HomeMy WebLinkAboutKuskokwim River natural gas Study 2012REPORT:
Pre -Feasibility Study for Natural Gas in the Yukon
Kuskokwim River Region
prepared for
Alaska State Senator Lyman Hoffman
Prepared by:
Ian Burkheimer
ian@transenergysolutions.com
253-237-2106
9622 NE Vancouver Way
Portland, OR 97211
Version number 1.0 (12/15/2012)
e�)Transweruvy
Acronyms:
AEA Alaska Energy Authority
AIDEA Alaska Industrial Development and Export Authority
BTU British Thermal Unit (a common unit of measurement of energy content in the
natural gas industry.)
C Carbon
CNG
Compressed Natural Gas (Typically stored at 3600 pounds per square inch)
DGE
Diesel Gallon Equivalent (amount of natural gas equaling the energy content
of a gallon of diesel) Primarily used for transportation
GGE
Gasoline Gallon Equivalent (amount of natural gas equaling the energy
content of a gallon of gasoline)
GJ
Gigajoule- 1 Billon Joules, approximately equal to 1 MMBtu
H
Hydrogen
HVDC
High Voltage Direct Current
J
Joule (The standard unit of energy in the metric system)
LNG
Liquid Natural Gas
MMBtu
1 Million BTU's
MMscf 1 Million scf, a common unit to measure capacity of pipelines and other large
users of natural gas = 1,000 MMBtu
MW Megawatt (1 million watts), a common unit for large power generation
projects
RNG Renewable Natural Gas
scf Standard Cubic Foot, a common base unit for measuring a volume of natural
gas
YKHC Yukon-Kuskokwim Health Corporation
2
Conversion Table
Natural Gas
LNG GA5 Mf J EnerQv uel.E uivalen
onversion.
Gallon
Mscf
MMsef
Pounds
MMBTU
Diesel Gallon
Units
Equivalent
(DGE)
LNG -'�
I aTion
1
0,083
83
3.734
0.083
0.598
GAS
'I msef
12.2
1
1000
45.06
1
7.22
1 MlY s cf
12200
1000
1
45060
1000
7220
Mass LNG �
i pound
0.27
0.022
22
1
0.022
0.16
ENERGY
1 MMBtu
12.07
1
1000
45.06
1
7.22
FUEL
Equivalents
f WE
1.67
0.1385
138.5
6.24
0.1385
1
1 GPI
1.5
0.1245
124.5
5.61
0.1245
0.0
3
1.1 Overview
In the summer of 2012, the Donlin Creek Mine filed its 404 permit with the US Army Corps of
Engineers. This mine is being developed by Donlin Gold, a joint venture of NovaGold
Resources and Barrick Gold. The mine site is situated about 12 air miles north of the village of
Crooked Creek, in western Alaska. Based on Donlin Gold's own estimates, the reserves at the
site are nearly 33.9 million ounces (NovaGold), and is one of the largest new gold developments
in the world. Due to the remote nature of the project, a tremendous amount of infrastructure will
need to be developed to support the operations of the mine.
Based on the project description in the permit information, Donlin Gold's published information
and direct communications with Donlin Gold's staff, the mine will require a large amount of
natural gas to power its operations. In order to supply this gas, the mine proponents have
proposed the development of a 313-mile long 12.75" diameter steel pipeline from Beluga to the
mine site. This pipeline is expected to have a capacity of between 40 to 50 million standard
cubic feet (MMscf) per day.' The majority of this capacity is intended to supply the electrical
power for the mine's operations, estimated to have an average annual running load of 153
Megawatts (MW) and a peak load of 184 MW. To put this into perspective, the City of
Fairbanks' peak load in 2011 was 211 MW (Golden Valley Electrical Association).
Figure I - Map of area of study (Blue- possible pipeline route to Aniak and Bethel, Red approximate route of
Donlin Creek's proposed pipeline) (Google Maps)
' See Appendix A - Price Gregory International Report
4
Currently, the timeline for the development of the pipeline and mine is estimated to be sometime
around 2018-2021, based on investment, permitting and a number of other factors. Once it is
up and running the mine will use an average of 30 MMscf per day to meet these power needs,
providing the possibility of additional capacity for energy use by outside parties and/or other
mine operations. This study looks at options for this excess capacity, specifically uses for
natural gas for communities in the region.
The following are the main options considered for delivery of the natural gas to regional
communities:
• Development of a pipeline from the mine site down river to Bethel
• Development of a "virtual" pipeline, liquefying the gas near or at the mine site, then
moving it to river communities through a combination of barging and trucking
• Development of an electrical transmission line to move power to Bethel and intermediate
communities
Some combinations of these options are also considered. The purpose of this study is to
identify the positives and negatives of various options, bring forward order of magnitude costing
information, and supply a framework for a follow-up full feasibility study for one or all of the
options to more fully develop a plan of action. This study does not go into detail regarding
routing, permitting, engineering or other aspects of the options, but does provide some context
for further development.
Additionally, during the course of this pre -feasibility study, one area of potential competition for
the capacity in the pipeline was identified, and will be discussed in more detail in the inferred
assumptions area of the study.
2 Study Assumptions
2.1 General Assumptions
In order to undertake this study, a number of general assumptions need to be made to direct the
research. For all options considered, the following assumptions have been made:
• At some point in the future, a mine, with specifications put forth in Donlin Gold's 404
permit application will be built at Donlin Creek
• In order to serve the energy needs of the mine, a natural gas pipeline will be developed
that has capacity of between 40,000,000 to 50,000,000 Standard Cubic Feet (40-50
MMscf) per day
• At the mine site, power generation capacity of 185MW will be installed
--) This power generation will consume 30 MMscf per day of natural gas for average
power production
• Sixty-nine 400-ton mining trucks and equipment will be powered by diesel fuel, which will
be barged to the mine site (Kurt Parken, Donlin Gold, Personal Communications,
October 17, 2012).
• A haul road from the mine to the Kuskokwim River will be developed to off-load product
and haul -in supplies south-west of Crooked Creek where a port facility will also be
developed.
It should be noted, that while these energy parameters are included in both the permit
application, as well as public relations materials from Donlin Gold, it is highly likely that the
pipeline and potentially the power plant will not be owned or operated by Donlin Gold. The
pipeline in particular will likely be a common carrier, with Donlin Creek as the anchor customer.
There is also a possibility that the haul road may be a publically accessible toll road, similar to
the model that has been used at Red Dog.
At this point, it is not possible to identify the actual developers of the road, pipeline, or power
plant. It is clear from both private conversations with Donlin Gold, and others in the mining
industry that the mine operators would likely prefer outside parties to design, build, own and
finance some or all of these components of the mines operations. Companies such as Alyeska,
Conam, TransCanada, Enbridge or any other pipeline developer may choose to pursue the
project individually or with partners.
It must be noted that it is outside the scope of this report, and at this point nearly impossible to
determine the cost of natural gas delivered to the Donlin Gold Mine. It is, however, helpful to
include notes about possible supplies of gas, and its possible effect on pricing.
The current Donlin Gold proposal plans to connect the gas pipeline to the Beluga fields the
existing network of pipelines in that region. It is not clear that the production in this area will
support the demand of the mine. If not, then gas will need to be brought to the Beluga end of
the line through other means. Possibilities include a connection to a pipeline that is developed
to transport natural gas from Alaska's North Slope, Cook Inlet or some other producing region in
the state. Another option could include delivery of LNG from another location in the state,
Canada or Washington State to a marine terminal on Cook Inlet.
As the price for the gas will be based on the cost of the commodity plus the cost of the
transportation to Beluga plus the tariff for the Beluga-Donlin Creek Pipeline, a number of
unknown variables already exist. From that point, based on the option(s) pursued to take the
gas down river, other variable costs including connection fees to the pipeline, capital
expenditures and operating expenditures will also affect the delivered cost. Some of these
items are discussed in this paper.
6
E
E
0
N
2010 2012 2014 2016 2018 2020 2022 2024 2026 202E 2030 2032 2034 2036 2038 2040
Figure 2 - Projected Natural Gas Prices on an MMBtu basis,Source: US Energy Information Administration
An additional challenge in determining the costs of the natural gas is that the gas will likely not
be delivered for another six to eight years, during which the price of natural gas may
significantly change. The current outlook for pricing for natural gas around 2020, according to
the US Energy Information Agency (Newell, 2011) is projected to be between $5 to $8 per
MMBtu, the same agency predicts a cost for crude around $18 to $22 per MMBtu (US Energy
Information Administration). One note of caution for this comparison is that the price for natural
gas is only for the
commodity, while diesel must
be refined from crude oil,
which increases its wholesale
price compared to crude.
With this taken into account,
there is a significant cost
differential that could be
captured to off -set
investments in infrastructure
necessary to use natural gas
in western Alaska.
O M tD M N Ln M -4 rr f` O M to Ql N Ln
O1 01 01 01 O O O rl rl rt N N N N M M
rl rl rl rl N N N N N N N N N N N N
Reference High Oil Price - tow Oil Price
I
To put the cost differential in
perspective, at 2012 prices,
Figure 3 - Source: US Energy Information Administration the cost of the commodity,
not including transportation,
distribution, marketing and
profit is approximately $2.07 for crude oil per diesel gallon equivalent (DGE), and $0.40 for
natural gas.
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2.2 Inferred Assumptions/issues
Currently, large, haul trucks in the 400-ton range, such as the ones Donlin Gold will likely use,
operate on diesel. Major original equipment manufacturers (OEMs) of this type of equipment
and after -market companies are rapidly investing in technology to utilize natural gas in this type
of equipment. This technology might include either 100% natural gas or partial natural gas
operations.
While Donlin Gold has not made indications that they plan to use natural gas for trucks, as the
equipment is not yet available, in our opinion, there is a high likelihood that this technology will
be considered. If that is the case, some of the basic assumptions are then impacted
significantly, including:
• There is a likelihood that Donlin Gold or an outside vendor would develop a natural gas
liquefaction plant to produce Liquefied Natural Gas (LNG) to supply fuel for the trucks
• Barge traffic on the river for mining supplies, primarily diesel fuel, would be reduced.
• Should the trucks be 90%-100% powered by natural gas, the current low -end estimated
capacity in the proposed pipeline would be nearly fully absorbed.2
Based on calculated estimates, with the trucks possibly using 9-12 MMscf per day of natural gas
for use in mine trucks, in addition to the 30MMscflday estimated to be needed for power
generation, the amount of available excess capacity for downstream energy consumption,
based on the current preliminary proposal for the gas pipeline, and the estimated potential
energy demand down river (see discussion below) may exceed the capacity of the line.
2.3 Assumed Regional Energy Demand
As the purpose of this study is to see what options are available for the use of natural gas in the
Yukon-Kuskokwim River Region, it is necessary to understand the energy demand profile of the
region. Energy prices in this region are among the highest in both the state and the nation.
Most of the electricity is supplied using diesel generation. Natural gas is a much more
affordable alternative if it is economically viable to transport the gas. For the sake of this study,
the communities, most of which are along the Kuskokwim river, that were included are listed
below:
2 Without knowing the exact equipment that will be used, the following calculations are based on current
diesel operations of similar 400-ton mining trucks, and an estimate about the use of the equipment based
on maximizing use of capital asset and including downtime for maintenance and breakdown:
(69 trucks * 1440 minutes/day operations* 365 days/year * 80% up time/truck * 1 gallon diesel
consumed/minute * .000141 MMscf Natural Gas/Diesel Gallon Equivalent)1365 days = 11.2 MMscf/Day
8
■
Akiachak
■
Kongiganak*
s
Quinhagak*
■
Akiak
s
Kewthluk
■
Red Devil
■
Aniak
■
Kwigillingok*
■
Sleetmute
■
Bethel
■
Lower Kalskag
■
Stony River
■
Chuathbaluk
s
Napakiak
■
Tuluksak
■
Crooked Creek
■
Napaskiak
■
Tuntutuliak
■
Eek
■
Oscarville
■
Upper Kalskag
Table 1 — List of communities included in fuel statistics for this study
(*Note that the communities with an asterisk are included in the following demand figures, but
these communities are on tidewater [may have access to other resources])
When defining energy demand, it is important to note that for the purposes of this study, energy
demand includes both heat and electricity, but not transportation. While transportation is an
important component in energy consumption, the likely adoption scenarios for natural gas, as
explained later in this report, make it likely that any conversion to natural gas for transportation
purposes will occur fairly late in the development process. The energy demand also only takes
into consideration diesel fuel. There are other types of energy resources like wind -diesel,
biomass and geothermal that may be used in these communities.
Table 2 below outlines the amount of diesel gallons consumed for electrical generation and
heating fuel. Bethel is also separated in the last row because it is the biggest consumer of
energy. See Appendix B for complete community data.
Electrical
Heating Fuel
Total
Generation (gallons
(gallons in 2008)
in 2007)
All Communities
4,363,521
3,743,617
8,107,138
Communities without
4,072,039
3,360,189
7,432,228
Tidewater included
Bethel
3,075,281
1,815,943
4,891,224
Table 2 - Diesel fuel consumption in heating and electricity in the YK River Region.
Source: Alaska Energy Authority
One can calculate the amount of natural gas this represents by multiplying the number of
gallons of fuel by 0.141 to get the MMBtu value. This number is then multiplied by .001 to give
us the total MMscf of gas this represents. The amount of potential natural gas demand is 1,143
MMscf a year, which averages out to 3.13 MMscf/day.
9
2.4 Natural Gas Storage and Transportation Overview
One of the major issues for developing an accurate demand profile for is the manner in which
the gas will be adopted and replace diesel fuels. While natural gas is a very familiar fuel for
cooking, heating and power generation in many urban, suburban and even rural communities,
introducing it to a community for the first time requires a large amount of public and private
investment in infrastructure, time and education.
2.4.1 Natural Gas Properties Summary
In order to understand the adoption scenarios that a
community will face, it is important to be familiar with natural
gas. Traditionally, it has been produced through drilling
processes similar to oil, and is often a bi-product of oil
development. In recent years, drilling and extraction
techniques for natural gas specifically have greatly improved,
leading to a huge increase in supply and large decrease in
price in most of North America. This has been lead primarily
through the improvement of hydraulic fracturing (`tracking")
technology, as well as horizontal drilling. Renewable natural
gas (RNG) can also be produced through the breakdown of
organic matter.
Figure 4 - Representation of a
Methane molecule (CH4)
Natural gas is primarily (90-98%) made up of methane. Methane (CH4) is the lightest
hydrocarbon, made up of one carbon atom, and four hydrogen atoms. Natural gas should not
be confused with propane (C3Ha), a related fuel, but with very different properties. Diesels and
gasoline are blends of much larger molecules, with diesel around C121-123. With a ratio of one
carbon to four hydrogen, rather than a ratio closer to one to two for other hydrocarbons, natural
gas contains much more energy per carbon atom than its bigger cousins. As such, it produces
significantly less carbon dioxide than other fossil fuels per molecule. On the other hand,
methane released directly into the atmosphere, without being burned, is a significant mid-term
greenhouse gas, having a warming potency over 20 times that of CO2.
While on a molecular basis, natural gas contains a large amount of energy, it is challenging to
use, because it is a colorless and odorless gas that is lighter than air at ambient temperatures.
Propane exists in a relatively low pressure vessel as both a liquid and a gas at room
temperatures, which allows a lot of molecules to be stored in a small space without high cost
containment vessels. In contrast, natural gas will not turn into a liquid in most conditions until it
is cooled to -260 degrees Fahrenheit. This makes its storage, transportation and distribution
more challenging than traditional liquid fuels, or even propane.
Both within communities and between production sites and end users, the most common way to
transport natural gas is via pipelines. The gas is slightly pressurized and close to ambient
10
temperatures. Two other ways to store and transport natural gas is to either compress it or
liquefy it. Both have their advantages and disadvantages.
2.4.2 Introduction to Compressed Natural Gas (CNG)
Compressed natural gas (CNG) is natural gas that is stored in a containment vessel at
high pressure. It is commonly used in vehicles around the world, and can also be used
for storage of gas for other industrial or small scale utility use.
The compression process is similar to other gases, basically using a pump to push
more gas into a high pressure container. These containers are use made out of
combinations of steel and carbon composites, the maximum rating available for most
today is up to approximately 3600 pounds per square inch (PSI) capacity. Depending
on the amount that needs to be compressed, and how often it is depleted, the gas may
be stored in onsite storage tanks, or if a vehicle or other piece of equipment has a
number of hours available for refueling, the gas may be compressed in a time -fill
process refilling the cylinder at a slower pace, requiring less compression infrastructure.
When stored as CNG, natural gas has an energy density about 114 that of diesel fuel,
meaning that for the same amount of energy, CNG requires 4 times as much space as
diesel. In comparison, Liquefied Natural Gas (LNG), described below, only requires
about 1.7 times the space of diesel to store the same amount of energy, making LNG
more attractive for storage of large amounts of energy in many cases.
CNG is a popular method of storage for the transportation marketplace. It also can be
used for local storage near end users. The cost for CNG infrastructure varies based on
the pressure of the natural gas as it comes into the plant, the speed at which the gas is
compressed, and the volume of gas that needs to be produced.
2.4.3 Introduction to Liquefied Natural Gas (LNG)
Liquefied Natural Gas (LNG) is a method that is commonly used to store and transport large
quantities of natural gas. Natural gas will change from a gaseous state to a liquid around -260
degrees Fahrenheit. This gas is then stored in specially designed containment vessels that are
similar to giant thermos bottles. Depending on the size and type of containment vessel, LNG
can be stored for up to 100 days. After that point, the fuel will need to be re -cooled, used or
gassed off. For safety and environmental reasons, this gas may be flared.
Liquefied Natural Gas has a much higher energy density than CNG, about 70% that of diesel
fuel. This means that LNG requires much less space for storage than CNG, but still takes more
than diesel.
11
The process to produce LNG uses advanced refrigeration techniques to progressively lower the
temperature of the gas to a point where it will condense into a liquid. This process traditionally
has been done on a large scale for export, or for utilities. In the United States, the most
common use of LNG today is as storage for utilities in peak shavers. These facilities slowly
produce LNG, and store it in large tanks for times when there is large demand for natural gas for
heat or power production, when the gas is then injected back into the transportation and/or
distribution pipeline for use.
Traditionally, a large amount of energy and capital investment have been required for LNG
plants, but recently, due to the large increase in natural gas production in the United States, and
demand around the world, more smaller scale LNG production equipment is coming into the
marketplace.
Recently, LNG consumption in transportation, oil & gas production and some mining
applications has been increasing. This has also spurred the development of transportation
vessels and other equipment to support the use of LNG.
2.4.4 "Virtual" Pipelines and infrastructure
Rather than a traditional pipeline, another method for moving natural gas is also available, often
times called a "virtual' pipeline. In cases where costs, dispersed demand, mobile demand, land
availability or other infrastructure impediments exist, a "virtual' pipeline provides another method
to transport and store natural gas. It is similar to the current supply chain used for diesel fuel
and fuel oil on the Kuskokwim River, with some additional components.
The value chain for a "virtual' pipeline begins in most cases at the end of a pipeline or in some
cases a natural gas well head. Natural gas is either compressed or liquefied for storage. It is
then transferred to a transportation vessel (truck, ship, barge or railroad car). This fuel is then
transported as LNG or CNG to an end user or a storage depot. in either case, the gas is usually
then off-loaded from the transportation vessel to a
Figure 5 - Regasification Vaporizer (Linde)
storage container. These can range from small
containers of several thousand gallons of LNG to
several hundred thousand.
From the storage container, the compressed or
liquefied fuel might be further transported by
wheeled vehicle to smaller facilities, or it may be
injected into a local distribution pipeline system for
end use. If the gas is compressed, then it simply
exits the containment vessel through a regulator that
lowers the pressure to one that is appropriate for the
distribution system. If the gas is liquefied, it must be
regasified by moving it through a heat exchanger, at
12
which point, it can be moved through the local pipeline system, or directly to its end use.
Variations on virtual pipelines are often times used in the oil & gas and mining industries. They
have also been used to develop national natural gas grids to supply remote communities. The
country of Turkey has supplied gas all over the country through "virtual" pipelines, as their
permanent infrastructure has been built.
The advantages of a virtual pipeline are its flexibility and mobility. For the Oil & Gas industry,
equipment is always moving to a new location. In the mining industry, virtual pipelines mostly
take the place of diesel delivered to the mine site. An additional benefit of "virtual" pipelines is
the opportunity to extend the availability of LNG or CNG from a production site to customers in
neighboring markets.
For a community like Bethel, Aniak or others on the Kuskokwim River, the benefit is the fact that
it would be delivered in a form that can be stored for a period of time before its final use. This
offers the ability to use existing infrastructure to compress or liquefy the gas, an cost intensive
venture, and maintain it in that form until time to distribute the fuel.
LNG in particular is very, very costly to transport through pipelines, so a virtual pipeline can be
very beneficial for moving the super cooled fuel from one point to another, even if they are
relatively close together. An example might be a ship that needs LNG for fuel, and a plant that
is located inland. The LNG would be loaded on a truck or rail car to get as close the ship as
possible to transfer the fuel.
Some of the drawbacks of "virtual" pipelines can include a high cost of transportation over long
distances or for very large volumes of gas. "Virtual" natural gas supply chains both benefit and
are at risk due to their mobility. As they depend on other modes of infrastructure besides
pipelines, interruptions in roads, waterways or railways can impede their efficiency of
operations. In rural Alaska, this is a leading drawback of any sort of "virtual' pipeline. Since
there is not usually a back -haul commodity that a LNG vessel or truck may haul, the cost of
transportation needs to cover both the delivery and return to base costs. This can rapidly
increase the costs for fuel transportation. In the case of the Donlin Creek mine project, there
may be an opportunity to transport diesel up the river, and LNG back down, mitigating some of
this cost.
3.1 Option 1 - Development of a Spur Pipeline to Bethel
3.1.1 Overview of the option
Option 1 involves building a spur pipeline from the main pipeline and running it to hubs in Aniak
and Bethel. Based on a cost -estimate prepared by Price Gregory International (see Appendix B
for complete report), we believe that the pipeline would be a 4.5 inch diameter pipeline with a
capacity of 3-4 MMscflday. It would run roughly 60 miles to Aniak and then another 111 miles
to Bethel for a total length of about 171 miles. A compressor station would need to be built near
13
the mine site to provide line pressure for gas transport. The estimated cost of the pipeline is
$124,560,000 based on $180,000 per diameter inch -mile. The compressor station cost is
estimated at $3,600,000 based on $15,000 per operating horsepower. This estimate does not
include the cost of the acquisition of rights -of -way, permitting and other land costs. The total
cost of this estimate is $128,160,000.
This number does not include any capital cost that would be required for any infrastructure
conversion or development to support natural gas electrical generation or heating in the
communities. These costs may be similar to other options as well.
3.2.1 Implications and adoption scenario
While costing and specifics of the local transition to the use of natural gas is beyond the scope
of this study, we will share some general scenarios for Bethel, as templates for consideration of
the many factors that need to be evaluated in the use of natural gas in a community. As
mentioned previously, this study does not include fuel demand for transportation, as it is a later
step in the adoption process, but we will include it in this conceptual walk through. For the
purposes of this scenario, we will assume that a supply of natural gas is available.
This option would deliver pipeline gas to Bethel and Aniak directly. Additionally, a pipeline
would introduce the opportunity for additional spurs to other communities along the pipelines
pathway, although spurs can increase costs and operational issues.
With pipeline access to natural gas, the opportunity to lower electric costs in both Aniak and
Bethel would be a possibility; however, significant hurdles would still exist. The best place to
realize immediate savings is in power generation. As both Bethel and Aniak have private
utilities, they may not be motivated to make the capital expenditures to upgrade their equipment,
and to pass on any savings if they do. As the power companies are the biggest single user of
fuel in both communities, the most sensible adoption scenario is to build the pipe infrastructure
to the power generation facility, or nearby.
One of the issues that will be important for all options is a recognition of the isolation and
vulnerability of any fuel supply chain in Western Alaska. In order to manage risk, and ensure
continuous operations, the utility would likely change from a dedicated natural gas generator to
a dual -fuel version. Currently there are after -market conversions that may work on the existing
power plants, greatly reducing the cost of adoption for equipment that otherwise does not need
to be replaced. A dual -fuel operation will only use about 50%-70% natural gas, with the
remainder of the fuel being diesel. While natural gas is likely to be lower cost, this allows the
generators to still run on 100% diesel should a supply interruption occur.
14
' r I
b
� ........... OdIMFrs4i
Figure 6 - Possible route for pipeline from mine site to Bethel via Aniak
In the case of a pipeline coming to Bethel, the most obvious second step in the adoption
process is to begin the implementation of a gas distribution system in the community. That
would likely be through the development of an above ground local pipeline system, with a large
energy user such as the Yukon-Kuskokwim Health Corporation (YKHC) being the anchor tenant
for the first portion of the distribution system. This initial distribution line could be tapped by
intermediate customers, including private residences. This process would then be repeated for
other major energy users. The developer of the distribution system could be a regulated or
unregulated utility or a public agency.
One of the barriers to the use of natural gas for home heating is the need to retrofit or replace
heating equipment in individual homes and businesses. Due to the capital costs involved, this
would induce major users of heating oil to update their equipment to use natural gas.
15
In order to incentivize the adoption of natural gas for home heating in particular, it will be vital
that natural gas is delivered at a significant discount relative to fuel oil. Even with a discount, it
is likely that an integrated financing and subsidy program will need to be offered for end users to
upgrade their heating systems. This could be done through state grants or through a state
financed program where the utility or government agency delivering natural gas will lease the
upgraded equipment to the customer. The following is a brief description of the system.
3.2.2 Equipment Conversion Program Description
One method to aid the adoption of natural gas in a new community is to borrow a model that is
being used by natural gas fuel suppliers in the trucking industry right now. In this model, the
end user pays for any equipment upgrades necessary through their purchase of fuel. The
model requires a lower cost of the new fuel in comparison to its existing competitor (Fuel -Oil).
Once natural gas is available in the community, and a distribution system begins being built,
customers along the system can begin to use the fuel. As many households would not have the
capital readily available to upgrade their heating equipment, the utility or government agency
selling the gas would buy the heating system for the customer. The customer would then pay a
higher price for their delivered fuel for a predetermined period of time and/or volume of fuel, until
the utility is paid back for the equipment, at which point, the cost of delivered natural gas then
reverts to a lower rate for the customer. This works best in a regulated environment, and would
likely be less costly if lower interest rate publicly backed or utility capital could be used to make
these purchases.
3.3.1 Benefits of Pipeline Option
• This creates a reliable transportation system delivering natural gas directly to energy
hubs that can be used for electrical generation or heating.
• Gas is delivered in a useable state to the end user without the need to re -gasify it as
LNG would need to be.
• Once construction is complete, there is no vehicle or vessel traffic needed to transport
the fuel in communities directly serviced on a regular basis.
• The development of a pipeline would require the development of a road for the
installation of the pipe, which may be available for regional transportation.
• A pipeline is traditionally the most efficient method to transport natural gas over long
distances.
• There is a lowest risk for natural supply interruptions with a physical pipeline compared
to other "virtual' pipeline options
• Even if a pipeline is only built part of the way to Bethel, a compression or liquefaction
facility can be developed at the end and/or intermediate points on the pipeline, allowing
for hybrid physical/"virtual" pipeline.
16
• A pipeline may also lend itself to power production facilities on the pipeline, and local or
regional distribution systems to take the power into communities.
• A pipeline could be buried, creating a modest permanent footprint on the landscape, and
avoiding interruption of wildlife corridors.
3.3.2 Challenges of this option
• A pipeline will require the acquisition of a number of environmental approvals
• Development of the right of way will require acquiring land, land swaps and partnership
agreements with a large number of stakeholders, including the Bureau of Land
Management, the Wildlife Refuge, Calista and village corporations and other private
landholders.
• Communities east of the mine site, such as Red Devil, Sleetmute, Stoney River and
Lime Village, would not be served by this pipeline. This may also be true for
communities west of Bethel.
• As a piece of permanent, immobile infrastructure, a pipeline may not offer the most
flexible option for changing energy consumption in the region. (This can be mitigated by
considering integration with other virtual options, covered in succeeding sections.)
• The cost of a pipeline will need to be borne completely by downstream users of the gas,
rather than the possibility of sharing costs for some other options with the Donlin Project
itself.
4.1 Option 2 - Creation of a "Virtual" Natural Gas (LNG) Pipeline
4.1.1 Overview of the option
Option 2 involves creating a "virtual' natural gas pipeline from the mine to communities along
the river. This would be accomplished by transporting the gas on barges pulled by tugs or on
trucks along a road. Barges will be delivering supplies and fuel to the mine nearly daily while
the river is ice free. On the return trips, it would be possible to bring LNG modules to the
communities along the river.
While it is still speculative at this point, but discussed earlier in this paper, there is a likelihood,
that should the Donlin Creek Mine decide to use natural gas as the primary fuel for their large
scale mine haul trucks, a natural gas liquefaction plant would likely be developed. As with the
pipeline to the mine, this facility would probably be developed and by a third party.
The capital investment in a 30-40 million gallon per year plant would be in the range of $60-70
million dollars. (Kirt Montague, Plum Energy, personal communications, December 5, 2012)
This number would likely be higher due to the challenges of the construction environment and
logistics in Western Alaska. For the communities in the region, the development of a
17
liquefaction plant for the mine would introduce the opportunity to participate in contracts with the
LNG plant for liquefaction. The benefit of this situation is that the capital for the development of
the plant would be funded through long term fuel contracts with the mine, or some other
mechanism with the mine as the primary customer. The communities would be secondary
customers of the plant, and the capital expense for the developer of the LNG plant to provide
the additional capacity for community demand would be modest.
Once the LNG is produced, it would then be incumbent upon a business entity to transport the
LNG from the mine site to communities along the river. This would be primarily done by
trucking the LNG from the mine site to the mine port, possibly in ISO containers', allowing for
cross loading to barges. During ice free months, LNG would be shipped and distributed to
communities along the river, with a depot in Aniak and one larger depot in Bethel. There could
be opportunities to truck fuel on the river during the winter months using an ice road, but this is
not something that consistent fuel supply should be built around.
It should be mentioned that a virtual
pipeline could use Compressed
Natural Gas (CNG) as the primary
mode of storage. In some cases, a
CNG "virtual" supply chain can make
sense, but with the distances, and
shallow draft of the barges need to
transport the gas from the mine to
market, LNG has an advantage as a
more dense fuel. Additionally, it is
more likely that a liquefaction plant Figure 7 - ISO Fuel Oil Containers stacked at the Port of
would be developed at the mine site, Bethel
rather than a compression facility. LNG is much faster to fuel for large trucks compared to CNG
and more energy is added with each fueling of the trucks. If a CNG plant was to be built at the
mine, it would make more sense for further exploration of this option, but it is a less likely
scenario.
3 ISO intermodal Cryogenic Containers are a common way to move liquid fuels. Since they come in
standard 20' or 40' sizes, they are compatible with intermodal transportation equipment such as truck
beds, rail cars, and stacking equipment.
18
Figure 8 - 40ft
(Approximately 10,000
gallon) LNG ISO on truck
(Chart Industries)
4.2.1 Implications and adoption scenario
This option would fundamentally turn the fuel supply chain along the river around. While the
mine and communities along the river will still require diesel fuel, now LNG will be distributed on
the return trip for the barge. A company that currently works on the river, Northland Services or
Crowley for example, could become the transporter and distributer of fuel to communities.
One of the challenges with Liquid Natural Gas is that it must be kept cold. After a period of
time, even in a very well designed containment vessel, the liquid will warm, and begin
transforming back to a gas. At this point, pressure will rise, if the LNG is not used, it will gas off
through a release vent. Depending on the size and quality of the container, LNG can be stored
without further re -liquefaction for up to 100 days. This would not allow for a stable year round
supply, and require a different adoption strategy. 4
Upon LNG becoming available to a community, it would be necessary to install one or more
storage facilities for the gas near an end user. A top candidate would be the power plant, as the
largest user of fuel in most communities. Additionally, due to the potential intermittent supply of
fuel, the power plant would likely need to be retrofitted with a diesel natural gas dual -fuel
system, or purchase a new dual -fuel generator. Once the generator is converted, it will be able
to operate on around 50% natural gas, and possibly more. If natural gas is not available, the
generator can still operate on 100% diesel.
4 There is currently technology that is coming into the market that could re -liquefy the gas, potentially
allowing for much longer storage, but they are in their early stage of implementation. Should this option
be further considered, it will be necessary to more specifically examine this technology, as there is rapid
development happening right now by companies such as Encana, Dresser -Rand and Linde. As can be
expected, this would change the adoption scenario significantly, as year round supply could then be
considered. The adoption would likely be similar to the pipeline, with the exception that rather than a
pipeline supplying the gas, a fuel depot would store it, then inject it into a local distribution pipeline
system.
19
Should natural gas have a significantly lower cost than diesel fuel in this scenario, it can lead to
a lower cost of generation. As an example, if bulk diesel is delivered to the community at
$6lgallon5 and LNG after transportation and storage, were only $1 less per Diesel Gallon
Equivalent, this would offer an effective savings of $.50 per gallon for the fuel used to run the
power plant. As discussed earlier, unless the utility is regulated, the power producer may not
pass on any savings to the customer.
While LNG has its challenges from a reliability issue, as a liquid fuel, once it is in a community, it
can be stored, re -gasified and distributed through a pipeline system, or it can be handled like a
liquid fuel, and delivered by truck. LNG is conducive to heavy, constant users of fuel, but not to
small users, due to the heating and gas -off mentioned earlier. This would make the second
step in the adoption process large fuel and heating customers, such as the YKHC or the school
district. Once again, if natural gas were to be used for heating, some capital investment in
converting existing systems, or installing parallel systems would be necessary. As with the
power plant, due to intermittent fuel supply, this would need to effectively be a dual -fuel system.
Should the price of the fuel be low enough compared to the alternative fuel - oil, these larger
users would be able to make a transition based on long term savings for investment in
conversions.
As the larger users of LNG develop, there may be an opportunity to either develop a community
wide natural gas distribution network, with one or more LNG depots taking the place of the
pipeline from option 1. Another option would be to develop neighborhood LNG grids, with a
central 6,000 - 10,000 gallon (or larger based on needs) LNG tank supplying natural gas to
surrounding structures. Each user would then be metered for their use, and the fuel supply
company would refill the tank on an as needed basis. Currently these tanks are expensive, a
6,000 gallon tank is approximately $100,000. By the time that LNG would be available in the
Yukon-Kuskokwim River Region, there is a reasonable possibility that these prices will drop as
more competitors are entering the market.
Another issue to be noted is that while LNG would be transported on the river by barge, its risk
for negative local environmental impacts is lower than for diesel. Should LNG from the barge
spill, it will simply vaporize and dissipate, as it is lighter than air.
4.3.1 Benefits of the virtual pipeline option
• There is a potential the capital cost of the liquefaction plant to be primarily funded by the
mine, with the community consumers being able to "buy" lower cost additional capacity.
• This option is very mobile, and can relatively easily be realigned to meet other future
needs in the region, and especially along the river.
• A virtual "pipeline" requires less up front capital investment for the community to begin
use, primarily being focused on storage and equipment reconfiguration.
5 AEA power cost equalization average
0
• There may be an opportunity to more efficiently use the river for transportation, allowing
downriver hauling for barges that have taken product up river.
• This option can be integrated with currently existing fuel supply chains, and likely be
handled by similar equipment and personnel who currently distribute diesel and fuel oil.
• A virtual LNG pipeline can be relatively rapidly deployed once LNG becomes available.
• LNG can be used in other applications that currently bring their own fuel into the market,
including asphalt plants, ships and other construction equipment. While the economic
impact would be modest, some of these users of fuel might be inclined to purchase their
summer fuel locally, rather than bringing it in from the outside.
4.3.2 Challenges of virtual pipeline option
• Regasification capability would have to be integrated with storage to return the gas to a
usable form. Costs can vary, but it is not uncommon for this to cost over $100,000.
Additionally, there may be a need to for more advanced and expensive regasification
equipment to manage the extremely cold temperatures faced in western Alaska.
• If LNG is transported via barge, river depth may be an issue. A typical barge requires
four feet of water, and there are reports that the river can be as low as three feet in some
areas. However, Donlin Gold is planning on using barge service frequently, so they may
have a solution to this.
• Additional barge traffic may have negative erosion effects along the river and negatively
interact with fisheries.
• If trucks are used to transport the LNG, a road would need to be built to the communities
requiring land access and environmental permitting.
• The river may be able to be used as an ice road during winter months
o The development of a road would of course likely have positive effects as well
• Any increase in barge traffic or road traffic would require environmental permitting for
things like air and noise pollution
5.1 Option 3 - Development of Transmission lines from Mine Site
5.1.1 Overview of the option
This option looks at the possibility of developing a electrical transmission line from the mine site
to Bethel, or other communities down river. This transmission line would likely follow the river
more closely than the pipeline examined in this study. Due to the relatively modest load of
Bethel, and the current state of technology, and the likely desire to have intermediate power
distribution between the mine site and Bethel, the best option for a transmission line would be a
three phase high voltage transmission line. At this point, high voltage direct current (HVDC)
technology is still in need to further development before it would be a likely option for this region.
Similarly to a potential LNG virtual pipeline, a transmission line may be able to connect to a
power plant that is developed at the mine site, helping to share the cost of the power plant
21
development with Donlin Gold's demand. The challenge with a transmission line is that it only
moves electricity, and likely does not help address home heating in a significant manner. It
does however facilitate opportunities to integrate renewable energy projects that might be
developed in the region.
This study does not include a detailed analysis of a transmission line, as the primary focus is the
opportunity to directly transport and use the natural gas. Two studies by NANA Pacific (2008)
and FIDE Roen (1995) were consulted in order to include basic considerations of a power
transmission option. Both studies estimate a per mile cost of a power line in this part of Alaska,
depending on the power transmitted to be between $500,000 and $1,000,000/mile. This can
vary, as can the cost for a pipeline greatly based on permitting, right of way, building and
material costs.
5.2.1 Implications and adoption scenario
A transmission line offers a number of implementation advantages over some of the other
options, as it is relatively easy to integrate with existing electrical systems. The line itself would
also allow for the integration of other potential power sources, both renewable and other along
the length of the line.
In or near a community accessing the transmission line, a substation would need to be
constructed to step the power down from the transmission line to lower voltages for local use.
Spur lines could also be constructed off of a main line to enable reach to additional
communities.
One of the issues that would need to be addressed, as in the other options, is motivation for the
local utility to commit to connect to the transmission line. Privately owned, non -regulated
utilities may not be willing to invest in infrastructure to access the line, particularly if their current
generation capacity is not in need of replacement. There could be opportunities to overcome
this barrier by either changing the structure of the utilities, offering a wholesale price to the local
utilities that is lower than their operating costs of operating their own generators. Another option
is for the owner of the transmission line to integrate the cost of substations and connections to
the local grid in the wholesale cost of electricity.
Building a transmission line from the Cook Inlet region to Donlin Creek was one of the options
that Donlin Gold considered in their plan to power the mine. After their internal review of power
options, they decided on a natural gas pipeline.
5.3.1 Benefits of the transmission option
• A transmission line adds the ability to move power between multiple generation sources,
including the mine site, as well as local generators and other potential renewable power
development.
• At some point in the future, a transmission line could be connected with other lines to
develop a rural Alaska Grid.
22
Electricity is the easiest option to integrate with existing power distribution systems in
each community it would serve
5.3.2 Challenges of the transmission option
• This only provides electricity for communities, and is not likely to replace home heating
fuel.
Transmission lines would require land access and environmental permitting. This could
be particularly challenging for the portion of the line running within the Yukon Delta
National Wildlife Refuge. Not only would it affect the land that the transmission line
operates on, but also potentially impact protected viewscapes and migratory routes for
birds and mammals.
6.1 Integration of options
Based on the variety of needs, costs, regional energy environment, and the advantages of
various energy transmission options discussed in this paper, is most viable option may be a
combination of presented. This would also facilitate an incremental adoption.
One incremental adoption scenario might begin with the simplest and least capital intensive
option, IF a gas liquefier or even compressor, is developed at Donlin Creek. This might look like
only a few power plants along the river converting their generators to dual -fuel, with fuel
delivered and stored as LNG. If the gas cost is low enough to lower the cost of electrical
generation in the community, it may become cost effective to develop small transmission lines
to neighboring communities. It also might make sense for that community to invest in the
storage and generator conversion system to start using natural gas themselves.
With these power producers already using natural gas, it might then aid the business case to
begin building a pipeline for at least part of the distance. A natural evolution on this scenario is
to start using LNG in the Aniak to Crooked Creek corridor with temporary storage infrastructure.
At some point, it may then become viable for a pipeline to be developed to Aniak, as in the
example below. At that point, some of the temporary infrastructure that would be used in Aniak,
could be used in another community down river to integrate them into a virtual pipeline.
Another example would be to build a gas pipeline to a location near Aniak. In the Aniak area, a
natural gas supply chain "hub" might be developed, with a liquefier, or compressor, near the
river, that would allow shipments to communities between Aniak and Bethel using a virtual
pipeline concept for both power and home heating. This infrastructure, either through a road
from the liquefier to the Yukon River, or an additional spur pipeline to a point near the Yukon
River, would facilitate adoption of natural gas for the communities on that river system.
In Aniak, a power plant might be developed using natural gas from the pipeline to produce lower
cost electricity, that is then transported to downriver communities by a transmission line.
2
6.2 Cost Comparison of options
This study only covers order of magnitude costs, and does not have within its scope specific
costs for each option. In the case of an incremental or virtual pipeline approach to natural gas
adoption in the region, costs can vary dramatically, but can often times be scaled to allow for
roll -out with more modest capital investments. Please note that these estimates are based on
consultation with experts in their field and published studies, each of which note that the final
cost of an option can vary widely, and would need to be more accurately determined in a more
rigorous full feasibility study. Additionally, permitting, right-of-way costs, and other costs related
to the projects are not included. Also not included are operating expenses.
Please note as well, that the cost comparisons include the assumption that the project
proponent would be able to buy electricity from Donlin Creek's power plant, and the ability to
buy LNG from a possible plant at Donlin Creek. It is still unclear at this point in time if either or
both of these options would be possible.
Option 1 - Pipeline Cost overview for 173-mile 4.5" pipeline:
Pipeline Cost _ $124,560,000
Compressor Stations $3,600,000
Total Cost $128,160,000
Option 2 - Virtual Pipeline "starter kit" Cost, based on using for 114 the fuel used in power
generation in Bethel (Figuring use of Natural Gas for '/z of generation for '/z of the year with river
access or stored LNG.) Not included are the conversion of the power plant, which would likely
be in the $75,000-$500,000 range, but vary greatly based on type and size of generator set
Item
Number of units
@cost
Total
40' ISO containers
10,000 gallon capacity)
4
$190,000
$760,000
100,000 gallon
permanent LNG Storage
tank
2
$1,500,000
$3,000,000
LNG re -gasifying Unit
1
$100,000
$100,000
Total Cost
$3,860,000
Option 3 — Transmission line
Item
Number of Units
@Cost
Total
Transmission Line
173 miles
$1,000,000
$173,000,000
Total Cost
$173,000,000
24
6.3 Financing and Funding
For all option, one part of the financing decision will depend on the cost differential of natural
gas at the mine site, as compared to the cost of diesel in the same market. If there is a
significantly lower cost of natural gas, there may be more options available to finance any
infrastructure upgrades through the cost savings over current fuel -oil and diesel costs.
In the case of a virtual LNG supply chain, the capital investment in equipment would be fairly
modest and capitalization of the cost of the upgrades attractive to both publically supported
financing, such as the Alaska Industrial Development and Export Authority (AIDEA), an equity
investor or another lender.
Should the difference in fuel cost between fuel -oil and LNG delivered to Bethel at a $1 per
gallon equivalent discount, Bethel could switch over '/, of its annual fuel purchase from fuel -oil to
LNG. Based on a 2012 total consumption of 3.1 million gallons (State of Alaska), this is
approximately 775000 gallons per year, or a savings of $775,000 per year. If the utility
borrowed the money at 6% and repaid the lender with about half of the net savings $350,000
per year, it would take about 9 years to pay off the loan.
With a grant, or lower cost financing, even if the project price is double the estimate included in
this report, this option could be paid for within a relatively short period of time, only using the
cost differential between the fuels. One of the issues however would continue to be if any
savings in fuel cost would be passed on to the consumer.
For the gas pipeline or transmission options, financing becomes much more challenging and
would likely require grants and low cost financing for either to be viable without additional power
demand. When one considers that all the communities on the entire Kuskokwim River from
Crooked Creek downriver only use about four million gallons of fuel for electricity production per
year and 53,000 MW/hours of power per year, the demand would likely not directly off -set the
costs of the pipeline or transmission line. Two previous studies by NANA Pacific (2008) and
FPE Roen Engineers (1995), both concluded that for the time being, a transmission line of this
magnitude would be challenging to finance in Western Alaska.
One option for the transmission line is to look at it within a broader development of a statewide
power transmission system, and develop a cost sharing plan with the State of Alaska and/or the
Federal Government. This could include grant funding, loan guarantees and low cost financing.
Another option is to look the opportunities to integrate other forms of renewable power
generation into the transmission line route. This power could possibly be sold back to the mine,
the leading power consumer in the region.
For both a pipeline and a transmission line, the economics greatly improve with a greater
customer demand to spread the costs across. A pipeline would have a challenging economic
case to be made, based on the amount of fuel officially counted and consumed in the region.
There are however a number of other fuel users along the river that are not likely reflected in
official numbers. This includes construction, asphalt, commercial river and marine vessels and
25
other operations that bring their own fuel with them. As an example, a mobile asphalt plant,
used to repair or build a runway, will typically use between 3,000-10,000 gallons of burner fuel a
day. This can be replaced by LNG with some modification to their plant. Marine vessels are
also beginning to use natural gas for propulsion as well.
One option for a pipeline, that a transmission line may not be able to offer, is the ability to
extend a "virtual' pipeline out to the Bering Sea, to meet fuel demands all along the west coast
of Alaska. In this case, a liquefaction or compression plant would be built in Bethel, for
transshipment of LNG or CNG via river and ocean to other communities. This could
significantly increase the amount of product travelling through the pipeline over which to
amortize the cost of the project.
Much of the structure of any financing or grants will depend on the proponents of the project.
As discussed, a pipeline to Donlin Creek will likely be built by a third party that will be financed
based on a long-term supply contract for the mine. This would be the traditional way for a
pipeline to be built to Bethel. Due to the disparate nature of energy demand along the river, it
will likely take a different approach to build a pipeline, transmission line or even virtual pipeline.
This would likely include the proponent of the project having a community responsibility, as well
as a bottom line responsibility. Entities that may be able to further develop projects of this
nature may be regional or village corporations, energy coops, including Alaska Village Electric
Cooperative, or a public utilities district.
7.1 Closing Discussion
Should the Donlin Creek Mine and its natural gas supply pipeline be built, it will likely have a
very large impact on western Alaska. While Donlin Gold has made clear its wish to work with
the communities surrounding the mine to benefit from the natural gas, it is up to the
communities to develop any plans in this area. Donlin Gold should not be looked upon as a
utility that might figure out how to sell more gas to western Alaska, but rather be thought of as
an energy supply chain partner. It is therefore necessary the Yukon-Kuskokwim community to
identify the entity, or entities, that are going to pursue projects for the region.
It will likely be incumbent upon that large consumers of fuel and electricity, including the school
districts, local governments, the village councils, the YKHC and local utilities to establish a
mechanism to further evaluate and possibly develop off -take agreements with the pipeline
operator that decreases their fuel costs. This might be in the form of a new entity or an existing
one.
At this point in time, there are still many variables that make it difficult to fully engage in the
development of a region wide adoption strategy. It is still unknown if a liquefaction plant may
become part of the Donlin Creek Project. The final size of the pipeline to Donlin Creek is still
unknown, as is their actual natural gas needs. As discussed earlier, it is not yet even
established how gas will get into the pipeline in Beluga.
26
Even with this uncertainty, due to the time frames needed to develop a transmission line or a
pipeline, there is little time to waste and a need for a strong local proponent. One option to get
started with the use of natural gas is a virtual pipeline, which could be deployed rapidly, but has
a number of drawbacks, mostly because of supply interruption risk. It may be a stepping stone
to a more robust and long-term system or a solution of its own. In any case, it is a way to start
getting savings flowing downriver as quickly as possible once the pipeline is in place.
7.2 Recommendations and areas for further study
While this pre -feasibility study was intended to introduce options for use of natural gas that may
be delivered to the Donlin Creek mine site, it is only a small step in the full evaluation and
possible development of a fuel cost reduction project in western Alaska. Should a full feasibility
study for any or all of the options discussed in this paper be pursued, the following outstanding
issues may be of interest.
• The development of a more complete fuel profile for the region, that includes
approximations of fuel brought in by outside parties such as construction, asphalt and
vessel operations companies. This could be a large number, and at some point, natural
gas could replace some of that usage.
• Exact energy demand and pipeline capacity rates should be firmed up. If there is not
enough capacity in the pipeline to meet demand, then the main pipeline should be
considered for expansion to accommodate a larger capacity.
• More research should be done to assess the feasibility of supplying natural
gas/electricity to the Yukon River and servicing the communities there.
• Not all of the communities in the YK region would be able to be served by this project.
This may cause some controversy and needs to be addressed.
• 75% of the Port of Bethel's revenue is generated by a delivery fee of fuel to into the tank
farm. By replacing this fuel with natural gas, the impact on the Port should be further
analyzed.
• An analysis of the impact of the mines eventual close, currently forecast at 27 years,
would have the supply of natural gas in the region.
• Further investigation may already be underway, and if not, may need to be considered
on a transmission line in the region, especially if there are other energy sources that may
be available for integration.
8.1 Acknowledgements
This paper was made possible by many people and companies that shared their expertise and
time. Many thanks to: Geoff Cooper, Institute of the North; Senator Lyman Hoffman and
Patricia Walker, Alaska State Senate; Representative Bob Herron and Rob Earl, Alaska State
House of Representatives, Kurt Parken and Mary Sattler, Donlin Gold; Gene Peltola, Yukori-
Kuskokwim Health Corporation; Ana Hoffman, Bethel Native Corporation; Zack Brink,
Orutsararmuit Native Council; Gary Baldwin, Lower Kuskokwim School District; Gene "Buzzy"
27
Peltola, Yukon Delta National Wildlife Refuge; Ron Powell, Jody Waddington and Heather Fett,
City of Aniak; Bruce Harland, Crowley, Jim Hemseth, Alaska Industrial Development and Export
Authority (AIDEA), Kirk Montague, Plum Energy; David Barr, Taylor -Wharton; Paul Manson, Sea
Breeze Power; Bill Aus, CONAM Construction Company; Gloria Chythlook, Bill Wilson and
many others.
28
Works Cited
FPE Roen Engineers. (1995). Transmission Intertie Feasibility design and cost estimate Bethel -
Nyac. Anchorage, AK.
Golden Valley Electrical Association. (n.d.). At a Glance 2012. Retrieved 12 2, 2012, from
http://www.gvea.com/images/pdf/ataglance l 2_2.pdf
NANA Pacific. (2008). Distributing Alaska's Power.A technical and policy review of electric
transmission in Alaska. Anchorage.
Newell, R. (2011, February 2). Long-term Outlook for Natural Gas. Retrieved December 10,
2012, from US Energy Information Administration:
http://www.eia.gov/neic/speeches/newell_aeo_ng.ppt
NovaGold. (n.d.). Presentation for the 2012 John Tumazos Very Independent Research
Conference in New York. Retrieved 11 5, 2012, from
http://www.novagoid,com/upload/pdfs/presentations/2012-10-03_NG_JTVI R_2012.pdf
State of Alaska. (n.d.). Alaska Energy - Community Energy Models. Retrieved October 4, 2012,
from Alaska Energy:
http://www.akenergyauthority.org/PDF%20files/AK_Energy_Model_Comm.pdf
US Energy Information Administration. (n.d.). AEO2012 Early Release Overview. Retrieved
November 21, 2012, from US Energy Information Administration:
http://www.eia.gov/forecasts/aeo/er/pdf/0383er(2012). pdf
29
APPENDIX A
31)
PRICE GREGORY INTERNATIONAL
KLISKOKWIM GAS PIPELINE
Proiect Description
The Kuskokwim Pipeline project consists of a gas pipeline extending from the Donlin mine site north of
Crooked Creek to Aniak and Bethel. The pipeline will have a throughput of 4 MMSCFD with an estimated
line size of 4". A compressor station may be required adjacent to the Donlan mine site to provide line
pressure for gas transport through the pipeline. A gas pressure reduction station will most likely be required
for a branch line at Aniak. Based on a preliminary line route, the distance from the Donlin mine to Aniak is
roughly 60 miles, while the distance from Aniak to Bethel is 111 miles for a total length of 171 miles.
Preliminary Construction Plan
Construction will most likely be performed over (2) winter and (1) summer construction seasons. Because
of the terrain, the section from Donlin to Aniak will be predominately summer construction with some
winter portions where wetlands are encountered. The section from Aniak to Bethel will be performed
during the winter with the use of ice roads due to the wet soils. Pricing is based on utilizing standard steel
pipe design with pipe purchased in 60' lengths. Materials will be barged up the Kuskokwim with likely
storage yards at Donlin, Aniak, Tuluksak, & Bethel. Camps will also be required at these locations. An option
is to use coiled tube for the section from Aniak to Bethel. This is essentially long tube sections coiled onto a
spool. For a 4" line, a single spool will hold as much as 5,200 ft of pipe, however, the spools are large (17'
Diameter) and are heavy (71,200 Lbs). Special equipment is required to uncoil and straighten the pipe. (See
attached information)
Design Assumptions
Line Size: 4.500" Dia (Wall Thickness 0.237" STD Wall)
Line Length: 173 Miles Assumes a 2 mile branch line to Aniak
Design MAOP: 1480 PSIG May be reduced depending upon delivery pressure
Design Flow Rate: 3 - 4 MMSCFD
Compressor Station HP: 240 HP Use 15% of Donlin Station
Estimated Costs
Pipeline Costs $ 124,560,000 Based on $180,000 per Diameter Inch -Mile
Station Costs $ 3,600,000 Based on $15,000 per Operating HP
Attachments: Preliminary Route and Profile
Coiled Tubing Information
Donlin Gas Pipeline Cost Summary
11/28/2012
PRICE GREGORY INTERNATIONAL
DONLIN GAS PIPELINE SUMMARY INFORMATION
Proiect Description
The Donlin Gold Mine is located roughly 11 miles north of Crooked Creek adjacent to the Kuskokwim River.
A 12" diameter gas pipeline is proposed to provide gas for mine power and operations. The pipeline will
originate on the west side of Cook Inlet north of Beluga via a tie-in to the Enstar 20" gas pipeline. A single
compressor station is planned at the Enstar tie-in to provide line pressure for gas transportation. The main
obstacle for pipeline construction is the remoteness of the right-of-way and the necessity of routing through
Rainy Pass. Main access to the route for supply of pipe and construction equipment is limited to the
Kuskokwim River on the west side and Cook Inlet on the east side. Secondary supply points are Skwentna
and the Donlin mine site. The construction plan assumes construction of a temporary road along the
pipeline route to allow movement of materials, construction equipment, camps, and personnel from these
main access points. Hauling of pipe materials would mainly be performed during the winter months when
the frozen soils would provide a more stable ground surface. Camps will be required along the route to
house construction personnel. Fuel for camp generators and construction equipment will need to be
trucked or flown into the camp locations.
Design Information
Line Pipe:
12.750" Dia (Wall Thickness varies from 0.300" to 0.500" - Av 0.350")
Line Length:
313.7 Miles
Design MAOP:
1480 PSIG (600# ANSI Rating) - 550 psig delivery pressure at Donlin
Design Flow Rate:
40 - 50 MMSCFD
Station HP:
1600 HP (2008 Estimate)
Estimated Costs
Pipeline Materials:
$ 116,000,000
Pipeline Construction:
$ 350,000,000
PL Design/Owner Costs:
$ 116,500,000 (Inc. Construction Management and other misc. costs)
Project Contingency:
$ 87,375,000 15%
Total PL Cost:
$ 669,875,000
Station Costs w/ Contin.
$ 20,000,000 (2008 Estimate)
Annual Operation/Maint.
$ 2,750,000
Pipeline Cost per DI -Mile
$ 176,935
Station Cost per HP
$ 12,500
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