factors, 

such as topography, the overall length and direction of the pipeline, and the large size of 

individual LSRs within contiguous tracts of NFS lands; 

• Safety and constructability requirements for installation of the pipeline, in areas with 

limited geological hazards to ensure the long term integrity of the pipeline and stability of 

the right-of-way makes it infeasible and unreasonable to avoid LSRs by aligning the 

pipeline on steep side slopes or other potentially unstable areas. 

Commentors on the draft EIS asked if it was possible to use HDDs or conventional bores to 

avoid or reduce impacts on LSRs. Pacific Connector addressed this issue in a January 21, 2009 

filing with the FERC, responding to a staff December 29, 2008 data request. There are many 

geophysical factors that must be taken into consideration to determine if a HDD is feasible, 

including topography and underground strata. HDDs for large diameter pipelines have minimum 

required distances and radius angles. Relatively flat places are needed to set up the drilling rig 

and associated TEWAs to lay out, weld, and test pipe. A good access road to the drill location is 

necessary, to bring in the rig and support equipment. To minimize the chance for drill failure, 

the entry and exit points should be at similar elevations. 

There are also multiple considerations for each of the specific bore techniques (i.e., jack and 

bore, slick bore, hammer bore, etc.), including topography, land availability for TEWAs, soil 

types, and depth to groundwater. Conventional bores are generally limited to not more than 400 

feet in length, where underground strata is acceptable. Boring operations can be ineffective in 

areas with cobble and gravel substrata. The bore must be completed in a straight line, and the 

presence of shallow groundwater can be problematic for workers in the bore pit. Large TEWAs 

are required adjacent to bores for dewatering and continuous spoil/slurry processing. 

Topography may limit the safety of deep bore pits, with regards to OSHA limitations for workers 

in the pit. High water tables may make the walls of the pit unstable. 

In most of the places where the pipeline would cross Riparian Reserves, LSR, and old growth 

forest the terrain is rugged, with steep slopes, and rocky substrata. Therefore, it is infeasible for 

Pacific Connector to avoid LSRs using HDDs or bores due to the geometry and geological 

constraints for installing a 36-inch-wide high-pressure steel welded natural gas pipeline using 

either an HDD or bore in the topographic areas that contain the LSRs. 
3-113 3.0 – Alternatives 

3.4.3.3 Project Design Measures Implemented to Minimize Adverse Impacts on LSRs 

To comply with the Principles of the 2001 Regional Interagency Executive Committee 

memorandum regarding new developments in LSRs, this alternative analysis discusses how the 

proposed Pacific Connector pipeline and associated facilities have been designed to have the 

least possible adverse impacts on LSRs. In summary, this alternative analysis will discuss: 1) the 

project design measures that were implemented to avoid LSRs, where feasible; 2) the project 

design procedures that minimize impacts to LSRs; 3) the measures that would be implemented to 

rectify project-related impacts to LSRs; 4) the project design measures that would be applied to 

reduce impacts over time by maintenance operations during the life of the action; and 5) the 

compensatory mitigation that Pacific Connector proposes to mitigate for unavoidable impacts to 

LSRs. Attachment 1 in Pacific Connector’s response to recommendations in the draft EIS (filed 

with the FERC on December 4, 2008) provides a listing by MP where the pipeline would cross 

LSRs on NFS lands. 

Pacific Connector attempted to minimize impacts to LSRs during the proposed pipeline route 

selection and construction footprint design process through the following steps: 

• Performing routing and geotechnical evaluations to ensure the most stable pipeline 

alignment for long-term stability. These efforts minimize the potential need to conduct 

future maintenance activities, which could require additional impacts to suitable NSO 

habitat and LSRs; 

• Where feasible, the alignment was co-located with existing roads to minimize disturbance 

impacts; 

• Areas of side slopes were avoided to the extent possible to minimize the need for 

additional TEWAs to accommodate the necessary cuts and fill to safely construct the 

pipeline; 

• The number and size of the TEWAs in LSRs were minimized to those critical for safe 

pipeline construction; 

• Additional TEWAs were located in previously disturbed areas (recently logged) or in 

young regenerating forest stands; and 

• Existing roads would be used to access the construction right-of-way during construction 

and the right-of-way would be used as the primary travel-way to move equipment and 

materials up and down the right-of-way to remove the need for additional roads within 

LSRs on NSF land. The existing roads would also be used during operations to avoid the 

need for new access routes. 

To help rectify pipeline-related impacts to LSRs, Pacific Connector would replant all disturbed 

areas of the construction footprint as described in its ECRP. Pacific Connector would replant or 

allow trees to naturally regenerate to within 15 feet of the pipeline centerline within the 

permanent pipeline easement to minimize potential long-term effects of the pipeline easement. 

Vegetation within the remaining area of the pipeline easement would be maintained as necessary 

to allow for DOT-required visual aerial survey requirements, and to prevent the root systems of 

trees from damaging pipe coatings and pushing on the pipeline. 

Additionally, Pacific Connector understands that unavoidable impacts on LSRs would require 

mitigation measures that in the long run would make the Project impacts neutral or benefical. 

Pacific Connector has recently developed a revised draft of its Mitigation Plan for LSRs on NFS 
3-114 3.0 – Alternatives 

lands that outlines these measures (see Appendix L). Pacific Connector would provide 

mitigation funds to the USFS to reclaim existing disturbance areas within LSRs such as roads 

that are no longer required for resource management or other locations recommended by the 

USFS. These funds could also be utilized to complete non-economic thinning or other 

management projects to accelerate old growth characteristics within young or dense forest 

stands. These funds could also be used to acquire conservation easements or acquire adjacent 

lands or in-holding parcels within agency boundaries that could be managed to maintain LSR 

habitat. Additionally these funds could be used to re-designate matrix or other land to LSR 

where feasible. 

3.4.4 Minor Route Variations Incorporated into the Proposed Route 

During the course of refining the route alignment for the currently proposed route, Pacific 

Connector incorporated a number of minor route variations that differed from either the initial 

pipeline route it presented in May 2006 during Pre-fling or in September 2007 with its 

application to the FERC, to address landowner requests, constructability issues or constraints, or 

to avoid cultural resources or geological hazards., or reduce impacts on threatened or endangered 

species. In addition, in a December 4, 2008 filing, Pacific Connector made some minor route 

changes to avoid or reduce impacts on biological or botanical resources. These minor route 

variations are listed in table 3.4.4-1. In all the cases listed on the table below, we find the minor 

route changes to be environmentally preferable and acceptable. We have reviewed these minor 

variations, and agree that these variations should be incorporated into the proposed route. 

TABLE 3.4.4-1 

Minor Route Variations Incorporated into the Pacific Connector Pipeline Proposed Route

Minor Route Variation County Rationale for Variation 

Big Creek Coos Geological hazards 

Muenchrath/Wilson Coos The original preferred route was aligned to avoid potential geological hazards based on a 

desktop review of existing information (aerial photography/lidar, etc.) but also resulted in the 

route being located in close proximity to the east of the Muenchrath residence. During an onsite meeting with a Pacific Connector routing specialist and Mr. Muenchrath, an agreement was 

reached to route the pipeline alignment further east, away from the Muenchrath and Wilson 

residences. Subsequently, the pipeline was rerouted between MPs 12.11 and 12.79 to address 

Mr. Muenchrath’s concerns. Upon review of the new agreed upon proposed reroute, LiDAR 

imagery interpretation by GeoEngineers identified a potential geological hazard along this route. 

As a result of this finding, GeoEngineers proposed a third tabletop reroute based on a field 

survey conducted by a GeoEngineers geologist and this reroute was mapped by a Pacific 

Connector routing specialists to the north and west of the Muenchrath/Wilson residences. Once 

the route was mapped, GeoEngineers subsequently evaluated the information they had 

gathered from the field and determined the new proposed reroute to the east could be built and 

maintained over the long-term if certain site specific construction, backfill, and restoration 

techniques were adhered to. Now that the potential geological hazard has been evaluated and 

proper mitigation of the feature identified, the current proposed route has defaulted to Mr. 

Muenchrath’s originally suggested route. 

Boone Creek Coos The alignment in this area was adjusted based on geological hazard evaluations. Further 

topographic and constructability evaluations of the rerouted alignment in the area between MPs 

15.31 and 16.03 required additional adjustments. Although the adjusted reroute is slightly 

longer than the original reroute, the adjusted reroute minimizes sidehill and steep slope 

construction requirements. 

BPA Adjustments Coos The alignment between MPs 20.86 and 22.28 was adjusted based on Pacific Connector’s 

meeting with BPA. BPA requested that the pipeline easement more closely abut the powerline 

corridor in these areas to minimize the strip of trees between the two easements. Abutting the 

easements would minimize the potential for tree wind throw hazards and subsequent 

maintenance requirements. 
3-115 3.0 – Alternatives 

TABLE 3.4.4-1 

Minor Route Variations Incorporated into the Pacific Connector Pipeline Proposed Route

Minor Route Variation County Rationale for Variation 

Lone Rock 

Timberlands 

Development 

Coos The alignment between MPs 29.05 and 29.49 was rerouted to minimize impacts to Lone Rock 

Timberland’s planned subdivision development for this parcel. The reroute would avoid impacts 

to a number of lots within the proposed subdivision. 

East Fork Coquille 

River 

Coos New proposed route segment between MPs 29.78 and 39.06, filed December 4, 2008. New 

route avoids MAMU habitat and MAMU Stands G46 and G47. 

MAMU Stand G50 Coos New proposed route segment between MPs 30.34 and 30.71, filed December 4, 2008. New 

route reduces impacts on MAMU Stand G50. 

MAMU Stand C3088 Coos New proposed route segment between MPs 31.70 and 32.33, filed December 4, 2008. New 

route reduces impacts on MAMU Stand C3088. 

Hardwood Study Plot Coos The alignment between MPs 31.44 to 32.22 was rerouted to avoid a long-term Hardwood Study 

Plot on BLM Lands that is being studied by Oregon State University. The reroute was 

coordinated with the BLM to ensure the study area was avoided. A portion of this alignment 

change was again changed as a result of the MAMU Stand C3088 Variation described above. 

MAMU Stand B07 Coos New proposed route segment between MPs 36.10 and 36.29, filed December 4, 2008. New 

route reduces impacts on MAMU Stand B07. 

MAMU Stand C3070 Coos New proposed route segment between MPs 45.24 and 45.70, filed December 4, 2008. New 

route reduces impacts on MAMU Stand C3070. 

Rust Parcel 

Subdivision 

Douglas The alignment between MPs 49.53 and 49.75 was adjusted to minimize impacts to the 

landowner’s proposed parcel subdivision. The alignment and block valve on this parcel were 

realigned to the edge of the parcel to minimize potential development impacts. 

Kincaide’s lupine Douglas New proposed route segment between MPs 57.84 and 57.92, filed December 4, 2008, in 

accordance with draft EIS recommendation 39. New route avoids population of Kincaide’s 

lupine. 

Interstate 5 Crossing Douglas The alignment between MPs 69.85 and 70.03 was slightly realigned for constructability 

requirements for the bored crossing of Interstate 5. The minor alignment adjustment was made 

to minimize excavation and grading requirements based on topographic conditions 

St. Johns Creek 

Reroute MPs 88.1 to 

90 

Douglas Constructability issues along the original preferred route at the St. Johns Creek crossing 

required the reroute. St. Johns Creek along the Original May 2006 Route is extremely narrow, 

steep and incised. An existing road which parallels the stream created additional 

constructability issues which required the minor reroute. Pacific Connector’s proposed reroute 

alignment crosses the creek in an area where the creek is not steeply incised and there is a 

minor floodplain on either side of the stream to facilitate the crossing. 

NSO Nest Patch 094-8 New proposed route between MPs 95.05 and 95.60, filed December 4, 2008, in accordance 

with draft EIS recommendation 36. New route reduces impacts on old growth forest and NSO 

Nest Patch 094-8. 

MPs 108.5 to 109 Jackson Geological hazards. 

MPs 110.84 to 111.14 Jackson The alignment in this area was trued-up with actual civil survey data, which ensured that the 

alignment approached the slope perpendicularly or head-on to the contours to minimize right-ofway grading requirements. 

Gagnon Jackson The alignment in this area (MPs 118.73 to 123.32) was adjusted based on landowner 

concerns/recommendations to move the alignment to the edge of the landowner’s 

parcel/pasture. 

Laudani Jackson The alignment between MPs 123.08 to 123.32 was adjusted based on landowner concerns. In 

this area the alignment was moved up-slope and away from landowners’ residences as much 

as possible. Further, the TEWAs in this area were reduced in size and extent to minimize 

overall disturbance on the slope which was a concern of the landowner. 

Mucky Flats Reroute Jackson Landowner concerns/constructability issues. Reroute to address landowner concerns with 

shallow groundwater, irrigation pastures. Landowner also proposed to extend private runway 

airstrip in Mucky Flats which would have crossed the proposed pipeline route. 

Mitchell Ranch 

Deviations MPs 127.4 

to 127.8 

Jackson Original route traversed landowner’s new home site development with installed electric, septic, 

well and well system. Minor reroute to avoid home site development. 

 Jackson New proposed route segment between MPs 127.35 and 128.58, filed December 4, 2008, in 

accordance with draft EIS recommendation 36 to avoid impacts on northern spotted ow.

Obenchain Mountain 

MPs 130 to 132.05 

Jackson Reroute to address landowner concern and impacts to spring and seep water sources and 

developed pasture. 
3-116 3.0 – Alternatives 

TABLE 3.4.4-1 

Minor Route Variations Incorporated into the Pacific Connector Pipeline Proposed Route

Minor Route Variation County Rationale for Variation 

C2 Ranch MPs 143.71 

to 147.54 

Jackson Between MPs 143.71 and 147.54, the alignment crosses the C2 Ranch, on which there are 

numerous irregularly-shaped conservation easements held by the Southern Oregon Land 

Conservancy (Conservancy). Pacific Connector met with the Conservancy and received GIS 

data showing the locations of the conservation easements. Pacific Connector reviewed this 

information and, using aerial surveys as a basis, adjusted the alignment to minimize the impacts 

to the conservation easements. The alignment on the C2 Ranch was finalized based on 

landowner recommendations. The alignment was realigned to minimize impacts to irrigated 

pastures and irrigation facilities (canals/ditches). Block Valve #11 was also relocated to MP 

145.19 adjacent to Gardner/Salt Creek Road and out of the view of Highway 140. The 

proposed route was modified between MPs 144.2 and 145.3, in a filing on December 4, 2008, in 

accordance with draft EIS recommendation 27. 

BLM Heppsie Mountain Jackson Minor alignment adjustment (MPs 150.37 to 150.70) to avoid BLM Heppsie Mountain Rock 

Quarry. 

Keno MPs 183.9 to 

195.6 

Klamath Reroute to avoid cultural resources. 

MPs 194.14 to 194.43 Klamath Pacific Connector has discovered a cultural resource site that could be eligible for listing under 

the NRHP at this location and would be conducting a Phase II investigation of the site during 

the summer of 2007. Depending on the discoveries and consultations with the Klamath Indian 

Tribe and the SHPO, Pacific Connector would employ appropriate mitigation and/or recovery 

measures of any eligible resources based on recommendations from the above listed entities. 

The previous jog in the alignment to avoid/minimize potential impacts was removed because it 

created a pipeline safety hazard within the agricultural pasture/hayfield where the short jog in 

the pipeline alignment may not be clearly visible. Although the alignment would be marked with 

aboveground pipeline markers, the markers may not be clearly evident within the 

pasture/hayfield where the markers are typically placed along fence lines to minimize 

hindrances. These alignment conditions are generally avoided wherever feasible to minimize 

the potential for third party damages (dig-ins) to the pipeline. 

Applegate milk-vetch Klamath New proposed route segment between MPs 195.45 and 196.52, filed December 4, 2008, in 

accordance with draft EIS recommendation 37. New route avoids population of Applegate milkvetch. 

MPs 202.30 to 202.62 Klamath The alignment in this area was shifted to minimize impacts to the hayfields by realigning the 

pipeline adjacent to the powerline corridor. 

MPs 210.31 to 211.57 Klamath The alignment was realigned to closely parallel State Hwy 39 to minimize land encumbrances 

and to minimize pipeline traversing the middle of the fields in this area. 

MPs 215.30 to 217.49 Klamath 

The alignment was shifted up-slope so that the alignment would parallel the powerline corridor 

more closely in this area. Additionally, the alignment in this area was adjusted to avoid 

impacting the center pivot irrigated hayfield. Wetland AW048 which is affected by this 

realignment adjustment is a low quality agricultural emergent pasture that is supported by stock 

pond seepage. Impacts to this wetland would be short-term and minor and readily mitigated 

during restoration. 

Lions Center Pivot 

MPs 225.46 to 228.21 Klamath 

The alignment in this area was rerouted to avoid impacts to the center pivot irrigated hayfield 

which the pipeline bisected. Additionally, the reroute avoids an area more than 1.5 miles long 

that is expected to require blasting due to shallow and hard bedrock which parallels the GTN 

Transmission Pipeline. The reroute was aligned along property line boundaries where feasible 

to minimize potential encumbrances. Pacific Connector has received survey permission along 

the entire reroute. 

3.4.5 Alternative Compressor Station Locations 

Pacific Connector’s design criteria for siting its proposed compressor station were 1) a location 

between MPs 96 and 138 based on pipeline hydraulics and expected fuel usage, 2) a relatively 

flat area of approximately 10 acres, 3) proximity to a paved or all-weather access road, 4) 

proximity to electrical power, and 5) proximity to telephone connectivity. Environmental criteria 

included avoidance of wetlands or sensitive habitats, and distance from potential noise sensitive 

areas. Pacific Connector identified one alternative location for the compressor station, at MP 

122 along the pipeline route, in Jackson County, Oregon, that met its siting criteria. The 

alternative site is on a bluff near the community of Trail, just west of State Route 62 and the 

Rogue River (figure 3.4-15 and table 3.4.5-1). 
3-117 3.0 – Alternatives 

The primary environmental advantage of the alternative compressor station site over the 

proposed Butte Falls Compressor Station location (at MP 132.1) is that the alternative site would 

not be within big game winter range, whereas the proposed compressor station would be within 

big game winter range. The alternative site would also require a shorter access road 

(approximately 600 feet) compared to the proposed compressor station (approximately 1,476 

feet). However, the access road for the alternative site would be new road, whereas access to the 

proposed compressor station would be along an existing road that would require improvement. 

A disadvantage of the alternative compressor station site is greater potential noise impact during 

operation, as there are 8 to 10 residences within 1,000 feet, a post office, church and store within 

1,500 feet, and the Rogue River within 1,500 feet. In comparison, the proposed Butte Falls 

Compressor Station would be more than 2,000 feet away from the two closest occupied 

residences, and would not be near any community buildings or recreational areas. Pacific 

Connector also identified engineering issues with the alternative site because the pipeline at that 

location would be installed using HDD as part of the Rogue River crossing, and would over 100 

feet below surface at the site. In order to construct the compressor station at the alternative site 

Pacific Connector would have to install about 500 feet of extra pipeline to tie into the mainline 

pipeline near the exit point of the HDD about 500 feet west of the alternative site. 

We do not believe the alternative compressor station site offers any significant environmental 

advantages over the proposed site, and therefore do not recommend use of the alternative site for 

the Butte Falls Compressor Station. We also did not identify any environmental issues with the 

proposed compressor station site that would justify evaluation of further alternative sites for the 

compressor station. 
3-118 3.0 – Alternatives 

Figure 3.4-15. Alternative Compressor Station Site 

Figure 3.4-15. 18
3-119 3.0 – Alternatives 

TABLE 3.4.5-1 

Comparison of the Proposed Butte Falls Compressor Station Site with the Alternative Compressor Station Site near 

Trail, Oregon

Impact/Issue Alternative Compressor Station Site – MP 122 

Proposed Butte Falls Compressor 

Station Site – MP 132 

Meets Site Selection Criteria a/ Yes Yes 

Size Not designed, expected to be similar to 

proposed compressor station site 

7.39 

Engineering Issues Additional engineering and piping required 

because proposed pipeline centerline at this 

location would be installed by HDD for the 

Rogue River crossing. Because of the HDD, the 

pipe would be at a significant depth below 

ground (> 100 foot depth - see Drawing 3430.2-

0010 Resource Report 2, Appendix 2H). The 

near surface location of the HDD pipe is 

approximately 500 feet west of the site. 

None 

Access Road Construction of an approximately 600-foot long 

access road would be required. 

The improvement of an existing road 

approximately 1,476 feet long would 

be required. 

Residences 8 to 10 residences within approximately 1,000 

feet of site from the center of the site. 

2 residences are more than 2,000 

feet. 

Other Community Features A church and a store are approximately 1,500 

feet from the center of the site, and the post 

office is 1,300 feet from the site. 

None 

Recreational Features The Rogue River is approximately 1,500 feet 

from the center of the site. 

None 

Potential Noise Issues Potential noise issues based on number of 

residences proximate to the site. 

None 

Vegetation Affected Shrubs and mixed conifers The site currently supports a grass 

meadow surrounded by oak and 

conifer trees. 

Wetlands None None – (Wetland AW243 is 

immediately adjacent to site). 

Waterbodies None None 

Big Game Winter Range None Ditch EDX075 passes through the 

site. 

a/ Site Selection Criteria: (a) location between MPs 96 and 138 based on pipeline hydraulics and expected fuel usage; (b) need 

for a relatively flat area approximately 10 acres (660’ X 660’) in size; (c) proximity to paved or all-weather access highway or 

road; (d) Proximity to electrical power; and (e) proximity to telephone connectivity.