HomeMy WebLinkAboutGuide for Alaskan Communities Utilize Local Energy Resources AK Energy 01-2009PB 1
ALASKA ENERGY
A first step toward energy independence.
January 2009
Prepared by:
Alaska Energy Authority
Alaska Center for Energy and Power
A Guide for Alaskan Communities to Utilize Local Energy Resources
2 323
Copyright Information:
This publication for a Statewide
Energy Plan was produced by the
Alaska Energy Authority per legislative
appropriation. The report was
printed at a cost of $12.00 per copy
in black and white, and $58.00 per
copy in color in Anchorage, Alaska by
Standard Register.
2 323
6 Sustainable Energy for Alaskans
8 How this Document Should be Used
17 Railbelt Region
22 Energy in Alaska
33 History of Energy Policy in Alaska
38 Current Energy Policy and Planning in Alaska
44 Policies with Energy Implications
55 Permitting
57 Technology Chapters
58 Diesel Efficiency and Heat Recovery
74 Efficiency (End-Use)
84 Hydroelectric
101 Wind
120 Biomass
135 Geothermal
150 Heat Pumps
156 Solar
161 Coal
168 Natural Gas
175 Delivery
179 Energy Storage
190 Hydrokinetic/Tidal
204 Wave
211 Nuclear
217 Coal Bed Methane
223 Fuel Cells
224 Alternative Fuels
232 Explanation of Database Methodology
240 Glossary
242 Units of Measure
243 Acronyms - List of Organizations
244 Acknowledgements
Table of Contents
Copyright Information:
This publication for a Statewide
Energy Plan was produced by the
Alaska Energy Authority per legislative
appropriation. The report was
printed at a cost of $12.00 per copy
in black and white, and $58.00 per
copy in color in Anchorage, Alaska by
Standard Register.
4 545
The narrative and model in this report are designed
to provide information to engage Alaskans who have
a passion to provide energy solutions, stimulate the
Alaskan economy and provide leadership for the benefit
of all Alaskans.
Alaska has had many high-quality energy plans written
over the years, but none ever gained traction to come
to fruition. To increase the likelihood that energy
solutions will become a reality, the new approach will
engage Alaskans in the solution and invite their active
participation in the selection and ownership of their
alternative energy sources.
The safe approach to conducting this work would have
been to hire a consultant. With some risk but a large
increase in the service to Alaskans, the Alaska Energy
Authority chose to utilize the expertise of in-house
staff. This personal accountability by the professionals
at AEA will help ensure Alaskans have access to energy
information and a single location they can work with to
resolve their energy challenges and opportunities. As
more information becomes available, the information will
be placed in the energy model for use by decision makers
long into the future.
Steven Haagenson
Statewide Energy Coordinator
4 545
6 767
We Alaskans live in a magnificent state that has
many blessings when it comes to energy, but also
some curses. Alaskans live in a state with abundant
energy resources, but are hampered by long distances
and low usages.
The Alaska Energy Authority (AEA) has developed
this document to act as a first step toward energy
independence for Alaskans. The document contains
two main sections - a narrative which you are
reading now, and a technology screening tool we
have developed to allow each community to review
locally available resources and determine the least-
cost energy options based on the delivered cost of
energy to residents.
Energy use in each community is composed of three
major components: electricity, space heating, and
transportation. The relative level of use and cost for
each of these components differs across Alaska. For
instance, Anchorage residents pay comparatively
less for electricity and space heating, but more for
transportation due to heavy dependence on vehicle
travel. Rural Alaskans see lower vehicle travel,
but have much higher costs for heating oil and
electricity.
All of America is struggling with the high cost of
energy, but Alaskans have the resources, the ability,
and the motivation to create long-term solutions that
will greatly benefit our children and grandchildren.
AEA’s goal in developing the Alaska Energy Plan is
to reduce the cost of energy to all Alaskans through
deployment of energy technologies that are vertically
integrated, economic, long-term stably priced, and
sustainable.
In order to achieve this goal, we will be engaging
Alaskans throughout the state who have the expertise
and passion to use local resources to reduce their
Sustainable Energy for Alaskans
dependence on petroleum. This effort must be
approached as a team effort, where each participant,
private or public, can provide value for permitting,
construction, applied research and development,
natural resource management, financing, workforce
development in management, design, business,
construction, operations, economic development,
wealth retention, and leadership.
Alaska Energy - First Steps
The first step in creating this document was to
identify each community’s current energy needs
for electrical generation, space heating, and
transportation. It is important to know these values
as they provide a reference or measuring stick
against which we can measure alternatives. Electric
power usage was obtained directly from current PCE
reports, while heating oil and transportation was
estimated by the Institute of Social and Economic
Research (ISER) based on modeling.
AEA conducted 28 Town Hall Meetings across the
state, engaging many Alaskans through the process
of seeking answers to three fundamental questions:
1) What resources near your community - where
you live, work, play, fish, and hunt - could possibly
be developed to help lower energy costs? 2) What
resources should not be developed? 3) Why not?
The information gathered from these Town Hall
Meetings was used to develop a resources matrix
for each community. Potential resources identified
included hydroelectric, in-river hydro, wind, solar,
wave, tidal, biomass, geothermal, municipal waste,
natural gas, propane, coal, diesel, coal bed methane,
and nuclear. Also identified were opportunities
for gasification and production of Fischer-Tropsch
liquids.
6 767
For each resource, AEA formed Technology Teams
made up of people with expertise and a passion
for energy solutions who were asked to identify
technologies options and limitations for each
identified resource. The Alaska Center for Energy
and Power (ACEP) at the University of Alaska was
brought in initially to help guide the technology
discussions, and ultimately went above and beyond
in their work on the narrative and the comparative
database.
Appropriate technologies for each fuel have been
identified. Capital and operations and maintenance
costs for each technology have been determined and
adjusted by region through use of factors developed
by HMS Construction Cost Consultants.
The net result is a focusing tool that will provide
each community with a high-level snapshot of the
least-cost options for electricity, space heating, and
transportation for their community. Prices will be
based on a delivered cost that includes capital cost
for infrastructure. The delivered cost number can
be used to quickly compare the alternative energy
options to diesel fuel based on a range ($50-$150) of
crude oil prices.
This first step in the ongoing Energy Plan is
intended to provide a high-level tool to focus each
community on its relative options for generating
electricity and heat through the use of locally
available resources. This is an important step in
developing a community, regional, and statewide
energy plan. This process is intended to occur in
stages, and it allows the state to provide assistance
with maximum support and buy-in from Alaskans.
Starting at the local level and using this plan as a
building block to develop regional and statewide
energy plans, the goal is to engage citizens directly
in developing energy solutions for Alaska.
Sustainable Energy for Alaskans
8 989
The illustration on this page shows a sample
community energy meter. The energy meter is part
of the technology screening tool and allows for a
quick comparison between alternative energy options
based on a range of future crude oil prices for each
community in the state. As part of this screening
analysis, current electric and space heating costs are
compared on a total cost basis with capital, operation
and maintenance (O&M), and fuel costs for various
technologies. The focus is on near-term, commercial,
and proven
technologies,
although an
assessment
of some pre-
commercial or
potential future
options are also
included.
The options for
each community
are compared with
the current cost of
energy as well as
a diesel equivalent
range of $50/bbl
crude oil (low
projection) to $150/bbl (high projection). There
are many communities with access to alternative
resources that can potentially provide energy at a
cost below the diesel equivalent of $50/bbl crude oil.
A sub $50 resource is defined as the Green Zone and
can include wood (biomass) heat and wind/diesel
options in the short term, as well as hydroelectric or
geothermal options in the long term. The projection
indicates that a Green Zone option alternative could
reduce energy costs even when crude oil is at $150/
bbl.
For most communities, the resource options fall
within the cost range for diesel equivalent with crude
oil between $50/bbl and $150/bbl. The $50-$150
range is considered the Yellow Zone and can include
the entire range of energy alternatives.
Some communities have options that exceed
the diesel equivalent of $150/bbl. This range is
considered the Red Zone and indicates resources
that are probably not cost-effective to develop at
this time. If no other resources exist, a broader
regional evaluation should be conducted to search
for available options
in nearby communities
with Green or Yellow
Zone resources. The
high cost is likely a
function of the size of
the community, or the
distance to available
resources.
In some communities,
the resource capability
is much larger than
the current energy
requirements of the
community. For
resources developed to
their full capacity but
only using a portion of the energy, the cost would
be high and could shift into the Red Zone. This is
the case with some of the larger hydroelectric and
geothermal resources. In this case, the community
could look at ways to use excess capacity from the
resource to spur economic growth opportunities and
lower the cost of energy to residents.
There are several communities that do not have any
viable alternative energy resources. This finding
demonstrates the need to follow up with regional
evaluations to assess potential alternatives beyond
the immediate area of the community. It is also
How this Document Should be Used
8 989
likely that some communities are too small or too
remote, and the most economic answer would be
to continue to use diesel fuel for the forseeable
future. However, this analysis indicates that most
communities have at least one opportunity to reduce
diesel use, even if solely through implementing
efficiency measures.
We believe that use of local resources will help
stabilize local economies by developing jobs to
build, operate, and maintain energy systems. Local
jobs will also be created where fuel collection,
processing, and transportation are required. In this
way, the dollars currently spent on diesel fuel could
be recirculated within a community and used to
strengthen the economic base.
The next step is to engage Alaskans at the regional
level to discuss results from this screening tool.
These regional meetings will provide a forum for
additional community input. Meetings will also be
conducted with utilities, municipalities, and native
corporations to develop public/private partnerships
and engage these entities in developing long-
term energy solutions. Local buy-in will permit
more focused regional feedback to the legislature,
thus insuring that the best options are being
recommended for approval. The screening tool is
also designed to be continually updated as more
information is available. In this way it will serve
as a valuable tool for the legislature and governor
when they consider energy requests in future capital
budgets.
The focus of this work is on the non-Railbelt
portions of Alaska. That is where the need to
reduce energy costs is greatest. The Railbelt will
be addressed through an Integrated Resource Plan
(IRP), which will evaluate multiple energy sources
and delivery systems. It is likely that the solution
for the Railbelt will be a combination of available
resources such as large hydroelectric projects,
natural gas supplies, pipelines, biomass, wind, and
geothermal systems.
How this Document Should be Used
10 111011
Alaska has abundant resources and Alaskans have
enjoyed relatively low-cost diesel prior to the pricing
surge in 2007 that extended through the summer of
2008. When fuel prices are low and stable, interest
in the use of locally available alternative fuels is
low. When prices spike, interest likewise becomes
high, but the opportunity to use lower-cost fuels
may not exist without proper planning, research,
and development. During oil price spikes in the
1980s, there was much interest in alternative energy
across the nation, including Alaska. Nevertheless,
projects such as the Susitna Hydroelectric Dam were
canceled when crude oil dropped to $9.00 per barrel.
We have recently seen the price of crude drop from
$124/bbl to $28/bbl, and lower, in a reduction
similar to the one in the 1980s. This drop in oil
prices hits Alaska doubly hard, as a reduction in
state revenue limits funds available to develop the
necessary infrastructure needed to switch to lower-
cost fuels when crude oil prices again rise. The
general consensus is that oil prices will again rise,
but there is on-going debate about the future price of
crude oil and the long-term volatility. Alaska is an
oil-producing and exporting state, but there are many
external factors that will increase or decrease crude
oil pricing. In a global market with large consumers
like India and China, Alaskans will be riding the
market roller coaster with little influence on the final
price determination. What can be controlled in this
energy world?
Alaska has numerous energy resources and the
power to choose its fuel supplies. A method is
needed to place these choices in perspective. Public
awareness needs to increase. There may be energy
options that can provide lower-cost energy than
today’s $50/bbl oil. Resources that could be used to
power and heat Alaskan communities and provide
opportunities for local economic development should
not sit unused. Alaskans must make the commitment
to shift from diesel as much as possible, even when
prices are low, if we are to avoid high costs in the
future.
This document can provide insight into the energy
opportunities that lie ahead for Alaskans. The
technology screening database is based on data
collected from numerous sources throughout the
state. Where data has not been collected, models
were developed to approximate the missing data.
For example, ISER developed a model to predict the
amount of heating oil used for spacing heating and
vehicular transportation by community.
Data pertaining to population change and Power
Cost Equalization has also been incorporated and is
felt to be reliable and accurate.
The cost estimates contained in this report were
conducted at the conceptual level with no site-
specific design or scope development. Cost
estimates were based on similar historical energy
projects constructed in Alaska, vendor estimates,
and historical studies and reports for specific
applications. These need to be recognized for
what they are: high level conceptual cost estimates.
The recommendations are based on the best data
currently available, but detailed site specific cost
estimates must be completed prior to project
selection to determine more accurate values.
How this Document Should be Used
10 111011
The technology screening tool exists in two
sections. The first is the energy meter page for a fast
scan of local resources. The second is in a numeric
results format for a more in-depth analysis of the
data.
The energy meter page has been prepared for every
community in Alaska located “outside” the Railbelt
region. The numbers are reported as specific values
for convenience, but in actuality contain a high
degree of uncertainty as a result of incomplete
data, conceptual cost estimates and estimates
based on models. They are intended to provide an
approximate value for the delivered cost of energy
from a particular resource. Prior to finalization of
an energy resource selection, a detailed site-specific
cost estimate must be done to determine actual
project costs for financing and benefits evaluation.
The energy meter page has two meter faces, one for
the cost of electricity and one for the cost of space
heating. The meter dial has three colors, green,
yellow, and red. They are linked to the cost of crude
oil. In the past few months, crude oil prices have
ranged between $150/bbl to $30/bbl. With the price
volatility of crude oil, the meter face was developed
to show the locally available energy sources with
respect to a variable pricing of crude oil. Rather
than predict the future price of oil, the green, yellow,
and red zones have been created. The Green Zone
defines relative costs for crude oil pricing of $50/bbl
or less. The Yellow Zone defines cost above $50/
bbl, but below $150/bbl. The Red Zone represents
crude oil costs above $150/bbl.
The cost of electricity and space heating from diesel
fuel shown on the meters are computed using the
price of crude oil, delivered to the community and
used in the existing infrastructure. The electrical
costs include non-fuel costs so the electrical cost
shown will relate to the cost per kilowatt-hour shown
on the billing statement, prior to the applicable PCE
reduction.
A community can select its fast scan sheet and look
for resources in the Green Zone. If resources exist
in the Green Zone, this is an indication that local
resources might provide a less expensive stable-
priced energy source, even if the cost of crude
oil were to rise. Green Zone resources should be
reviewed for projected construction costs and time,
since the most economic projects, such as hydro or
geothermal, tend to have a longer construction time.
If all Green Zone projects have long construction
times, look at the Yellow Zone for resource options
with a shorter delivery schedule.
The Yellow Zone is the range of possible crude
pricing we have seen over the past few months.
Predicting crude oil prices can be risky if not
impossible. The recent reduction in crude prices is
believed to be temporary, but exactly when and how
much prices will rise is not known. If resources
exist in the Yellow Zone, this indicates that the
alternative resource may not be economic unless
crude oil prices were to rise. This is also the zone
where the state could assist in paying down the
capital debt component to reduce the resultant cost
of energy to the community. If $50/bbl is the target
point for state assistance, then, rather than paying
the entire capital cost of the alternative project, the
state assistance should be limited to paying capital
costs down to the Green Zone or the $50/bbl target
point. Using the target point concept will help
produce alternative energy at a level that can be
sustained. For example, large hydroelectric projects
are capital intensive but have low O&M cost on
the order of $0.01/kWh. Rather than assuming full
capital relief and yielding the low O&M cost only, a
balance of loans and grants could be applied to bring
the resulting energy costs down to the pricing point
equivalent. The all or nothing approach to capital
funding may result in the wrong pricing signal for
energy, and over-expend funds in one area while
other areas will be paying much higher prices. Both
short and long-term projects can exist in the Yellow
How this Document Should be Used
12 131213
How this Document Should be Used
Sample CommunityZone. As the values of resources have a wide
range, several of the lower-cost options should be
reviewed for further investigation. As a general
rule, short term projects should be selected first,
with the addition of larger or longer term projects
that will further reduce the cost of energy to the
community.
The Red Zone includes projects that are not cost
effective at this time and will not be so unless
technology develops to reduce the resulting energy
cost, or until crude oil is above the $150/bbl price.
The numeric results sheet can be used for a more in-
depth analysis of the data. The first part identifies
the current energy needs and costs for electricity,
space heating, and transportation.
The current use can be compared to the existing
capacity and energy usages to determine the
general resource size required for the community.
If a selected resource is much larger than the
community needs, an economic development
opportunity exists. For the community to achieve
the lowest price, the resource will need to be used
to its maximum. In this case, additional loads
must be developed to match the capacity of the
energy resource. For example, if a geothermal
source exists that is larger than the community
needs, the community could develop a fish cannery
and use an absorption chiller to make ice in the
summer or grow vegetables under grow-lights in a
geothermally heated greenhouse in the winter.
Financing of energy projects is expected to be
a mix of bonds, loans, private equity, grants or
financial guarantees. To ensure the financial
success of energy projects, good business practices
would require the creation of a project scope,
cost estimate, project business plan, management
team, design team, financing plan, and permitting
strategy. Business plan development will also be
necessary for grant and loan approval, with an
evaluation of the balancing of the risks and rewards.
The community energy model can be used to analyze
and compare different methods and levels of financing
and grants.
Learning from history, we need to recognize past
performance, to avoid the historical results of
alternative energy plans described in the ‘History of
Energy Policy in Alaska’ section of this document.
Specific factors which impeded success of alternative
energy initiatives as stated in the House Research
Report 85-C published in 1985 include:
• State agencies did not develop strong
management capabilities
• State agencies lacked methods for assessing
the technical and financial feasibility of
projects
• Coordination among state agencies was often
lacking
• Features of an alternative technology were
poorly matched with a useful rural application
• Unrealistic expectations existed about what an
agency or technology could accomplish
• Too much responsibility was delegated to
contractors while the state often assumed the
risk in performance of the project
Development of public/private partnerships is critical
for successful implementation, with recognition of
our respective strengths and weaknesses to ensure all
parties are providing quality service to the effort.
Private sector development by electric utilities, native
corporations, municipalities and other qualified entities
will provide access to management, business and
operations expertise. Detailed business planning at
the local level will ensure the technical and financial
feasibility of the projects. The business plans will be
required in all applications for state assistance and be a
core part of the evaluations by state agencies, similar to
the Renewable Energy Fund - Request for Applications
12 131213
evaluation and selection process. The local business
plans will provide a tool to help identify and evaluate
the best application of an alternative resource. The
risks and rewards must be balanced and shared by the
private, public and construction sectors.
Engaging Alaskans
The AEA team will engage Alaskans through a
series of public meetings across the state. Regional
meetings will be conducted in early 2009. The public
meetings will be used as an opportunity to explain
to local residents the use and the results of the
report. This is also an opportunity to obtain feedback
from Alaskans on the initial results and to obtain
additional input. These discussions are an important
step in creating a regional vision for energy
development that has local support and buy-in. The
AEA team will discuss specific local opportunities
and explain the use of the report in a large group
setting.
In addition to the public meetings, the AEA team
will meet with the local municipalities, utilities,
native corporations, and other groups with an
interest in resolving the Alaskan energy challenge.
These discussions will be conducted in smaller
group settings and will help identify the people who
have passion, expertise, knowledge and a realistic
perspective for a specific resource and technology.
How this Document Should be Used
14 151415Sample CommunityHow this Document Should be Used
Akutan
39%
15%
46%Heat
Transportation
Electric
Energy Used
Heat $372
Transportation $147
Electricity:$444
Total:$964
Per capita
Per capita
Per capita
Per capita
POPULATION:859
Aleut Corporation Page 1 of 5Monday, January 12, 2009 Akutan
14 151415 Sample CommunityHow this Document Should be Used
Akutan
POPULATION 859
LOCATION Akutan is located on Akutan Island in the eastern Aleutians, one of the Krenitzin Islands of the Fox Island
group. It is 35 miles east of Unalaska, and 766 air miles southwest of Anchorage.
ECONOMY Commercial fish processing dominates Akutan's cash-based economy, and many locals are seasonally
employed. Trident Seafoods operates a large processing plant west of the City for cod, crab, pollock and fish
meal. The population of Akutan can double during processing months. Seven residents hold commercial
fishing permits, primarily for halibut and other groundfish. Subsistence foods include seal, salmon, herring,
halibut, clams, wild cattle, and game birds.
HISTORY Akutan began in 1878 as a fur storage and trading port for the Western Fur & Trading Company. The
company's agent established a commercial cod fishing and processing business that quickly attracted nearby
Unangan to the community. A Russian Orthodox church and a school were built in 1878. Alexander Nevsky
Chapel was built in 1918 to replace the original structure. The Pacific Whaling Company built a whale
processing station across the bay from Akutan in 1912. It was the only whaling station in the Aleutians, and
operated until 1939. After the Japanese attacked Unalaska in June 1942, the U.S. government evacuated
Akutan residents to the Ketchikan area. The village was re-established in 1944, although many villagers chose
not to return. This exposure to the outside world brought many changes to the traditional lifestyle and attitudes
of the community. The City was incorporated in 1979.
LATITUDE: 54d 08m N LONGITUDE: 165d 46m Aleutians East Borough
Consumption in 2007
kW-hr/galCurrent efficiency 11.81
48,913
Current Fuel Costs $230,488
gal
$0.66
kW-hours510,306
Total
Estimated Local Fuel cost @ $110/bbl $4.71
kW58
Fuel COE $0.45
Fuel Oil:100%
Wood:0%
Electricity:0.0%
2008 Estimated Heating Fuel used:56,012
Estimated Diesel:22,154
Estimated heating fuel cost/gallon $5.71
$/MMBtu delivered to user $51.81 Total Heating Oil
$319,950
Total Transportation
$126,547
Transportation (Estimated)
gal Estimated cost $5.71
Energy Total $785,693
2000 Census Data
Est OM $0.02
NF COE:$0.19
Space Heating (Estimated)
gal
Regional Corporation
Aleut Corporation
Total Electric
$339,196
Average Load
Estimated Diesel OM $10,206
Other Non-Fuel Costs:$98,502
Electric (Estimates based on PCE)
Average Sales
Current Energy Status
/kw-hr
/kw-hr
/kw-hr
/kw-hr
House 37
Senate :S
PCE
Community heat needs in MMBtu 6,721
Estimated peak load 116.51 kW
Aleut Corporation Page 2 of 5Monday, January 12, 2009 Akutan
16 171617Sample CommunityAcheivable efficiency kW-h
New Fuel use 41,267
$194,457
$35,402$0.55
Alternative Energy Resources
Savings
Diesel Engine Heat Recovery
Water Jacket 7,337 gal
14
Stack Heat 0 gal
Upgrade needed:
Semiannual Circuit Rider
Status Completed
Heat Recovery System Installed?
Is it working now?
BLDGs connected and working:
Possible Upgrades to Current Power Plant
Power Plant - Performance Improvement to higher efficiency
New fuel cost
New cost of electricity
per kW-hr
Value
$41,910
$0
Savings
$24,985
Annual Capital cost $628
Annual ID $13,663
Capital cost $7,500
Capital cost $163,112
$0.02Estimated Diesel OM $10,206
/kw-hr$0.00
$0.38
Avg Non-Fuel Costs:$108,708 $0.19
Annual OM $3,262
Total Annual costs $16,926
Heat cost $20.88 $/MMBtu
Geothermal
Installed KW 5000
Capital cost $38,500,000
Annual Capital $2,587,805
Annual OM $1,155,000
Total Annual Cost $3,742,805
0
99.00
Shallow Resource Feet
Shallow Temp C
$0.09
Site Name Akutan - Shallow
200 MW
$0.00
kW-hr/year 41610000
Project Capatcity
Fuel cost:$0
$0.03
per kW-hr
New Community COE $7.55 ($3,403,609)
Savings
$0.06
Heat Cost
$/MMBtu :
$26.36
(includes non-fuel and diesel costs)
Non-Fuel Costs $0.21
Alternative COE: $0.30
% Community energy 8154%
$18.22
$8.13
Geothermal
Installed KW 6000
Capital cost $37,500,000
Annual Capital $2,520,589
Annual OM $1,125,000
Total Annual Cost $3,645,589
0
99.00
Shallow Resource Feet
Shallow Temp C
$0.07
Site Name Akutan - Deep
200 MW
$0.00
kW-hr/year 49932000
Project Capatcity
Fuel cost:$0
$0.02
per kW-hr
New Community COE $7.36 ($3,306,393)
Savings
$0.05
Heat Cost
$/MMBtu :
$21.39
(includes non-fuel and diesel costs)
Non-Fuel Costs $0.21
Alternative COE: $0.29
% Community energy 9785%
$14.79
$6.60
Aleut Corporation Page 3 of 5Monday, January 12, 2009 Akutan
How this Document Should be Used
16 171617 Sample CommunityHydro
Installed KW 197
Capital cost $2,507,920
Annual Capital $97,472
Annual OM $55,200
Total Annual Cost $152,672
69
0.52
Plant Factor %
Penetration
$0.27
Site North Creek
feasibilty
$0.00
kW-hr/year 566166
Study plan effort
Fuel cost:$0
$0.10
per kW-hr
New Community COE $0.51 $186,524
Savings
$0.17
Heat Cost
$/MMBtu :
$79.01
(includes non-fuel and diesel costs)
Non-Fuel Costs $0.21
Alternative COE: $0.48
% Community energy 111%
$50.44
$28.57
Hydro
Installed KW 209
Capital cost $2,509,760
Annual Capital $97,543
Annual OM $55,200
Total Annual Cost $152,743
77
0.54
Plant Factor %
Penetration
$0.22
Site Loud Creek
feasibility
$0.00
kW-hr/year 701186
Study plan effort
Fuel cost:$0
$0.08
per kW-hr
New Community COE $0.51 $186,453
Savings
$0.14
Heat Cost
$/MMBtu :
$63.83
(includes non-fuel and diesel costs)
Non-Fuel Costs $0.21
Alternative COE: $0.43
% Community energy 137%
$40.76
$23.07
Wind Diesel Hybrid
Installed KW 600
Capital cost $4,253,640
Annual Capital $285,911
Annual OM $57,184
Total Annual Cost $343,096
7
8.50
Wind Class
Avg wind speed m/s
$0.28
Met Tower?no
yes
$0.00
kW-hr/year 1218860
Homer Data?
Fuel cost:$0
$0.05
per kW-hr
New Community COE $0.89 ($3,900)
Savings
$0.23
Heat Cost
$/MMBtu :
$82.48
(includes non-fuel and diesel costs)
Non-Fuel Costs $0.21
Alternative COE: $0.49
% Community energy 239%
$68.73
$13.75
Aleut Corporation Page 4 of 5Monday, January 12, 2009 Akutan
How this Document Should be Used
18 191819
Railbelt Region
opportunities and challenges in the Railbelt
Region differ from those in other parts of Alaska.
The Railbelt electrical grid is defined as the service
areas of six regulated public utilities that extend
from Fairbanks to Anchorage and the Kenai
Peninsula. These utilities are Golden Valley Electric
Association (GVEA); Chugach Electric Association
(CEA); Matanuska Electric Association (MEA);
Homer Electric Association (HEA); Anchorage
Municipal Light & Power (ML&P); the City of
Seward Electric System (SES); and Aurora Energy,
LLC as an independent power producing utility.
Sixty five percent of Alaskan population lies within
the Railbelt region.
The southern portion of the Railbelt: Mat-Su Valley,
Anchorage, and the Kenai Peninsula are highly
dependent on natural gas as a source of electricity
and heat. The northern portion of the Railbelt
including Fairbanks and other communities in the
Interior relies on petroleum fuels in addition to
natural gas, coal and hydroelectric electrical imports
from the south. Petroleum fuels provide the majority
of energy used for transportation across the entire
state.
Nearly all of the thermal generating capacity in the
Railbelt is more than 20 years old, and much of
it is more than 30 years old. The majority of the
generation is predominately combustion turbine
generation. There are five utilities to the south of the
Alaska Range. GVEA is the sole utility to the north.
A Regional Integrated Resource Plan (RIRP) is
being developed to identify and evaluate the best
resource mix to insure that least-cost options for
electricity and heat are developed in the Railbelt
region. The RIRP will be completed in late 2009
and will consider multiple energy options and
make a recommendation on specific projects to be
developed.
The complete Request for Proposals on the Regional
Integrated Resource Plan for the Railbelt Region of
Alaska can be found on the Alaska Energy Authority
website, www.akenergyauthority.org.
The current generation mix includes a number of
existing hydroelectric power plants that are operating
in the southern portion of the Railbelt. Two coal-
fired power stations (one operational) are positioned
within GVEA’s service area at Healy River, near
extensive sub-bituminous coal resources available
from the Usibelli coal mine.
The Cook Inlet gas basin still yields large quantities
of natural gas for power generation and space
heating, but known reserves are now falling and
dropping field operating pressures are causing
concern that the region may not be able to depend
on lower Cook Inlet for adequate gas supplies in
the future. There are several proposals to construct
pipelines that could bring Alaskan North Slope
natural gas into the Railbelt. Consideration of these
potential fuel sources will be a part of the integrated
resource plan for the Railbelt.
A number of future generation projects have also
been proposed, among them wind power projects,
large-scale and small-scale hydroelectric power
projects, Fischer-Tropsch plants, coal-fired power
stations, and turbines fired by fuel oil or natural gas
turbines.
Future fuel supplies for the Railbelt are diverse.
Near-term fuel supplies include natural gas from the
Lower Cook Inlet Basin, petroleum fuel supplies
from Fairbanks and Kenai Peninsula refineries, and
coal resources near Healy and Chuitna. Significant
quantities of North Slope natural gas are also
available, although there is no pipeline currently
available to bring this gas to the Alaska Railbelt.
Trucking of LNG from the North Slope is being
investigated as an interim opportunity to use North
Slope natural gas to reduce the cost of energy to the
18 191819
Fairbanks area. If the large-scale Alaska Natural Gas
Pipeline is constructed, then significant quantities of
natural gas will become available in Fairbanks. A
compendium of known reports, RCA orders, and
other data are available on the AEA website at www.
akenergyauthority.org/USOhomepage.html, via
the ‘Resource Documents’ link under the section,
**Existing Railbelt Electric Grid data.
The Susitna Hydro Evaluation
Project
The large-scale Susitna Hydro Project was proposed
in the 1980s to provide hydroelectric power for
the Railbelt. It was evaluated extensively by the
state, but tabled in 1985 when oil prices dropped
precipitously. AEA is currently engaged in the re-
evaluation of the feasibility of this project. Historical
information about the Susitna Hydro Project is
available at http://www.akenergyauthority.org/
SusitnaReports.html.
AEA intends to complete these studies on or before
June 1, 2009. The RIRP for the Railbelt will require
consideration of information from the Susitna Hydro
Evaluation Project.
The Railbelt Electrical Grid
Authority Project
AEA recently completed the Railbelt Electrical Grid
Authority (REGA) Project, which recommends
business structures that will own, operate, maintain,
and control generation and transmission assets
throughout the Railbelt.1 The project considered
several different energy futures for the Alaska
Railbelt, and a regional plan for generation and
transmission was part of this study. The final report
and other resource documents are available online at
http://www.akenergyauthority.org/REGAHomePage.
html.
Regional Integrated Resource Plan (RIRP) for the Railbelt
The goal of the Regional Integrated Resource Plan
for the Railbelt (RIRP) is to minimize future power
supply costs and maintain or improve current levels
of power supply reliability through the development
of a single, comprehensive resource integration plan.
The plan will identify and schedule a combination of
generation and transmission (G&T) capital projects
over a 50-year time horizon.
Healy Clean Coal Project
Railbelt Region
20 212021
Railbelt Region
The plan is intended to provide:
An assessment of loads and demands for the •
Railbelt Electrical Grid for a time horizon of
50 years, including new potential industrial
demands;
Projections for Railbelt electrical capacity •
and energy growth, fuel prices, and resource
options;
An analysis of the range of potential generation •
resources available, including costs, time for
construction, and long-term operating costs;
A schedule for existing generation project •
retirement, new generation construction,
and construction of backbone-redundant
transmission lines that will allow the future
Railbelt Electrical Grid to operate reliably
under open access tariffs, with a postage stamp
rate for electricity and demand for the entire
Railbelt as a whole;
A long-term schedule for developing new fuel •
supplies that will provide for reliable, stably-
priced electrical energy for a 50-year planning
horizon;
A diverse portfolio of power supply that •
includes in appropriate portions renewable
and alternative energy projects and fossil fuel
projects, some of which could be provided by
independent power producers;
A comprehensive list of current and future •
generation, transmission, and electric power
infrastructure projects, each one including a
project description, narrative, location, fuel
source, estimated annual fuel consumption,
power output capacity, and energy output, both
annually and monthly.
For reasonable generation fuel supply configurations,
the RIRP will develop and recommend up to three
feasible resource plan scenarios, complete with
assessment of costs and benefits, and collective and
individual impacts on utility tariffs.
The RIRP will include consideration of the following
energy sources:
Healy Clean Coal Project •
Susitna Hydroelectric Project (including •
phased development)
Chakachamna Hydroelectric Project •
Fire Island Wind Power Project•
Eva Creek Wind Project•
Fairbanks Fischer-Tropsch Project (energy •
source and fuel source)
Chuitna Coal Project (energy source and fuel •
source)
Nenana Basin natural gas•
New gas reserves and exploration in Cook •
Inlet
North Slope natural gas Bullet Line•
LNG trucked from the North Slope to •
Fairbanks
In order to integrate Susitna development with
Railbelt Electrical Grid capacity and energy needs
the RIRP will consider a number of options for
bringing generation sources online, including the
phased development of the Susitna Hydro Electric
Project. The RIRP will also consider input from the
Wind Integration Study currently being conducted
by AEA, and it will include an analysis of the role
of demand side management rules and the ability to
reduce generation resource and energy requirements
if such programs are implemented.
The RIRP will also consider potential contributions
of a merchant power market, where energy needs
could be partially met by tenders from the Railbelt
G&T entity for a portion of the power supply needs.
The RIRP process will analyze a range from 0% to
25% of power needs being supplied by merchant
power suppliers (Independent Power Producers).
20 212021
The RIRP will also consider a scenario where in
10 years all Railbelt G&T assets will be owned,
controlled, maintained, and operated by a single
business entity.
Transmission planning for the RIRP will begin with
the most recent Chugach and GVEA transmission
plans integrated into an overall interconnected grid
development. It will be assumed that transmission
projects will be accomplished cooperatively with the
serving distribution utility whose service area the
transmission line must traverse.
The RIRP will consider future industrial loads
compared to a baseline load growth (demand and
energy requirements) scenario, that assumes Railbelt
development without new, heavy industrial high
power demand. An evaluation of potential future
industrial projects for the Railbelt and of incremental
costs identified for increasing G&T capabilities to
supply industrial loads will be completed. This
will include the Donlin Creek mining projects
and the Pebble Mining project as possible grid
interconnected loads, as well as a third, undefined
but similarly sized industrial project.
22 232223
Energy in Alaska
Introduction
It is difficult to conceive many human activities that
do not in some way depend on affordable, reliable
energy. Whether it is providing fuel for our vehicles,
electricity and heat for our homes, or energy for the
production and transportation of the products we use
daily, almost everything we do depends on a constant
supply of energy. Inexpensive energy has helped
our society create wealth and, as an energy exporting
state, is a cornerstone of our economy.
The United States uses more energy per capita than
any other country in the world, and Alaska as a state
has the highest per capita energy use in the nation
at 1112 Mmbtu per person. This is more than three
times higher than the national average of 333 Mmb-
tus, and is in part due to our climate, with long cold
winters throughout most of the state requiring more
energy for heating homes. However, our geographic
location and oil and gas industry also contribute
significantly. For example, almost 32 million bar-
rels of jet fuel were used in 2006. Jet fuel constitutes
43% of total energy end-use in Alaska, however a
large portion is used for international flights and is
not actually consumed in-state. An additional 484
Mmbtu can be attributed to energy used for oil and
gas production in 2006, and while this was energy
consumed in-state, a vast majority of the product
was shipped out of state as crude oil exports.
Alaska is also home to tremendous untapped or
underutilized energy resources, including some of
the highest concentrations of fossil and renewable
energy resources on earth. In addition to the well-
known oil and natural gas resources on the North
Slope and in Cook Inlet, Alaska’s proven coal re-
serves represent the 4th largest fossil energy resource
in the world. Alaska also has significant undevel-
oped geothermal resources in the Aleutian Island
volcanic arc, abundant untapped hydropower, wind,
and biomass resources, and the majority of the tidal
and wave power potential in the United States.
How Much Energy Does the
Average Alaskan Use?
A long distance sled dog puts out 5 kW,
or 17 Mmbtus, based on a 10,000 kcal/
day diet during a typical day on the
Yukon Quest or Iditarod. This means
that in order to generate the amount of
energy needed by each Alaskan every
day, we need the equivalent effort of 65
Iditarod sled dogs.
22 232223
Energy in Alaska
Data from the United States Energy Information Administration (EIA), based on 2006 values. Total Annual Energy Consumption per Capita
24 252425
Energy in Alaska
Energy diagram produced by the Alaska Center for Energy and Power based on data from ISER, the Alaska Department of Natural Resources, the U.S. Army Corp of Engineers, and the U.S. Energy Information Administration
24 252425
Energy in Alaska
Energy Flow in Alaska
In order to reduce the cost of energy for Alaskans, it
is important to understand how energy is produced
and how it is used. The energy flow diagram on the
opposite page describes the inputs for Alaska energy
consumption, as well as the amount used by the
residential, commercial, industrial, and transporta-
tion sectors. While the values used in this diagram
are based on 2006 data, the only recent significant
change in major energy use patterns is the closing of
the Agrium Fertilizer plant on the Kenai Peninsula,
which has eliminated urea exports out of the state.
Energy flow diagrams are useful for visualizing
where energy comes from and where it goes. They
also demonstrate the inefficiencies associated with
various energy conversion technologies as energy is
‘lost’ between the developed resources (left side of
diagram = 2173 trillion btus), energy exports (top of
the diagram = 1435 trillion btus), energy consumed
(right hand side = 363 trillion btus), and energy
imported (bottom of the diagram = 70 trillion btus).
This is particularly evident in the production of elec-
tricity, where on average 66% of the energy used by
our power plants is dissipated as waste heat.
It is also interesting to note that since 2001 (the last
time ISER completed an energy flow diagram for the
state), residential energy use increased by 18% while
the state population increased by only 7%. This
shows that we are not doing a good job impelement-
ing energy efficiency measures at the level of the
individual home owner, which should be the lowest
cost and consequently the first area addressed when
seeking opportunities for reducing the cost of energy.
Unfortunately, the picture of energy flow for the
entire state of Alaska does little to show what is hap-
pening in any particular region, let alone in a single
community. For example, a large fraction of the
hydropower is produced in southeast Alaska, while
natural gas is a large component of energy supply in
the Anchorage area and Kenai Peninsula, as well as a
few communities on the North Slope. Coal is solely
used in Interior Alaska for both power generation
and heating.
What is 1 trillion btus?
The units used for the energy flow diagram are in trillion btus (British Thermal Units), where 1 btu
is the energy required to raise 1 pound of water 1 degree Fahrenheit. Another way to understand
what a trillion btus represents is that each Alaskan uses nearly 1 million BTUs per day; so 1 trillion
BTUs is about enough energy for a day and a half of energy use for all of Alaska.
Alaska’s total energy consumption in 2006 = 419 trillion btus divided into the following sectos:
• Residential 45 Trillion BTUs
• Commercial 45 Trillion BTUs
• Industrial 26 Trillion BTUs
• Transportation 263 Trillion BTUs
26 272627
Energy in Alaska
26 272627
Using data on the consumption of energy from the
U.S. Energy Information Administration (EIA), we
can track the amount of energy used in Alaska since
statehood. These estimates of consumption from the
EIA also include energy used during oil and gas ex-
traction processes, and jet fuel from international air
travel. The graph below shows the gross consump-
tion of energy in Alaska from 1960 through 2006.
Oil and gas production began in Cook Inlet during
the late 1960s, and by the early 1980s natural gas
was the predominant source of energy used in Alas-
ka. When oil and gas production began on the North
Slope in the late 1970s, natural gas consumption by
industrial users increased dramatically because it
was used to power North Slope operations. All other
fuels, including diesel, motor gasoline, jet fuel, and
coal, have contributed relatively stable shares of total
energy consumption per capita in the state.
Energy in Alaska
Chart created by ISER based on data from the United
Stated Energy Information Administration
Historical Trends in Energy Consumption
28 292829
Putting the Cost of Energy in Context
While energy and its cost to our communities are the
main focuses of this document, the context of energy
within the social framework of Alaskan communi-
ties must also be considered. Energy is ultimately a
tool used to achieve a certain quality of life. Energy
heats homes, runs appliances, provides light, fuels
our vehicles, and powers communication equipment,
among other applications. With this fact in mind it
is clear that state energy planning must look at more
than simply reducing the cost of energy in communi-
ties throughout the state. The planning effort must
also look at the much more complex goal of improv-
ing and sustaining the quality of life across the state
to retain a stable population base, and diversify the
economy.
The statement has often been made that many Alas-
kan rural communities are dying, and this is fre-
quently attributed to the high cost of energy in those
locations. It is easy to document the fact that resi-
dents in most rural communities spend a dispropor-
tionate percentage of their gross income on energy
when compared to the more urban areas of the state.
According to ISER, in 2006 rural residents spent
approximately 9.9% of their total income for energy-
related expenses, an increase from 6.6% in 2000,
and there has almost certainly been a further increase
since 2006.
While this trend is most apparent in rural Alaska,
the rising cost of energy is affecting Alaskans in all
regions of the state. Southeast Alaska and Kodiak,
which largely benefit from stable electric costs from
hydropower, are still being effected by the high cost
of space heating. The Fairbanks area has seen a dra-
matic increase in both space heating and electricity
costs. Even in the Anchorage area average residen-
tial natural gas prices increased 27% in one year,
from 2006 to 2007. While the rising cost of energy
Energy in Alaska
is clear, what is less definitive is whether these rising
costs directly correlate to out-migration from rural to
urban areas, and out of the state completely.
ISER recently completed a study that indicates
migration from rural to urban areas of the state is a
long-term trend caused by a number of factors and
that it has been occurring for generations in some
parts of the state. There has also been a small net
migration out of the state since 2002. Many factors
contribute to this trend, including the overall high
cost of living in Alaska. In general, people migrate
to improve their lives by increasing their access to
opportunities such as better paying jobs, education
for themselves and their children, and a lower cost of
living. It is possible that the current spike in energy
costs may serve as a tipping point, or final straw
stressing rural residents to the point where the deci-
sion to leave is finally made. This decision is also
frequently influenced by other considerations: the
lack of adequate housing, lack of well paying jobs,
and deterioration of social networks due to prior out-
migrations and other social issues.
In fact, an attitudinal survey of 600 Alaska Natives
and 302 non-Natives who had moved from rural to
urban areas of Alaska was conducted by the First
Alaskans Insitute in 2007. It indicated that for 65%
of survey participants, nothing would motivate them
to return to rural Alaska. This is presumably due to
a lack of real or perceived opportunities for them-
selves and their families, which combined with the
high cost of living, reduced the overall attractiveness
of their community of origin.
In the technology screening database developed as
part of this document, the cost-to-benefit analyses of
energy projects in each community are based solely
on the potential for displacing diesel fuel. There is
28 292829
Energy in Alaska
no consideration included for the impact of any single
project on the overall economic health of a commu-
nity, such as the potential for new jobs, businesses, or
industries. However, even though the database does
not quantify those impacts, they exist. Examples in-
clude jobs created by harvesting and processing wood
for a biomass energy project, the development of a
greenhouse business based on low-cost heat from a
geothermal development project and the stabilization
of energy prices through the use of local renewable
resources.
An energy project could also have a positive im-
pact on the social health of a community. Examples
include a more stable employment base, educational
opportunities for local students and the perception that
energy prices are becoming more stable. It is usu-
ally the communities that already have strong leader-
ship and cohesive social structures that will be most
successful in implementing new projects, and those
communities tend to be larger.
For more information:
Fuel Costs, Migration, and Community Viability Colt,
S. and Martin, S., University of Alaska Anchorage, In-
stitute of Social and Economic Research, May 2008.
Engaging community knowledge to measure progress:
Rural development performance measures progress
report Alaska Native Policy Center (September, 2007),
Prepared for the Denali Commission, available at http://
www.firstalaskans.org/documents_fai/A.%20RDPM%20
Report.pdf
30 313031
Crude Oil and Fuel Products
Crude oil is a global commodity, and crude oil prices
are determined by global supply and demand. Apart
from an allowance for tanker transportation costs
and quality differentials, it makes sense to speak of
the world price of oil. Alaskans can do nothing to
impact this price.
There is no price for Alaska crude oil on the New
York Mercantile Exchange (NYMEX) or other com-
modity exchanges. The spot price of Alaska North
Slope (ANS) crude oil is calculated by subtracting
a market differential from the price of West Texas
Intermediate (WTI) quoted on the NYMEX. Four
different assessment services estimate that market
differential and report a daily spot price for ANS.
Fuel oil (also often called diesel) is one of several
products distilled from crude oil and used for heat-
ing fuel or engine fuel. Alaskans use a number of
petroleum products, including motor gasoline, diesel
fuel #1, diesel fuel #2, aviation gasoline, and jet
fuel. Motor gasolines are used in automobiles, small
boats, and snowmachines; there are typically three
grades of gasoline available (mostly in larger com-
munities in Alaska). Diesel fuel #1 is a kerosene
product used for heating fuel. Diesel fuel #2 is a
light gas-oil used for home and commercial heating
and as a motor fuel. Aviation gasoline and jet fuel
are used to fuel aircraft, but a type of jet fuel is also
often used for home heating. According to Crowley
Marine, one of Alaska’s largest fuel distributors,
most of the diesel fuel in more populated areas like
Southcentral Alaska and Fairbanks is ultra low sulfur
diesel. Most villages in Western Alaska still use low
sulfur diesel because they are exempt from the ultra
low sulfur diesel requirement until 2011.
Crude Oil Price Forecast
The U.S. Department of Energy’s Energy Informa-
tion Administration produces long-term price fore-
casts in its Annual Energy Outlook. The most recent
publication was June 2008. In the AEO2008 refer-
ence case, the world oil price path reaches a low of
$57 per barrel in 2016 and then increases to about
$70 in 2030 (2006 dollars).
In the high-price case, with the price of imported
crude oil rising to $119 per barrel (2006 dollars) in
2030, the average price of U.S. motor gasoline in-
creases rapidly to $3.06 per gallon in 2016 and $3.52
per gallon in 2030. In the low-price case, gasoline
prices decline to a low of $1.74 per gallon in 2016,
increase slowly through the early 2020s, and level
off at about $1.84 per gallon through 2030 (see Fig-
ure 1 on the following page).
It is important to note that in the past, EIA forecasts
have not proven to be overly accurate. This is in part
because a large number of factors, some unpredict-
able, can affect crude oil prices on the world market.
Current Crude Oil Price Trends
The EIA also publishes the Short Term Energy
Outlook. The next one will be published in January,
2009. According to the October 2008 report, strong
global demand and low surplus production capacity
contributed to the run-up to record crude oil prices
in July. The current slowdown in economic growth
is contributing to the recent decline in oil demand
and the sharp decline in prices since July. According
to the December 8 report, the current global eco-
nomic slowdown is now projected to be more severe
and longer than in last month’s Outlook, leading to
further reductions of global energy demand and addi-
tional declines in crude oil and other energy prices.
Energy in Alaska
Current Energy Costs and Future Projections
30 313031
Figure 2. Energy Infor-
mation Administration
Short-Term Crude Oil
Price Forecast
Energy in Alaska
$0.00
$20.00
$40.00
$60.00
$80.00
$100.00
$120.00
$140.00
$160.00
Jan-04May-04Sep-04Jan-05May-05Sep-05Jan-06May-06Sep-06Jan-07May-07Sep-07Jan-08May-08Sep-08Jan-09May-09Sep-09Dollars per Barrel(nominal dollars)Figure 1. Energy Infor-
mation Administration
Crude Oil Price Forecast
$0.00
$20.00
$40.00
$60.00
$80.00
$100.00
$120.00
$140.00
19801983198619891992199519982001200420072010201320162019202220252028Dollars per Barrel(2006 dollars)Reference High price Low price
32 333233
The monthly average price of West Texas Interme-
diate (WTI) crude oil has fallen by more than half
between July and November, reflecting the fallout
from the rapid decline in world petroleum demand.
The annual average WTI price is now projected to be
$100 per barrel in 2008 and $51 in 2009. The OPEC
oil cartel met on December 17, 2008 and agreed to
reduce production by 2.2 million barrels per day,
their largest decrease ever, to boost prices. Whether
all producers adhere to the reductions and whether
the reductions stem the price slide or raise prices are
yet to be seen. Figure 2 on the previous page shows
the EIA short-term price forecast.
Energy in Alaska
32 333233
Alaska has a history of energy planning and poli-
cy development dating from statehood in 1959. That
history still holds some relevance today by demon-
strating both successful and less successful energy
program implementation. This section provides a
brief synopsis of past efforts in energy planning and
implementation of those plans, including some of the
lessons learned.
Overview of Rural Energy
Although electricity first appeared in some rural
Alaska villages as a result of military, cannery, min-
ing, or logging operations, its introduction into many
villages began only in the late 1950s as the BIA
installed small generators for lighting its schools.1
This electricity was not available to households, and
few villages had central power supplies before the
mid-1970s. The exceptions were larger rural com-
munities such as Bethel, Nome, Dillingham, and
Kotzebue.
Electrification began to spread more rapidly in
the 1970s, but an estimated 85 rural communities,
most with less than 200 residents, were still without
central power supply systems in 1975. Over the
next 10 years the state provided local communities a
large number of grants for electrification, and by the
mid-1980s most remote communities had centralized
diesel power facilities.
The demand for diesel and other petroleum products
in rural Alaska originated with the introduction of
outboard motors in the 1940s and snowmobiles in
the 1960s. This demand expanded when the BIA and
Alaska State Housing Authority began constructing
conventional western housing in rural communities
in the 1960s. Demand for petroleum products has
continued to expand with the introduction of electric
utilities and other infrastructure such as schools and
water treatment plants.
Today most rural communities generate electricity
with centralized diesel systems. Petroleum fuels
provide the bulk of all energy for electricity, space
heating and transportation. Costs are high due to the
expense of moving fuel to rural Alaska and the small
scale of operations. The high costs have motivated
residents to use less and mean rural energy consump-
tion is lower than in urban areas.
Rural Energy Policy 1979-1985
In 1979, under Governor Jay Hammond, the state
articulated its first energy policy that included the
following principles:
1) Equitable distribution of Alaska’s energy wealth
2) Improved efficiency of production and delivery
3) State planned and funded facility construction
4) Technical assistance in conservation and
management
5) Support for development of locally oriented
energy technologies
6) Public participation and local input in energy
planning decisions
Several conditions at the start of the 1980s heavily
influenced development of this energy policy. This
included the concept that developing cheap power,
primarily through investment in hydropower projects
such as Susitna and Bradley Lake as well as various
projects in Southeast Alaska, would stimulate eco-
nomic development. It was also assumed that state
revenues from the newly producing oil field at
History of Energy Policy in Alaska
1. This historic account through the 1990s is partially extracted from Scott Goldsmith, Short (and Informal) Review of Alaska
Rural Energy Policy, with Particular Reference to Alternative Technologies, prepared for the Denali Commission, May 24, 1999.
34 353435
Prudhoe Bay could provide the money needed to
bankroll these huge investments. The high price of
oil and the expectation that it would continue to rise
also led to the assumption that there would be no
shortage of money. (In 2008 dollars the 1981 price of
crude oil was close to $60 per barrel)
Of particular importance to rural communities were
the following considerations:
• A way to spread the wealth from oil to all
residents would be to make electricity available
and cheap for all Alaska communities, including
those in the bush.
• The high price of crude oil meant that the price of
diesel fuel, the source of most of the energy for
rural Alaska, was oppressively expensive -
particularly in relation to costs in urban areas.
Many urban places were somewhat insulated by
existing hydro facilities or by availability of
natural gas, which was not tied to the price of oil.
• The fear of oil embargoes gave rise to the idea
of self sufficiency of energy supply, which meant
the use of locally available sources of energy
rather than the use of imported diesel.
• The national initiative to develop alternative
energy and implement conservation measures
meant that a lot of money from the federal gov-
ernment was available to consider alternative
means of providing electricity in rural Alaska.
In 1980 the state began spending large amounts of
money collecting data on energy resource avail-
ability and energy use, conducting studies of hydro
potential and investigating the potential for alter-
native energy sources, particularly for the state’s
smaller communities. For example, the 1981 State
Long Term Energy Plan (the first of six such plans)
described the activities of the newly formed Divi-
sion of Energy within the Department of Commerce.
Prominent was a list of the alternative energy sources
(peat, biomass, solar, wind, geothermal, tidal, hydro-
gen, fuel cells, heat pumps, and waste heat recovery)
that the division would be investigating in the hope
that some would be appropriate for rural Alaska.
By the time the 1982 plan was written, the Division
of Energy, together with the Alaska Power Authority,
had spent $12.6 million on geothermal, wind, wood,
peat, single-ground-wire transmission, waste heat,
weatherization, organic rankine generators, and tidal
energy. The state departments of Transportation and
Public Facilities and Environmental Conservation
also conducted alternative energy studies. Hydro-
electric studies fell into their own category.
The progress of those investigations can be traced
through the early 1980s by reference to each suc-
ceeding State Long Term Energy Plan. These docu-
ments reflect the evolution of policy over time,
partially through changes in administrative structure,
and tend to be forward looking. Consequently, they
include only a limited amount of information about
the successes, failures, and lessons learned from
money spent on existing projects, including invest-
ments in alternative energy.
What Did The State Learn About Rural Energy?
After gaining experience with renewable resource
exploration and development in the early 1980s, sev-
eral conclusions were reached. These included:
Resource Assessment:
• Geothermal resources are site specific and ex-
pensive to develop
• Wood is an excellent substitute for fuel oil
• Alaska has vast resources of peat, but technical
expertise and infrastructure for its economical
use are not in place
• Wind resources need more study
• Seasonal fluctuations restrict the viability of
solar power
• Tidal power has limited applicability
History of Energy Policy in Alaska
34 353435
Technology Options:
• Diesel generators will remain the dominant
option due to their appropriate scale, reliability,
and minimal maintenance requirements. Im-
provements in diesel-operating efficiency offer
one promising strategy for addressing the prob-
lem of high energy costs in the bush.
• Small hydro and wind projects may be attractive
on a site-specific basis. (Thirty-four wind
turbines were identified as in operation in 1982)
• Extensive, long-distance intertie systems are
probably not economic.
• Fuel cells may prove promising, but they were
expensive and not commercial. They have some
potential advantages including efficient fuel use,
modular design, (theoretically) simple operation,
excellent load-following capability, and minimal
environmental impact.
The 1983 report, written by Arthur D. Little, found
that “generally it is either technically difficult or
uneconomic to alter the dependence of Bush com-
munities on oil. Many alternatives, while attractive
on the drawing board, experience operation and
maintenance problems which quickly negate any
cost savings. Reliability and simple technology are
therefore essential.”
The energy plans for 1984, 1985, and 1986 have less
to say about alternative energy for rural Alaska for
several reasons. Early enthusiasm for alternative
energy sources to generate electricity was dampened
because these alternatives did not hold up under
investigation either because they were technically
or economically infeasible or they did not work in
operation. Additionally, and more importantly, the
price of oil, and consequently the relative price of
electricity generated by diesel in the bush compared
to alternatives, was falling. This also resulted in the
federal government losing interest in funding alter-
native energy as the national oil crisis dissolved.
According to the 1986 plan, little progress in en-
ergy diversification in the bush had been made since
1979. The only projects that had been implemented
were a number of wind generators. In reference to
those installations, the 1986 plan concluded that
wind power could be both technically and economi-
cally feasible and yet still fail because of improper
management, logistical problems (distance from sup-
pliers and qualified technicians), or lack of an opera-
tions and maintenance network.
1985 Review of Energy Policy
By 1985, concern within the Alaska Legislature on
the direction of the state rural energy program led to
a review and analysis by the legislature’s research
agency (House Research Report 85-C). The review
concluded, among other things, that:
• State loans and grants to rural utilities for
diesel generation systems flourished in the late
1970s and early 1980s.
• Numerous alternative energy demonstration
projects were begun in the late 1970s in hopes
that they would eventually provide replacements
for rural diesel generation.
• The state established a power rate subsidy pro-
gram in 1980 as an interim measure, until a
long-term alternative energy solution could be
found for high rural power costs (a.k.a. the PCE
Program which is still in place today).
• Disenchantment with the general lack of success
of alternative energy projects and the perception
of disorganization led to the demise of the
Division of Energy and Power Development in
1983.
• As results from alternative energy projects and
village reconnaissance studies were made pub-
lic, many people began to realize there were
no realistic alternatives to diesel power genera-
tion in many rural communities.
History of Energy Policy in Alaska
36 373637
The report quoted one state analyst’s perspective
on the reasons for the failure of alternative energy
initiatives. The analyst’s observation was that
bureaucracy is not good at choosing winners and los-
ers. The marketplace is better for determining which
alternatives are most appropriate. Specific factors
the analyst mentioned were: state agencies did not
develop strong management capabilities; they lacked
methods for assessing the technical and financial
feasibility of projects; coordination among state
agencies was often lacking; features of an alternative
technology were often poorly matched with a use-
ful rural application; unrealistic expectations existed
about what an agency or technology could accom-
plish; and too much responsibility was delegated to
contractors while the state often assumed the risk in
the performance of the project. When considering
the current (2008) RE Fund, the system of competi-
tively and rigourously vetted proposals will hopeful-
ly mitigate some of the concerns expressed regarding
the failed programs initiated during the late 1970s
and early 1980s.
Differing opinions on the role of the state in devel-
oping renewable energy projects was also expressed
in the 1985 Review. In particular, Neil Davis of the
University of Alaska Fairbanks felt that the state
had given up too soon on research into alternative
technologies, particularly considering the amount
of money it was spending to develop other energy
resources.
The 1985 Review estimated that from 1975 to 1985
the state had spent $1.7 billion on energy programs.
This included $720 million on urban hydro; $93 mil-
lion for grants and loans for rural electricity genera-
tion and distribution; $27 million in the search for
alternative sources of energy (hydro, geothermal,
coal, and gas); and $24 million in research and pilot
projects related to wind, wood, solar, single-wire-
ground return, biomass, and waste heat recovery.
The Review concluded that since the state’s energy
policy was largely driven by the desire to share the
wealth from oil, much of the money had not been
spent wisely.
Specific criticisms of state energy policy as it was
implemented included:
• Most of the focus had been on electricity, which
is only a small part of the total energy require-
ment of rural Alaska.
• Benefits were distributed inequitably, with the
better organized communities getting the lion’s
share of the benefits in a ‘survival of the fittest’
approach.
• The rural energy problem is not one of high cost,
but rather of low cash income to pay for energy.
1990s Energy Policy
In 1986 the state slipped into a recession because of
declining oil prices and the state started reducing its
budget. Energy policy initiatives were reduced, and
most state effort went into the maintenance of exist-
ing projects and programs. By the early 1990s the
large hydro projects for urban and maritime Alaska
and Railbelt interties had been completed, and the
Power Cost Equalization program for rural utilities
had been established. The Healy Clean Coal Plant
was built in 1998, but with the exception of a brief
test period, it has not been commercially operated.
Attention in urban Alaska, particularly in the Rail-
belt, was centered on the introduction of competition
in electricity sales, construction of interties, and find-
ing alternatives to Cook Inlet natural gas as it began
to decline. State electricity policy for rural Alaska
during this period is reflected in the programs of the
Alaska Energy Authority, Office of Rural Energy
(previously the Division of Energy of the former
Department of Community and Regional Affairs).
History of Energy Policy in Alaska
36 373637
After the large effort that went into wind demonstra-
tion projects in rural Alaska in the early 1980s not
one of them remained in service by the early 1990s.
This was due primarily to immature technology
coupled with a lack of continued maintenance as
federal tax incentives expired. However, a new gen-
eration of improved wind turbine technology began
to be tested in Kotzebue, a relatively large rural hub
village, and Wales, a very small community. Both
communities were using new technology that was
more reliable than what was used in the 1980s, and
more suited to withstand arctic conditions. Today,
Kotzebue is still the leader in wind technology with
the most installed capacity of any community, rural
or urban, in the state. Kotzebue Electric Association
now has twelve 65 kW AOCs, one 100 kW North-
wind 100, and one 65 kW remanufactured Vestas.
These units currently supply about 7% of Kotzebue’s
electrical requirements annually.
2000 to Present
State energy policy early in this decade is reflected in
the 2003 Statewide Energy Issues Overview, a prod-
uct of the Alaska Energy Policy Task Force. The
Task Force was established under House Concurrent
Resolution No. 21 (HCR 21). The sunset date for
the Task Force was April 15, 2004. The Task Force
examined how electricity is generated, transmitted,
and distributed in Alaska in order to meet the State’s
existing and future electrical needs in a safe, reliable,
and efficient manner. It was tasked to develop a
long-term Energy Plan for Alaska that would en-
hance the State’s economic future.
For the Railbelt, the primary projects identified were
a retrofit to the Healy Clean Coal facility, the Emma
Creek (coal) Energy Project near Healy, expansion
of the GVEA North Pole power plant, construction
of the Sutton-Glennallen intertie, reconstruction of
the Anchorage-Kenai intertie, upgrades of military
power facilities, and coal bed methane development.
For the Copper Valley, Kodiak, and Southeast Alas-
ka, the focus was on a piped natural gas or propane
distribution system to Southeast Alaska, and on
interties, including construction of the Swan Lake–
Tyee Lake intertie, the Juneau-Greens Creek-Hoonah
intertie, and the Kake-Petersburg intertie.
As was true of past state energy policy, the Task
Force’s work product was primarily focused on elec-
tricity and on grants and loans for the construction of
new generation and transmission infrastructure.
Concurrent to the Statewide Energy Issues Overview
was the development of the 2004 Rural Energy Plan.
The Plan recommended a combination of utility
management best practices, investments in commer-
cially available, cost-effective production and end-
use technologies, and the fine tuning of the power
cost equalization incentive structure. It estimated
those changes could increase rural energy efficiency
by as much as 20% over the next 15 years, compared
to current practices. The Rural Energy Plan also
suggested investing approximately $65 million for
energy efficiency over five years, an investment the
Plan estimated could produce benefits on the order of
$78 million over fifteen years.
The Plan also provides guidance to AEA and the
Alaska Village Electric Cooperative (AVEC) for
upgrading the following programs: Rural Power
System Upgrades, Bulk Fuel Upgrades, Power Cost
Equalization (PCE), Alternative Energy and Energy
Efficiency, and training. Currently rural Alaska utili-
ties, schools, and residential households account for
about $170 million in annual energy expenditures
(utility payments for fuel and non-fuel costs; school
payments for heating fuel and electricity; residential
household payments for heating fuel and electricity;
PCE payments to utilities).
History of Energy Policy in Alaska
38 393839
In the last couple of years, attention to energy issues
has increased significantly with the dramatic increase
in world oil prices, which has simultaneously raised
the cost of energy use for Alaskans and swelled state
coffers with increased petroleum revenues. After
peaking at over $140 per barrel in July 2008, prices
collapsed to under $50 per barrel by December 2008.
While the price decline provides some relief to urban
and ice-free areas of the state, it provides no such
relief to parts of rural Alaska that were forced to
purchase winter fuel before fall freeze-up. For those
communities there is no potential relief until the
spring of 2009.
In June, 2008, the Cold Climate Housing Research
Center published a report outlining energy efficiency
measures that can be implemented as part of the
State Energy Plan. The report focuses on programs
that address end-use energy consumption in space
heating and the electrical needs of residential and
commercial users, with a focus on the Railbelt. The
recommendations are broken into nine categories.
For a more detailed description of those recommen-
dations, please see the Alaska Energy Efficiency
Program and Policy Recommendations section of
this report or refer to the original document.
Also in 2008, the Alaska Legislature established the
Renewable Energy Grant Program under HB 152,
to be administered by the Alaska Energy Authority.
The Fund established funding for renewable energy
projects over a period of five years at a level of $50
million per year, although each year’s appropriation
is subject to legislative approval. In 2009, lawmak-
ers approved $50 million to fund the program during
the regular legislation session, and added an addi-
tional $50 million during a special session for a total
appropriation of $100 million available during Fiscal
Year 2009.
House Bill 152 also established a seven member
advisory board with a mandate to ‘consult with the
Alaska Energy Authority as it develops eligibility
criteria for grants from a renewable energy grant
fund, develops methodology for determining the
order of projects that may receive grants from that
fund, and adopts regulations identifying criteria to
evaluate the benefit and feasibility of projects seek-
ing legislative support’.
Current Energy Policy and Planning in Alaska
Summary of proposals submitted un-
der the first round of the Alaska Re-
newable Energy Fund (2009). This
does not include round 2 proposals.
38 393839
LABOR
Resource
Technology Technology Teams
Economic Comparison Renewable Energy Fund AEA
Round 1
Least Cost Plan/ IRP Renewable Energy Fund Applied R&D Researchers
Feasibility Round 2 UA ACEP
Champion
Community/ Regional Plan Community
Selection
Champion
Legislative Designers
Vision/ Planning Financial Task Force Legislature
Alternatives Administration
Energy Projects
RFA Proposal Renewable Energy Fund Cost Sharing Philosophy Business
Round 3 Grant Writers
RFA Evaluation Financial Vehicle Evaluators
Development
RFA Selection Evaluators
Advisory Committee
Management
Permitting/ Licensing Contract with Vendors Financing RCA oversight for IPP's Project Team
Grants/ Debt
Craft Labor
Construction Grant Administration Lender Programs PM/CM
Cost Audit State/ Banks State / Bankers
Champion
Operations Community
Cost Audit
Steps to Successful Implementation of Renewable Energy Grant Fund
Current Progress (January, 2009)
Current Energy Policy and Planning in Alaska
40 414041
Alaska Railbelt Electric Grid
Authority (REGA) Study
With recognition of the changing regional conditions
facing the Railbelt, the Alaska Legislature recently
requested a study to assess whether reconfiguring the
electric generation and transmission elements of the
Railbelt region would produce benefits in terms of
cost, efficiency, and reliability. The contractors for
the study evaluated five paths for potential reorga-
nization and tested those paths under four potential
scenarios for meeting electric power demand.
The following descriptions of Organizational Paths 2,
3, 4, and 5 focus on the functional responsibilities of
a new regional entity. In each case, the new regional
entity could be a Joint Action Agency (JAA), genera-
tion and transmission (G&T) Cooperative, or State
Agency/Corporation.
• Path 1 – Status Quo. This path assumes that the
six Railbelt utilities continue to conduct business es-
sentially in the same manner as now (i.e., six separate
utilities with limited coordination and bilateral con-
tracts between them). It does not include the potential
impact of the proposed ML&P/Chugach merger. This
is, in essence, the Base Case and the other Paths are
compared to this Path for each of the evaluation sce-
narios considered.
• Path 2 – form an entity that would be respon-
sible for independent operation of the Grid. On this
Path, a new entity would be formed to independently
operate the Railbelt electric transmission grid. Cur-
rently, the Railbelt utilities have three control centers
(GVEA, Chugach, and ML&P). The operations of
these centers are coordinated (but generation is not
fully economically dispatched on a regional basis)
through the Intertie Operating Committee. This new
entity would not perform regional economic dispatch,
just the independent operation of the Railbelt trans-
mission grid.
• Path 3 – Form an entity that would be respon-
sible for independent operation of the grid and
regional economic dispatch. This Path would ex-
pand coordination in Path 2 through the formation of
an organization that would be responsible for the joint
economic dispatching of all generation facilities in the
Railbelt. This Path, as well as the following two, will
require some additional investment in transmission
transfer capability and supervisory control and data ac-
quisition (SCADA)/telecommunications capabilities.
This Path, and the following two Paths, would also
require the development of operating and cost sharing
agreements to guide how economic dispatching would
occur, and how the related costs and benefits would be
allocated among the six Railbelt utilities.
• Path 4 – Form an entity that would be responsi-
ble for independent operation of the grid, regional
economic dispatch, regional resource planning, and
joint project development. This Path is similar to
Path 3, except the scope of responsibilities of the new
regional entity would be expanded to include region-
ally integrated resource planning and the joint project
development of new generation and transmission as-
sets.
• Path 5 – Form a power pool. This entity would
be responsible for the independent operation of
the transmission grid, regional economic dispatch
and regional resource planning. In that sense, it is
similar to Path 4, except that the individual utilities
would retain the responsibility for the development
of future generation and transmission facilities.
The study also considered four potential electric
portfolio scenarios to test how, under each, the
organizational scenarios would fare. However, the
contracting firm reiterated that it was not tasked to
Current Energy Policy and Planning in Alaska
40 414041
choose a generation scenario, and none of the sce-
narios was based on an in-depth integrated resources
plan (IRP). The study concluded that any of the
paths could be achieved under any of several poten-
tial portfolio scenarios, such as:
• Scenario A – The Large Hydro/Renewables/
DSM/Energy Efficiency Scenario assumes that the
majority of the future regional generation resources
that are added to the region include one or more
large hydroelectric plants (greater than 200 MW),
other renewable resources, and demand side manage-
ment (DSM) and energy efficiency programs.
• Scenario B – The Natural Gas Scenario assumes
that all of the future generation resources will be
natural-gas-fired facilities, continuing the region’s
dependence upon natural gas.
• Scenario C – The Coal Scenario assumes that the
central resource option is the addition of coal plants
to meet the future needs of the region.
• Scenario D – A Mixed Resource Portfolio Sce-
nario assumes that a combination of large hydroelec-
tric, renewables, DSM/energy efficiency programs,
coal and natural gas resources is added over the next
30 years to meet the future needs of the region.
Current Energy Policy and Planning in Alaska
42 434243
Current Energy Policy and Planning in Alaska
State Policy on Criteria for
Project Feasibility
Historically, the primary criteria the state has used
to evalaute an energy project have been the project’s
technical and economic feasibility. These are gener-
ally still the explicit tests of a project.
Technical feasibility means technically feasible given
Alaska’s temperature, wind, and other conditions;
consequently it is inappropriate to adopt a technology
that is technically feasible elsewhere without testing it
here. Economic feasibility is usually based on life-cy-
cle costs over 30 years compared to those of the next
best alternative, usually diesel when analyzing rural
energy projects.
Two other important feasibility criteria for rural
Alaska are location feasibility and human resource
feasibility. Location feasibility is the support infra-
structure in place in the community to deal with the
normal but unanticipated situations that arise over
the life of a facility. Rural Alaska communities have
limited access to an inventory of spare parts or tech-
nical expertise in the event of a breakdown. Human
resource feasibility is the technical, managerial, and
administrative support within the community to take
care of the equipment. The importance of location
feasibility and human resource feasibility has not yet
been documented for rural Alaska electricity projects.
For example, because of today’s improved technology
wind generation would seem to be an ideal choice for
parts of rural Alaska with excellent wind resources.
However, wind generation must be used in conjunc-
tion with either a diesel system and/or batteries that
supply the electricity when the wind is not blowing.
Thus a simple solution rapidly becomes more com-
plicated by the need to integrate technologies and
operate and maintain them together, and location and
human resource feasibility must be considered.
Economic feasibility has consistently been an il-
lusive and controversial topic for Alaska energy
projects. This stems from the focus on electric
power generation and transmission projects and their
tendency to have project economic analyses with
benefit-cost ratios below 1.0 (the benefit-cost ratio is
equal to the net present value of a project divided by
the project’s capital cost). This is because of the low
price of Cook Inlet natural gas, high capital costs,
and limited rate payer market base. The conse-
quence is that projects considered in the 1980s were
shelved when oil prices declined, and resurrected
during oil price spikes.
In rural Alaska, PCE provides rate relief but uninten-
tionally removes some of the market incentives for
local utilities and rate payers to improve the efficien-
cies of their utilities or invest in energy conserva-
tion. Given the small number of rate payers and the
high proportion of utility fixed costs, conservation
measures tend to benefit the state of Alaska through
reduction in PCE payments more than they assist
ratepayers and utilities.
A central challenge for both urban and rural project
economic feasibility analyses is assumptions regard-
ing future crude oil and thus diesel and natural gas
prices. Those prices are at the heart of any com-
parison of the status quo to alternative projects. A
comprehensive review1 was recently completed on a
number of theories of what produced the high price
of oil in the summer of 2008, including commodity
1. Hamilton, James D., Understanding Crude Oil Prices, prepared for National Bureau of Economic Research, NBER Work-
ing Paper No. 14492, November 2008. This highly recommended paper can be found at: http://www.nber.org/papers/w14492
42 434243
Current Energy Policy and Planning in Alaska
price speculation, strong world demand, time de-
lays or geological limitations on increasing produc-
tion, OPEC monopoly pricing, and an increasingly
important contribution of the scarcity rent (growth
in prices due to scarcity in petroleum reserves and
production). The study focused on our inability to
forecast crude oil prices. ISER tested the statistical
behavior of oil prices, related these to the predic-
tions of theory, and looked in detail at key features
of petroleum demand and supply. The study con-
cludes that future oil prices are at best very difficult
to predict. For example, using historic oil prices and
a first quarter 2008 oil price of $115 per barrel, a
prediction of the second quarter 2008 oil price within
a 95% confidence interval ranged from $85 to $156
per barrel. Statistically the same forecast projected
out four years would give a 95% confidence interval
for oil prices being as low as $34 or as high as $391
per barrel.
When investigating the causes of the 2008 price run
up, the three key features identified as unquestion-
ably important are the low price elasticity of demand
for petroleum products, the strong growth in demand
from China, the Middle East, and other newly in-
dustrialized economies, and the failure of global oil
production to increase. These facts explain the ini-
tial strong pressure on prices that may have triggered
commodity speculation in the first place. Specula-
tion could have edged producers like Saudi Arabia
into the discovery that small production declines
could increase current revenues and may be in their
long-run interests as well. And the strong demand
from emerging economies may be initiating a regime
in which scarcity rents, while negligible in 1997,
became perceived as an important permanent factor
in the price of petroleum.
In other words, all of these factors contributed to price
fluctuations and are likely to continue to do so. This
suggests that when screening projects for their poten-
tial to lower the cost of energy, an average price of oil
should be used: over the course of the project’s useful
life it is likely to be both more and less expensive than
its natural gas or diesel alternative. However, scarcity
is likely to keep fossil fuel prices trending upward
without a significant destruction in world demand.
What is certain is that Alaska’s oil production is
declining and thus so are future state revenues.
Competition for state funding will increase and the
opportunity costs of building uneconomic projects
will increase. Similarly, the opportunity costs of not
completing projects with benefit-cost ratios above
1.0, such as those identified in the 2004 Rural Energy
Plan, also increase. Real capital costs for building any
projects are also likely to continue to increase with an
increase in fossil fuel prices, as commodity prices for
construction materials such as steel and concrete trend
upward along with oil and gas prices.
44 454445
Fuel Stabilization
The Alaska Power Association (APA), the trade as-
sociation for Alaskan electric utilities, has hired Steve
Pratt to investigate opportunities to stabilize fuel costs.
With the recent reduction in crude oil prices an oppor-
tunity exists to lock in to these low prices using estab-
lished financial derivative and hedging transactions to
stabilize the net cost of fuel.
The focus of this study was directed to the fuel pur-
chases for electric utilities and school districts as the
larger commercial purchasers of fuel in rural Alaska,
but could be applied to other fuel use sectors. Essen-
tially, the utilities or school district commits to pay an
agreed upon price for fuel delivered at a specific future
date – once committed, that price never fluctuates,
regardless of what happens to market prices for petro-
leum products during the interim.
Because this price insurance allows the user to lock
into a fixed price, it removes the risk of the fuel price
increasing. However, it also removes the cost reduc-
tion if fuel drops to a lower price. This is the trade-off
of fuel insurance, and is a risk determination that each
participant must weigh and evaluate before commit-
ting to this program.
Under the APA proposal the program would be gov-
erned by an oversight board and administered by the
Alaska Power Association. APA would contract for
services of a Program Director/Manager who will
design, budget for, implement and operate the pro-
gram, assist and educate participating organizations,
and provide continually updated information about the
market place risks and opportunities.
This program is designed to provide short-term (roll-
ing 1-3 years) fuel cost certainty for participants. A
three-year look ahead position would provide price
certainty and allow for accurate fuel budgeting. Pre-
Policies with Energy Implications
dictability of fuel costs will allow the utilities and
school districts to tend to the long-term needs of their
customers and constituents rather than dealing with
the immediate financial crises.
Power Cost Equalization
Since 1980, programs (i.e., Power Production Cost
Assistance and Power Cost Assistance) have been
enacted by the legislature to assist citizens of the
state burdened with high power costs. The Power
Cost Equalization program (PCE), which became
effective in October 1984, is the latest effort aimed
at assisting Alaska consumers faced with extreme
electric costs. The PCE program provides economic
assistance to communities and residents in rural ar-
eas of Alaska where, in many instances, the kilowatt
hour charge for electricity can be three to five times
higher than the average kWh rate of 12.83¢ (July
2007) in Anchorage, Fairbanks, or Juneau.
The PCE program was established to assist rural
residents at the same time that state funds were used
to construct major energy projects to assist urban
areas. Most urban and road-connected communities
were benefiting from major state-subsidized energy
projects such as the Four Dam Pool, Bradley Lake,
and the Alaska Intertie. To help spread benefits to
more remote communities, power cost equalization
funds are distributed to eligible utilities, which in
turn reflect the state payment by lowering monthly
bills to individual customers. The program insures
the viability of the local utility and the availability
of central station power. The PCE Endowment Fund
was created and capitalized in FY 2001 with funds
from the Constitutional Budget Reserve and pro-
ceeds from the sale of Four Dam Pool Project. The
fund was further capitalized in FY2007 with general
funds and now totals around $280 million.
44 454445
Policies with Energy Implications
Eligibility and monthly PCE payment amounts are
determined by formula specified in state statute (AS
42.45.110-150). The primary formula variables
include:
1) the number of eligible kWh (up to 500 for
residential and 70 per community resident per
month for community facilities)
2) the maximum per kWh power cost (52.5 cents)
3) the minimum per kWh power cost
(12.83 cents)
4) the percentage of actual costs in excess of the
minimum, but less than the maximum
(95 percent)
A formula is used to determine PCE levels that
represents 95% of a utility’s costs between the floor
(12.83 cents per kWh) and the ceiling (52.5 cents)
If the eligible costs are more than 52.5 cents/ kWh,
then PCE level is 37.69 (52.5 – 12.83 = 39.69 cents
/ kWh x 95% = 37.69 cents). The base may vary on
annual basis per AS 42.45.110(c)(2).
As a result of increases in the number of utilities par-
ticipating, changes to the subsidy formula, rising oil
prices, and increased population, payments under the
program grew from $2.2 million in fiscal year 1981
(FY81) under the power cost assistance program, to
approximately $17.7 million in FY87. In FY88, 102
utilities serving 170 communities and 24,455 cus-
tomers in rural Alaska were eligible to participate.
The average disbursement was $686 per customer.
In the late 1980s, AEA expected the PCE program to
grow at seven percent annually. As a result, the leg-
islature changed the formula by lowering the num-
ber of kWhs eligible per customer from 750 to the
current 500 kWh per month. The minimum per kWh
power rate floor was also raised from 8.5 cents to 12
cents and was to be adjusted as the average cost in
Anchorage, Fairbanks, and Juneau changed. Proba-
bly the most significant change from a fiscal perspec-
tive was removing commercial consumers from par-
ticipation in the program. In addition, a mechanism
was put in place to allocate dollars across customers
if the annual appropriation was insufficient to fully
fund the program.
During FY07, approximately 78,500 Alaskans living
in 183 communities participated in the program at
a cost of $25.4 million. Total utility costs for the
period were $142.7 million, so PCE covered approx-
imately 17.8% of utility costs. Despite the growth in
the number of utilities and customers, nominal pro-
gram costs and average disbursements per customer
were lower in most years since FY87. This shifted
in FY06 and FY07 with rapidly increasing fuel costs.
In real dollars, program costs and per customer dis-
bursements have declined.
The PCE program only pays a portion of approxi-
mately 30% of all kWhs sold by the participating
utilities, and household electricity usage is lower in
PCE communities.
Average kWh Usage per household
PCE communities: 412 kWhr
Anchorage: 725 kWhr
National Average: 750 kWhr
The Regulatory Commission of Alaska determines
the PCE level for each utility based on fuel and
non-fuel expenses such as salaries, insurance, taxes,
interest and other reasonable costs. AEA administers
the PCE fund based on appropriation by the legis-
lature, monthly reports submitted by participating
utilities, and eligibility determination.
46 474647
Wind Power and other Alternative Energy Im-
pacts on PCE Rates
According to AEA, rates are affected only if wind
or alternative energy generation reduces a utility’s
costs. While there are no implicit incentives in PCE
legislation for renewable energy, there is the eco-
nomic incentive to keep a downward pressure on
utility costs and subsequent costs to customer. The
greatest incentive is if customers consume more than
the 500 kWh program maximum or if the utility’s
rate is above or close to the 52.5 cent program maxi-
mum rate.
However, because of the state’s role in funding PCE,
which makes it a de facto ratepayer, the state has an
incentive to invest in alternative energy that lowers
the cost of the PCE program. In addition to direct
financial benefits, alternative energy and energy effi-
ciency displacing diesel fuel reduces the risks of fuel
spills and greenhouse gas emissions.
Wind power will not completely displace diesel,
but it can reduce fuel consumption. For example,
in 2007 Kotzebue reduced diesel consumption by
100,000 gallons, saving the community an estimated
$450,000. Kotzebue now gets 7% of its energy from
wind and hopes to reach 20% in the next several
years. Similarly, the fuel cost per kWh is 25% less
than it would have otherwise been in the five com-
munities served by wind projects in Tooksok Bay
and Kasigluk.
Ultra-Low-Sulfur-Diesel
In response to health concerns related to chemical
and particulate matter in diesel exhaust, the Environ-
mental Protection Agency (EPA) enacted stringent
standards for new diesel engines and fuels1.
EPA rules currently mandate the use of ultra-low
sulfur diesel (ULSD) for on-highway mobile sources
with diesel engines such as automobiles. Similar
rules will take effect for construction equipment, lo-
comotives, boats, and ships, and similar off-highway
equipment in 2010. The rule for stationary engines
applies to new, modified, or reconstructed internal
combustion engines used for power generation and
to industrial pumps starting with model year 2011
Under the EPA rules for Alaska, rural areas can
continue to use uncontrolled-sulfur-content diesel for
all uses and are not required to carry multiple grades
of fuel until 2010. However, as of June 1, 2010 all
areas of Alaska, rural and urban, will begin the tran-
sition to ULSD for highway and non-road, locomo-
tive, and marine diesel fuel.
As noted above, the new EPA USLD rules will not
be implemented for all fuels and for mobile, station-
ary, on- and off-road uses simultaneously. There-
fore, compliance can occur gradually in concert with
the regulation dates. These would require additional
fuel segregation by use, or the shift can be made at
the earliest compliance date for all fuel uses to avoid
additional storage costs. ULSD is usually more
expensive per gallon so there would be higher fuel
costs for the one-time shift to ULSD. To deter-
mine the lowest cost option for rural households, an
analysis was completed2. It found that the cost is
lower to make one rapid transition, because the cost
of segregating relatively small quantities of ULSD
is higher than using ULSD for all uses, even before
the required transition date for that use. However,
the study concluded that even an efficient and rapid
transition to ULSD will incur significant costs for ru-
ral households in the study area, on the order of $190
per household per year or roughly $16 per month.
1. Much of the following text is taken directly from a report published by the Alaska Department of Environmental Conser-
vation. Available at: http://www.dec.state.ak.us/air/anpms/as/ulsd/cost_rpt.pdf
2. Study completed by Northern Economics
Policies with Energy Implications
46 474647
Policies with Energy Implications
Carbon Tax or
Carbon Cap and Trade
According to 2005 Energy Information Administra-
tion (EIA) figures, Alaska consumes 40% more fuel
per capita than any other state and more than three
times the national per-capita average. This is due to
a number of factors including Alaska’s remoteness;
cold climate; scattered communities and population;
limited road system and resulting dependence on air
and ferry travel; status as a major world air cargo
hub; and oil production, transportation and refin-
ing. As a result, measures to decrease greenhouse
gas (GHG) emissions such as cap and trade, carbon
taxes, or other remedies can be expected to impact
Alaska residents and businesses especially hard.
According to the International Panel on Climate
Change, the most important naturally occurring
GHGs associated with this phenomenon are water
vapor (H2O), carbon dioxide (CO2), methane (CH4),
and nitrous oxide (N2O). To address these issues,
in 1999 the U.S. Department of Transportation the
created the Center for Climate Change and Fore-
casting (CCCF), and numerous investigations into
addressing transportations climate change impacts
were initiated. According to the U.S. Environmental
Protection Agency’s Transportation GHG Emis-
sion Report, CO2 accounted for 85% of the radiative
forcing effect of all human-produced GHGs in the
United States in 2003. This proportion is higher for
transportation sources, with CO2 representing about
96% of the sector’s GWP-weighted emissions. In
2003, U.S. transportation sector derived all but 1%
of its energy from fossil fuels, 97% of which was
petroleum.
According to an Alaska Department of Environmen-
tal Conservation (DEC) 2008 report, the principal
source of Alaska’s GHG emissions is residential,
commercial, and industrial (RCI) fuel use, account-
ing for 49% of total state gross GHG emissions in
2005. Nearly 85% of the RCI fuel use emissions are
contributed by the industrial fuel use subcategory,
approximately 42%. Based on estimates of emis-
sions from large facilities, the oil and gas industry
appears to be a key industrial source of greenhouse
gas emissions.
Transportation sources accounted for approximately
37% of the gross GHG emissions in Alaska, with
jet fuel consumption the largest share. Commercial
aviation accounts for 96% of aviaton’s contribution;
international aviation as a sub-division of commer-
cial aviation appears to be a large GHG emission
source and may account for roughly 60% of the
emissions from aviation sources, largely due to the
role of international cargo at the Anchorage Interna-
tional Airport. In 2006, NASA and FAA conducted
a joint workshop with atmospheric and aviation
experts on the impacts of aviation on climate change
and priorities for future research. They concluded
that the effects of aircraft emissions on the current
and projected climate of the planet may be the most
serious long-term environmental issue facing the
aviation industry.
Alaska Department of Environmental Conservation
green housegas emission estimates are given in Mil-
lion Metric Tons of CO2 equivalents (MMtCO2e) in
Table 1 (on the following page). Industry and trans-
portation account for over 80% of Alaska’s estimated
GHG emissions. Eity production and residential and
commercial uses each account for approximately 7%
each.
48 494849
Source: EIA, http://www.eia.doe.gov/oiaf/1605/coefficients.html.
Policies with Energy Implications
48 494849
Source: EIA, http://www.eia.doe.gov/oiaf/1605/coefficients.html.
Policies with Energy Implications
50 515051
Policies with Energy Implications
In order to reduce greenhouse gas emissions, a
national carbon tax or a carbon cap and trade pro-
gram may be created in the near future. Both systems
would effectively increase the cost of using fossil
fuels, although the cost of all fossil fuels will not
increase by the same amount. The tax will be on the
carbon dioxide released when the fossil fuel is used.
As a result, low-carbon-intensive fuels like natural
gas will be taxed about half as much as coal. (Table
2 on the previous page shows the carbon content of
fossil fuels)
A carbon tax or a cap and trade system would in-
crease the cost of using fossil fuel energy, increasing
the economic benefits of renewable energy projects.
The actual increase of the benefits of renewable en-
ergy projects is dependent on the size of the carbon
tax and the type of fossil fuel replaced.
Net Metering
Net metering is a policy whereby consumers who
own small renewable energy facilities such as wind
or solar power systems can use their own generation
to offset their consumption over a billing period.
They do this by allowing their electric meters to turn
backwards when they generate electricity in excess
of their demand. This offset means that customers
receive retail prices for the excess electricity they
generate. Net metering is currently offered in 42
states plus the District of Columbia. Net metering is
being considered by the RCA (Docket R-06-5), and
by the Alaska Legislature under (HB 288). Concerns
have been raised in Alaska regarding the burden
that a mandated net metering program could create
for small utilities with high fixed costs and a small
customer base.
As an alternative to net metering, Golden Valley
Electric Association instituted the Sustainable Natu-
ral Alternative Power (SNAP) program in 2004,
a voluntary program that links renewable energy pro-
ducers with other individuals on the GVEA grid who
are willing to pay a premium for that power. SNAP
producers pay to install their own renewable power
systems and feed that power onto the grid. They
are paid a premium for this ‘green’ power by vol-
untary contributions from other GVEA ratepayers.
At the end of 2008, there were 27 renewable energy
producers and 574 members contributing a total of
$36,120 annually.
Land Use
Land use policy in Alaska is primarily addressed at
the local government level and, among other things,
can dictate the placement of buildings and homes
within a community. Indentifying energy efficient
land use policy can be one way to reduce the energy
needs of a community. For example, in urban com-
munities, land use policy can promote sprawl by lack
of zoning or zoning for single use and low density
neighborhoods. This sprawl creates increased de-
pendency on automobile use and results in increased
energy use.
In rural Alaska, land use policy can be used to
encourage building placement that increases energy
efficiency by increasing the potential for and benefits
of cogeneration. Building a community facility near
a cogeneration power plant enables use of waste
heat and reduces the energy lost during the transmis-
sion of the heat, whether through hot water lines or
through a direct heating loop.
Transportation
The transportation industry is a relatively large
sector of the Alaska economy. Tourism and interna-
tional air cargo are both fuel intensive industries that
are part of the transportation sector. Also, the cost of
50 515051
Policies with Energy Implications
transportation increases the cost of living in Alaska
because of the state’s remoteness. Alaska is remote
from global markets and population centers, and
communities and industries are remote from markets
and population centers within the state, thus requir-
ing greater use of air transportation. This remote-
ness increases the cost of getting goods and people
to and from the state, making the Alaska economy
especially susceptible to transportation energy price
increases.
Alaska’s transportation policy can affect energy use
by promoting either energy substitutes or energy
compliments. Energy substitutes would decrease
the demand for transportation energy. For example,
state transportation policy can be used to reduce the
amount of fuel used for transportation by promoting
public transportation systems. An example would
be a commuter rail line or increased bus service
between the Valley and Anchorage that would allow
commuters to switch from personal automobiles to
far less fuel intense public transport.
Roads, railroads and airports are all energy compli-
ments but it is likely that energy prices and use drive
demand for energy infrastructure, not vice versa.
It is important understand the role energy plays in
transportation and to pursue transportation policy
that is responsive to changes in energy markets.
According to John Horsley, Executive Director,
American Association of State Highway and Trans-
portation Officials (AASHTO), transportation pro-
duces 33% of CO2 emissions with highways produc-
ing 72% of transportation’s share. Transportation
will need to do its part to address climate change.
Some of this fuel use reduction will occur through
fleet fuel efficiency improvements. Federal legisla-
tion passed in 2007 called for increased Corporate
Average Fuel Economy (CAFE) mandate of 35 miles
per gallon (mpg) by 2020. AASHTO’s Vision Report
calls for doubling the CAFE standard by 2020 to 42
mpg. Europe today averages 40 mpg versus the US
at 21 mpg.
In addition to increasing fuel efficiency, the policy
goal is to reduce the vehicle miles traveled (VMT)
growth rate by 50% (instead of 2.2% growth annu-
ally, reduce VMT growth to 1% annually). A policy
combining 35 mpg fuel efficiency and 50% cut in
VMT results in highway transportation emissions
below current levels by 2030. To reduce VMT, the
goal nationally is to double transit ridership from 10
billion to 20 billion by 2030. The highway fund-
ing reauthorization is expected to increase transit
funding 70% from $10.3 billion to $17.3 billion
by 2015. In addition to increasing transit use, fed-
eral policy will be directed at increasing walking
and biking trips, increasing telecommuting/on-line
shopping, and adopting supportive land use policies
that accommodate one-third of new development
through infill of central cities and older suburbs. Mr.
Horsley concludes that one third of transportation’s
contribution to emission reductions will be shaped
by reauthorization investments and policies and two
thirds will come from federal, state, and local energy
policies, local land use policies, the effect of higher
fuel prices, and new technologies.
The Low Income Home
Energy Assistance Program
The Low Income Home Energy Assistance Program
(LIHEAP) is designed to help low income house-
holds offset the high cost of home heating. The
State’s LIHEAP block grant is administered by the
Department of Health and Social Services (DHSS)
and the Division of Public Assistance.
52 535253
Prior to the spring of 2008, Alaska operated the
federally funded LIHEAP program, which capped
income at 150% of the poverty income guidelines.
In May of 2008, the State Legislature created the
Alaska Heating Assistance Program (AKHAP) for
households with income between 150% and 225% of
the poverty income guidelines.
In 2008 Alaska provided 13,620 households with
LIHEAP financial assistance. The average heating
assistance benefit was $756 in 2005. Alaska will
receive $23.6 million in Federal LIHEAP funding in
FY2009, up from $16.9 the previous year (Campaign
for Home Energy Assistance, http://www.liheap.org/
liheap%20fact%20sheet/AK/liheap-AK.pdf).
AHFC Weatherization
Program
For years the Alaska Housing and Finance Corpora-
tion (AHFC) has provided free weatherization as-
sistance to low income households. Households that
meet the income requirements are assessed to deter-
mine the weatherization measures to be performed
on the home. The weatherization improvements are
done by one of 15 state designated housing authori-
ties.
In 2008 the State Legislature approved $200 million
for the weatherization program, and the program’s
income requirements were expanded from 60% of
median income to 100% of median income. Prior-
ity is given to the elderly, the disabled, young chil-
dren, and families under 60% of median income. A
household may not participate in both the AHFC
weatherization program and energy rebate program
(described in the next section). The tremendous
popularity of this program has led to bottlenecks and
waiting lists because of a scarcity of trained contrac-
tors to do the work, as well as a shortage of trained
energy raters.
AHFC Home Energy
Rebate Program
The AHFC home energy rebate program assists
homeowners in making the best energy-efficiency
improvements for their home. The Home Energy
Rebate program has no income requirements and fo-
cuses on owner-occupied homes. Homeowners pay
for certain energy-efficiency improvements and are
rebated a portion of the cost for doing so.
To participate, a homeowner pays an energy rater to
make an initial assessment of the home. The hom-
eowner completes work on measures chosen from
the Improvement Options Report and then requests
a follow-up energy assessment. AHFC will issue a
rebate for some of the costs of improvement. The
amount of the rebate is determined by the points
and step increase in the home’s energy rating, not to
exceed actual expenditures supported by receipts.
These rebates are for up to $10,000. The program
may also supply a $7,500 rebate on qualified, new 5
Star Plus homes.
Particulate Matter Regulation
According to the Environmental Protection Agency
(EPA), Particulate Matter (PM) is a “mixture of ex-
tremely small particles and liquid droplets” that can
cause health problems when inhaled. Fine Particu-
late Matter (PM2.5) is less than 2.5 micrometers in
diameter. PM2.5 is a product of combustion, primar-
ily caused by burning fuels. Examples of PM2.5
sources include power plants, vehicles,
wood-burning stoves, and wildland fires. The EPA
recently increased the stringency of the PM2.5 stan-
Policies with Energy Implications
52 535253
Policies with Energy Implications
dard by lowering the previous 24-hour standard of
65 µg/m3 to 35 µg/m3.
The U.S. Environmental Protection Agency recent-
ly announced that it intends to classify Fairbanks
and Juneau as nonattainment areas. This clas-
sification will force local officials to respond by
restricting the use of wood-burning stoves. Winter
inversions often leave the air stagnant, allowing
PM2.5 to accumulate in the air. If the level of
PM2.5 reaches a certain point, the community will
temporarily restrict the use of all woodstoves ex-
cept those that burn wood pellets. The new PM2.5
regulations could significantly increase the cost
of heating in these communities because residents
will not be able to rely on low-cost wood stoves.
Renewable Energy Fund
In 2008 the Alaska Legislature established a Re-
newable Energy Grant Fund through the passage
of HB 152. The legislation authorized the Alaska
Energy Authority to distribute renewable energy
grants and set out procedures to be followed to
award those grants. The bill also established a
state heating assistance program in addition to the
federal heating assistance program, and it estab-
lished an Alaska Renewable Energy Task Force of
legislators.
HB 152 promised AEA $50 million annually
for the next five years to fund renewable energy
projects. An additional $50 million was authorized
during a legislative special session for FY09.
Renewable Energy Fund grants are available to
electric utilities, independent power producers,
governments and government agencies (eg, tribal
councils). AEA may recommend grants for fea-
sibility studies, reconnaissance studies, energy
resource monitoring, and/or work related to the de-
sign and construction of an eligible project. Grants
will be awarded based the following criteria:
1. Cost of energy per resident in the affected
project area relative to other areas
2. The type and amount of matching funds and
other resources an applicant will commit to
the project
3. A statewide balance of grant funds to assure
funding is made available for feasible projects
in all regions of the State
4. Project feasibility (technical and economic)
5. Project readiness
6. Success in previous phases of project
development
7. Economic benefit to the Alaska public
8. Other Alaska public benefit (such as ability to
use technology in other parts of Alaska)
9. Sustainability
10. Local Support
Energy Research Fund
At this time, no state funding is available for energy
research in Alaska. The Alaska Energy Authority
currently has no mandate or capability to engage
in energy research. The Renewable Energy Fund
legislation does not allow for funding of any emerg-
ing technologies, and funding is explicitly limited to
projects utilizing proven, existing technologies. This
limits Alaska’s ability to utilize emerging technolo-
gies and become a leader in energy development. It
is particularly crippling in a state with very different
conditions than are found elsewhere in the U.S. in
terms of environment, population density, and the
isolated nature of the transmission system.
Applied research is designed to solve existing prob-
lems, to develop recommendations that can be used
to improve practices, and to help decision and policy
54 555455
makers toward effective choices by defining a
clear path forward.
According to the National Science Foundation,
Alaska currently ranks 46th among states in terms
of funding spent on R&D, and it has no significant
mechanism for funding energy research at the
state, regional, or local level. The creation of an
Alaskan R&D or emerging technology fund would
put the state in a better position to receive the
increase in federal R&D dollars for clean energy
development that President-elect Obama is now
proposing.
References
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Summary Report of Improvements to the Alaska
Greenhouse Gas Emission Inventory, January 2008.
Alaska Department on Natural Resources, Oil and Gas
Divisions. 2007 Annual Report. DNR 2007 Annual
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publications/annual/report.htm
Alaska Department of Revenue, Tax Division, Rev-
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Alaska Energy Authority, 2008. Request for Grant Ap-
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ficients.html
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56 575657
Given the high cost of fuels and energy across
much of Alaska, many new projects to develop
local resources will be starting across the state over
the coming years. Each of these projects will have
its own set of needs and development plans. This
information will help agencies determine what
authorizations are required for a project to progress
from conception through construction to operational
phase. The specific permits necessary will depend
on many variables, and may come from a wide
assortment of agencies. Land owners and regulating
agencies have the authority to determine what is
needed. The developer has the responsibility to
work with them all to aquire the proper permits for
the project.
Each project will need site control, which is
achieved by specific authorization from the land
owner. Projects can be on private, native, municipal,
state, or federal lands. Often they cross land
ownership boundaries necessitating permission from
more than one land owner. Hydrokinetic projects
in rivers or in the ocean also require permission
from the agency that owns the submerged land. In
addition, navigation or other access issues need
to be addressed. In Alaska, subsurface owners
rights predominate over the surface owner’s rights,
but impacts on the surface owner must still be
addressed. There may be different authorizations
for different phases of the life of the project. These
authorizations often come in the form of permits,
leases, or rights of way with stipulations that govern
use.
In addition to site control, the use and activities that
are part of the project often require the developer
to go through other regulatory processes and obtain
further authorizations. These other regulatory
requirements may control the use of the land and
resources or even the sale of power. There may be
requirements for the actual physical construction
and operations or for management of the camp for
the construction crew. Activities during the resource
and environmental assessment stage may require
different authorizations. Sometimes permitting
requirements for larger projects can be coordinated,
but often each agency must follow its own regulatory
process. Some authorizations are dependent on
others, such as the overall umbrella requirement
to first obtain a consistency review under the
Alaska Coastal Management Program (when the
project is related in the coastal district boundaries).
Authorizations for experimental projects are short
term in nature and will not carry any preference
right, implied or otherwise, toward a long term
authorization.
Specific regulations govern how an application
and subsequent authorization is treated by the
nature of the applicant. For instance, with some
authorizations, a licensed public utility may have
different process and fee requirements than an
independent power producer. This is important to
understand as it may have longer term implications
in the event that the project developer intends to
transfer ownership or operation in the future. If the
proposed transferee does not qualify under the same
terms and conditions of the original authorization, a
totally new authorization process would be required.
Some authorization processes are driven by strict
timelines. A majority of the authorizations will take
some time to obtain. It is essential that the project
developer understand the probable timelines to
obtain the necessary authorizations. Entities seeking
permits are encouraged to start early by working
with the authorizing agencies to reduce the chance of
project delays at critical junctures. Many agencies
are under large workloads, and it is rare that the
agencies can drop the permits they are working on
in order to expedite an individual request. Energy
projects funded through grants do not guarantee that
Permitting
56 575657
a project can get all authorizations. Grants do not set
agency authorization-processing timelines.
The project developer may need to gather data or
conduct studies that will be used to determine the
appropriate stipulations on given authorizations.
Some of the federal processes require environmental
or environmental impact assessments which can
take a significant amount of time. Most state and
federal regulatory processes require a public process
with a chance for the public to provide input into
the decision-making process. Most public agencies
also have some form of option for affected parties
to appeal decisions. Agencies try to make sound
decisions that will withstand challenge and thus not
delay projects. It is in the project developer’s best
interest to cooperate fully in providing required
information to the respective agencies. Developers
need to schedule these resource assessments and
review periods into their proposed timelines.
Because of the complexity of the permitting
requirements, and the diversity of resource
development projects, it is best to start working
with the agencies early in order to understand the
potential authorizations that are needed and the
appropriate timing for applications to be submitted.
Professional permitting and project consultants will
contract for this type of work and help a developer
acquire the necessary approvals. Most agencies have
a specific contact who can explain what is needed or
provide contacts with the appropriate entities.
The following is a list of some of the agencies
that should be contacted to determine issues of
land ownership or required authorizations. Many
agencies offer a centralized public service center,
the best initial contact point. Note that this does not
include a list of all the potential land owners, nor
does it break down each agency that may require
more than one type of authorization.
Alaska Department of Environmental
Conservation
Alaska Department of Fish and Game
Alaska Department of Natural Resources
Regulatory Commission of Alaska
U.S. Army Corps of Engineers
Bureau of Land Management
U.S. Coast Guard
U.S. Environmental Protection Agency
Federal Aviation Administration
Federal Energy Regulatory Commission
U.S. Forest Service
U.S. Fish and Wildlife Service
Whether project developers are operating in the
Coastal Zone or not, two websites provided by the
Division of Coastal and Ocean Management under
the Department of Natural Resources provide helpful
information and diagnostic tools for determining when
various agencies should be contacted.
Additional Resources
Coastal Project Questionnaire: http://dnr.alaska.gov/
coastal/acmp/Projects/pcpq3a.html
Agency contacts in regions of the state: http://dnr.
alaska.gov/coastal/acmp/Contacts/PRCregcont.html
Permitting
58 595859
Energy Storage
TECHNOLOGY SNAPSHOT: DIESEL EFFICIENCY
Resource Distribution Most rural Alaskan communities generate the major
portion of their power with fuel oil
Number of communities impacted Nearly 180, consuming more than 2,500 MWh of
electrical energy annually
Technology Readiness Commercial
Environmental Impact Reduction of fuel use and related emissions
Economic Status
Typical payback of 3 to 5 years depending on
technology used and specific application per
community
Diesel Efficiency and Heat Recovery
AEA Program Manager: Lenny Landis (771-3068)
New Powerhouse
in Tuluksak.
New generators in
Tuluksak.
58 595859
Rural Alaska relies heavily on diesel engine
technology as the main energy source for producing
electricity. This reliance is not likely to change
significantly in the immediate future. Hybrid
and standby diesel generation is still required
to augment almost all rural renewable electrical
energy sources. In addition, the development of
renewable and alternative energy sources for the
production of electricity is typically a multi-year
project, while diesel
efficiency can usually
be implemented in a
much shorter time.
For this reason, diesel
efficiency is one of
the most cost-effective
strategies with the
shortest payback.
Diesel efficiency can
almost immediately
reduce the energy
cost burden on
rural, grid-isolated,
Alaskan communities
while renewable and
alternative energy
resources are developed.
Recent advances in diesel engine efficiency,
automated generator controls, heat recovery,
and continuous operations and maintenance
techniques have made possible diesel fuel efficiency
improvements of more than 50% in old, sometimes
obsolete, rural powerhouses.
Over the last six years, deployment of modern
diesel technology in rural community diesel
powerhouses has been documented to increase the
usable electrical energy generated from a gallon of
diesel fuel by 20% - 30%. Installation of monitored
heat recovery systems from both traditional water
jacket systems and new exhaust stack heat recovery
systems can increase the fuel conversion efficiency
of diesel powerhouses by another 20% - 35%.
The deployment
of automatic,
load sensing
switchgear with
data acquisition and
remote monitoring
capabilities has
lowered the
maintenance and
operational costs
in powerhouses
recently constructed
by the Alaska
Energy Authority
(AEA) in rural
villages.
The Alaska Village Electric Cooperative (AVEC),
with 53 member villages, has also reported similar
increases in fuel efficiency as documented by
communities that have taken advantage of AEA’s
Energy Cost Reduction grant program.
The following charts illustrate general estimates of
the typical distribution of the fuel energy used in
diesel electric power generation.
Introduction
60 616061
Technology Overview of Generator Fuel Efficiency and Heat Recovery
New Technology
Old Technology
80% Wasted
20% Utilized
63% Utilized
37% Wasted
60 616061
Increases in diesel generation efficiency can generally be found in three broad areas.
Increasing the amount of electricity (kW) produced per gallon of diesel consumed by the generator 1.
engine
Recovering heat from the engine water jacket cooling system and, if applicable, from the engine exhaust 2.
stack
Minimizing losses in the electrical distribution system3.
A more detailed breakdown with categories, related technologies, and potential gains is shown in the
following graphic.
Technology Overview of Generator Fuel Efficiency and Heat Recovery
62 636263
Tighter control over the fuel systems provided by electronic fuel injection, electronic speed governors, and
electronic engine controllers has boosted the usable kWh per gallon of diesel. Efficiency improvements of
10% - 15% over the older mechanically governed engines have been achieved in over 25 rural powerhouses
upgraded by AEA.
Screen images of diesel
engine controls.
Diesel Engine Controls
Latest Diesel Engine and Powerhouse Control Technologies
62 636263
automatic dispatch of the most efficient generator or
combination of generators to closely match changes
in the village load demand throughout the day have
allowed efficiency increases of an additional
10% - 20%.
These next two graphics are computer screen captures
of the Supervisory Control And Data Acquisition
(SCADA) interface utilized in modern powerhouses.
Notice that this one is a diesel-hydro hybrid.
Programmable switchgear controls facilitate more
efficient coordination with renewable and alternative
energy sources of electrical power like diesel/hydro
and diesel/wind hybrid power systems.
Additional benefits of new switchgear
Automatic recovery from power outages•
Automatic dispatch of available alternative •
energy sources
Data acquisition, historical data downloads •
for utility planning, energy engineering and
research
Remote monitoring for faster, more efficient •
troubleshooting
Recently, the reliability and automation of a
new diesel/hydro hybrid system was put to a
real-world test when an anomaly occurred in a
community’s electrical distribution system. The
hydro was supplying the full community load when
a momentary distribution fault tripped the hydro
off line in the early morning. Within seconds the
powerhouse controls started the diesel generators
and restored power to the town. Within minutes
the controls restarted the hydro, paralleled it with
the most efficient diesel generator, then cooled
and shutdown the diesel generator. Without the
intervention of an operator and in a short period
of time, the community was fully back on clean,
efficient hydro.
Heat Recovery Technologies
A significant portion of fuel oil used in rural
Alaska is for space heating. Recovery of wasted
heat from diesel generation has great economic
potential for remote Alaskan communities. Typical
applications for heat recovery are environmental
space heat for community buildings and augmented
electric power generation. The most efficient use of
waste heat is to use it directly as heat. This avoids
efficiency losses that occur when heat is transformed
to another kind of energy. The recovered heat can
be used for space heating, domestic hot water, or
for tempering municipal water supplies to prevent
freezing and facilitate treatment. The efficiency
of recovering waste heat for augmenting electrical
power production is lower than that for heating;
however, it can be attractive and economical in some
places since electrical power is needed year round
as opposed to space heating, which is usually only
needed during the cold seasons.
Heat recovery may use one or all of the diesel
generator’s waste heat sources including the exhaust
stack, jacket water, and charge air. Waste heat
recovery using jacket water heat and/or charge air
heat directly for heating is a mature and proven
technology. Over a quarter of rural village diesel
generators have already been equipped with jacket
water heat recovery systems. Charge air heat has
been recovered for heating in a select number of
communities.
Water Jacket Heat Recovery
For rural Alaska, the technologies most applicable
are systems that use recovered heat directly, as
the end product. Modern high-efficiency heat
exchangers, super-insulated heat piping, high-
efficiency electric pumps, modern electronic BTU
meters, and variable speed radiator fan motor
controllers maximize the utilization of heat available
from the diesel engines. Waste heat recovery for
space heating is a common, proven design. The
associated design and maintenance procedures are
well understood in the Alaskan power industry. For
this reason, water jacket heat recovery for space
heating is considered a mature technology in Alaska.
Powerhouse Switchgear Controls
Advances in powerhouse switchgear control for the
64 656465
Exhaust Stack Heat Recovery
Heat recovery from the diesel engine exhaust stack
is a proven and cost-effective technology in larger
power plants. Recent technological improvements
have made exhaust stack heat recovery feasible
and economical in midsize engines, which are
most representative of the engines in rural Alaska.
These advances in exhaust stack heat recovery have
boosted recovered heat and reduced the hazards and
maintenance burdens typical of the older systems.
At this time, only one production diesel generator in
Alaska, apart from the University of Alaska diesel
test bed, is known to employ an exhaust stack heat
recovery system for heating applications. This is
a relatively large 5 MW power plant at a mining
site. No heat recovery performance data for that
installation was readily available for this publication.
The reasons why diesel stack exhaust heat recovery
is not considered more often in rural Alaska include
the high capital and maintenance costs, as well as the
potential for excessive exhaust system corrosion and
soot build up. The risk of the heat recovery system
causing generator failure and higher maintenance
costs often outweighs the value of recovered energy.
Advances in exhaust heat exchanger design and
operational strategies have reduced the probability of
corrosion and soot problems. The coming mandate
for the use of low sulfur fuel oils will also reduce
corrosion risk.
Recently, the University of Alaska Center for Energy
and Power conducted an experimental study to
investigate the economic effect and feasibility of
employing exhaust heat recovery techniques on a
midsized diesel engine. Based on the study results,
the diesel exhaust heat recovery strategy appeared to
cause no critical problems to engine performance nor
to increased maintenance frequency.
The payback time for this exhaust heat recovery
system is estimated to be less than three years for
a fuel price of about $3 per gallon, with engine
operation of eight hours per day. Study results
and performance of existing exhaust heat recovery
systems on large diesel engines in industrial level
applications show exhaust heat for heating to be a
mature and proven technology, ready for adoption.
Performance and economic results will differ for
each project. Influential factors, including power
plant load pattern, heating load characteristics,
and existing heating system infrastructures will
also vary accordingly. For this reason, it may
be necessary to analyze the specific generating
system to be retrofitted, before the installation of an
exhaust heat recovery system. As a rule of thumb
for rural Alaska, before exhaust stack heat recovery
is considered, it is recommended that the diesel
generator capacitity exceed 400 kW and that the
community have a year-round population above 700
residents.
Heat to Electricity Technology
There are promising methods for waste heat to
electric power conversion: organic Rankine cycle
(ORC), Kalina cycle, exhaust gas turbine, and direct
thermoelectric conversion systems. The organic
Rankine cycle and Kalina cycle systems may be
preferred because of their availability, ease of
installation, and efficiency. For years, engine heat
recovery for power generation has been applied to
very large power plants and marine engines. Many
heat recovery power systems have capacities over a
megawatt, including combustion engines powered by
natural gas, coal, and petroleum-based fuels.
The performance of the waste power system is
relatively sensitive to exhaust temperature and the
energy content of the heat sources. For midsized
engines, technologies for converting waste heat
to electrical power are still in the research and
development stage and not yet considered mature
technologies. Their feasibility is highly dependent
on the fuel cost. Current research and development
groups include engine manufacturers and power
plant companies. The University of Alaska
Center for Energy and Power is also assessing the
performance of heat-to-electricity technologies from
several manufacturers.
Most existing ORC systems are used in geothermal
Heat Recovery Technologies
64 656465
applications and range in size from about 250 kW
to multi-MW. ORC systems for engine waste heat
applications have similar capacity. Commercially
tested Kalina cycle systems are not common, with
only a few in production and almost all of the units
in multi-MW capacity. Successful Kalina cycle
systems are much larger than a megawatt and would
not necessarily scale down to be effective systems
on the midsized diesel engines employed in rural
Alaska. For many years, small scale, organic
Rankine cycle systems were used successfully
in some Trans Alaska Pipeline systems. The
manufacturer presently produces only large scale
systems. Kalina cycle systems based on ammonia
are rare, and commercially available options are not
of a scale suitable for Alaskan village generators.
The performance of the thermal-to-power conversion
systems is sensitive to the properties of heat source,
heat sink, working fluid, and energy intensity. For
example, resources with similar power capacities may
require different systems in order to obtain optimum
system performance. Therefore, each prospective
installation site will require an individual analysis to
insure appropriate operation.
Distribution System Efficiency
Upgrades
How the electrical energy is delivered to the load
or customer can have a significant impact on the
efficiency of the system. The use of newer, more
efficient transformers and more flexible power
distribution systems that allow easier balancing of the
village loads can increase the efficiency of delivered
power 3% - 6%.
Electrical loads on the distribution system must be
reasonably balanced to obtain the greatest efficiency
from the generation system. Loads shift seasonally
and annually as new loads and buildings are added
or removed. The generation system must be
monitored and the distribution system loads adjusted
appropriately. Distribution systems may need
upgrading if appropriate load shifting adjustments
cannot be made.
The voltage of the distribution system can have a
significant effect on line losses. An older system
design utilizing 208, 480, and 4160 voltages
becomes inefficient when the system is expanded
to accommodate a growing community’s new
subdivisions and projects. Newer transformers more
efficiently convert between voltages. Power factor can
be a significant issue in rural communities where long
underground runs have small loads.
Fuel Boosters
Fuel boosters have not yet been proven under
the harsh, varying conditions in remote Alaskan
powerhouses. The Alaska Energy Authority suggests
test bed studies through the University of Alaska
Center for Energy and Power and pilot testing in rural
powerhouses.
Operations and Maintenance
The ability a community has and the methods it
uses to maintain and operate its powerhouse have
a significant impact on efficiency. Keeping diesel
generation systems operational and maintained has
a direct influence on the energy produced for each
gallon of diesel fuel consumed. Operator training,
spare parts availability, automatic system monitoring,
data trending, and data analysis, along with prompt
maintenance and repair are key factors in keeping
efficiency and performance high.
The previous charts document variations in diesel
efficiency due to operation and maintenance practices.
Village 1 received a new powerhouse upgrade
in 2000. Efficiency immediately improved from
previous years. Notice the decline in the years
directly after 2000. This is due to the fact that
the utility was unable to consistently operate and
maintain the powerhouse. In 2005, maintenance
assistance was provided via the Circuit Rider
program. Efficiency improved and then again
declined when the proper operations and
maintenance were not continued.
Other Diesel Efficiency Technologies
66 676667
Low Level Maintenance (timely repairs,
general engine decline, system de-
tuned).
Inconsistent Maintenance (sporadic
repairs, generators out of service for
long periods).
66 676667
These charts presents the information from a different
perspective. Notice the projected loss in savings and
efficiency if powerhouse upgrades are not continued and
routine maintenance via Circuit Rider is not performed.
68 696869
This chart presents powerhouse efficiency as a
percentage of improvement. The new Rural Power
System Upgrade project improved efficiency by
>26%. Over time, the powerhouse lost nearly 10%
of the improved efficiency from lack of proper
routine maintenance.
Improvement to the operation of existing diesel
systems is a short-term opportunity for almost every
rural community. As such it should be an area of
immediate focus. If Rural Power System Upgrades
and Circuit Rider maintenance were fully funded
across a five year period, a significant amount of fuel
oil could be saved. If a portion of the funds from the
Circuit Rider maintenance program savings were
set aside, local communities or regional associations
could continue the Circuit Rider from the reserves,
and the efficiency gains could be sustained.
If proper routine maintenance is performed on the 31
powerhouses that have already been upgraded, and if
the 62 remaining powerhouses in communities AEA
assists are upgraded and properly maintained, over
800,000 gallons of fuel per year will be saved.
Another fuel-saving measure that could be effected
immediately is to get existing heat recovery systems
operating properly. While a number of Alaskan
communities have some type of waste heat recovery
system, a substantial number of those systems
are not functional. Available records show that
if all existing waste heat recovery systems were
operational, an estimated 2,917,099 gallons of fuel
could be saved annually. Assuming a $3.00 per
gallon fuel cost, that translates to over $8,751,298.
These numbers are impressive, reinforcing the value
of supporting heat recovery systems. It would take
only a fraction of this annual savings to get all of
these systems back up and running effectively.
Generator Efficiency
Since technologies for increasing the kWh per
gallon of diesel burned are mature and commercial
generator engine and powerhouse controls are in
production, all utilities should consider the feasibility
of using them to reduce the cost of electrical power
in rural Alaska. Routine maintenance and operations
can have a significant impact on efficiency.
Waste Heat
Since technologies for recovering heat from jacket
water and exhaust gases are mature and commercial
heat recovery devices are in production, all utilities
should consider the feasibility of employing
jacket water and exhaust heat recovery for heating
applications.
Heat to Electricity
More research is needed to evaluate the suitability
of organic Rankine cycle and Kalina cycle systems
for use in most small Alaska utilities. These
technologies may be suitable for use in Alaska’s
larger power generating plants that operate on fuel
oil, but they should first be demonstrated via a pilot
project or the diesel testbed at the University of
Alaska.
Implementation
The following table provides rough preliminary
construction estimates for various types of diesel
efficiency upgrade projects in rural Alaska.
AEA’s Rural Power System Upgrade (RPSU)
program is well suited to rapid implementation
of diesel efficiency technologies in rural Alaskan
communities. The RPSU program also offers
technical and emergency assistance to over 130
isolated, rural villages, and has a longstanding
relationship with the Alaskan rural utilities and local
native organizations. The program has upgraded
32 rural village power systems over the last eight
years, primarily using Denali Commission funding.
This program replaces obsolete, inefficient diesel
powerhouses with regulatory-compliant facilities
that employ new diesel and control technology.
These improvements have increased diesel fuel
efficiency by 20% - 50%, saving hundreds of
thousands of gallons of fuel to date.
With proper funding, RPSU has the resources in
manpower, engineering support, and construction
management capacity to build five new powerhouses
and to upgrade an additional five powerhouses every
year.
68 696869
Recommendations
The next steps include:
• Identify and correlate funding sources for stable multi-year budget for the program
• Ramp up the current RPSU Program for five plus new powerhouses and five plus upgrades per year
• Evaluate new technologies and support field testing of promising techniques that will increase fuel
efficiency
• Add fuel efficiency parameter to evaluation process for new powerhouses
• Reevaluate powerhouses replaced over the last eight years for new technology efficiency
upgrades
Diesel Efficiency Project
Type
Rough Construction
Estimate Notes
Semiannual Circuit Rider $5,000 - $15,000 Semi annual on site training and technical assistance
Repair an Existing Heat
Recovery System $25,000 - $50,000 Analyze, repair, upgrade and install BTU meter and monitoring
controls
Installation of a SCADA
System $10,000 - $50,000 Remote monitoring capable SCADA system in a satisfactorily
functioning powerhouse
Install a Water Jacket
Heat Recovery System $180,000 - $250,000
For suitable powerhouse, modify existing cooling, install heat
exchanger, BTU monitoring, and arctic pipe to nearby heat
receptor.
Exhaust Stack Heat
Recovery $500,000 - $750,000 For suitable powerhouses with greater than 400kWh average
demand and a nearby heat receptor.
Powerhouse Upgrade $800,000 - $1.2million Powerhouse structure requires substantial remodel and
installation of heat recovery system
Powerhouse Module $1.2milllion - $1.5million Retire existing powerhouse and replace with a prefabricated
module
Complete Powerhouse $2million-$3.5million New powerhouse and heat recovery system with some
distribution improvements
70 71
The City of Ouzinkie was able to save substantial
amounts of diesel fuel and stabilize its rising energy
costs with the combined efforts of community, state
and federal agencies. The City of Ouzinkie, Denali
Commission, DCCED Community Development
Block Grant Program, and Alaska Energy Authority’s
Rural Power System Upgrade Program all worked
cooperatively on Ouzinkie’s successful and notewor-
thy diesel hybrid project.
Before the Project
The City of Ouzinkie has historically been plagued
with unreliable power, unpredictable outages, and
numerous consumer complaints. Customers routine-
ly replaced damaged electronic equipment and appli-
ances due to power quality problems. The outdated
powerhouse equipment was far past its designed
useful life. The plant consisted of two inefficient
diesel power generators, obsolete manual controls,
and an unreliable hydroelectric system. The system
required constant operator intervention to maintain
a marginal level of operation. The existing power-
house structure was in relatively good condition and
consisted of steel construction with concrete floors.
The dam, penstock, and turbine building were in
average condition.
The City’s water reservoir, dam, and penstock serve
a dual purpose. They supply the community with
potable water and provide the energy needed to turn
the hydroelectric turbine. When the water level
behind the reservoir becomes low due to freezing
temperatures or low precipitation, the operator must
shut off the hydroelectric and revert fully redundant
to expensive diesel generation.
The obsolete methodology used for the hydro load
and frequency stabilization wasted nearly a third of
the potential energy of the hydro. A diesel engine
was routinely operated with the hydroelectric turbine
Case Study
to provide backup power just in case the hydro went
offline. The trade-off for a small increase in reli-
ability was a significant increase in diesel fuel costs.
The diesel generators’ sizes were mismatched for
community load and for operation with the hydro.
Above: Old Ouzinkie powerhouse. Below: City of Ouzinkie
reservoir.
70 71
Project Scope
The project goal was to stabilize the cost of electrical
energy in the community while improving the reli-
ability and safety of the systems. This was accom-
plished by completely rebuilding the diesel power-
house and renewing the hydroelectric system. The
diesel powerhouse structure was sound, but a small
addition of a control room was added for the safety
of the operators and the reliability and life of the
new electronic switch gear and control equipment.
The cooling radiators were replaced and relocated
outside. The diesel fuel and cooling piping were
consolidated. The old, single-wall, bulk diesel fuel
tank was replaced with a double-wall intermediate
tank outside the plant. A new day tank with auto fill
controls was installed. An automated communica-
tions link between the diesel generator switch gear
and the hydro facility was established. The turbine
and generator were refurbished.
The two old 60kW and 200kW generators were
replaced with new 40kW, 100kW, and 155kW diesel
generators. All three have automatic paralleling and
load sharing capabilities in any combination with
each other and with the hydroelectric turbine. The
modern switchgear automatically dispatches the
most efficient generator.
The new powerhouse switchgear and controls can
bring the system from blackout to full diesel to die-
sel/hydro combination to full hydro. The system will
select the most fuel efficient combination of diesel
and hydro power all the way to full hydro (diesel off)
operation.
Project Result
Though not fully complete, the project has already
substantially lowered the community’s diesel fuel
consumption, increased power reliability and quality,
and increased the efficiency of the water resource.
Successful Rural Power System Upgrade for
the City of Ouzinkie
The community’s utility manager, Tom Quick,
recently reported that last year the community ex-
pended over $18,900 in diesel fuel at a cost of $2.76
per gallon. This year they have only spent $4,900 at
a current cost of $3.56 a gallon. Port Lions, a nearby
community, is reportedly paying over $8.00 a gallon
for diesel. Mr. Quick believes that keeping commu-
nity energy cost stable has prevented egress of the
local population.
Recently, the reliability and automation of the new
Above: The City’s new powerhouse building.
Below: The new powerhouse equipment.
72 73
diesel/hydro hybrid system was put to a real world
test when an anomaly occurred in the rural commu-
nity’s electrical distribution system. The hydro was
supplying the full community load when a momen-
tary distribution fault tripped the hydro off-line in
the early morning. Within seconds the powerhouse
controls started the diesel generators and restored
power to the town. Within minutes the controls re-
started the hydro, paralleled it with the most efficient
diesel generator, and then cooled and shutdown the
diesel generator. Without the intervention of an
operator in a short period of time the community was
back on clean, efficient hydro.
Remaining Items
Few items still remain to be completed:
To provide long-term efficiency, reliability, and
safety, replacement of the controls and switch gear
at the hydro turbine building, addition of a reservoir
level sensor and surveillance camera, and installation
of a reliable communication link to the dam reser-
voir. Future plans include waste heat recovery from
the diesel powerhouse and electrical distribution
improvements.
Continuing Efforts
With the partnership of the Denali Commission and
other agencies, Alaska Energy Authority’s Rural
Power System Upgrade Program continues to assist
rural communities to achieve results similar to those
of Ouzinkie.
Case Study
King Cove, Pelican, Gustavus, and Larsen Bay have
similar hydro and diesel electric systems. AEA is
currently working closely with these communities
to maximize their use of renewable hydro resources
and minimize their use of diesel fuel.
72 73
In June 2008 a Diesel Efficiency Workgroup formed to focus on reducing diesel fuel consumption in rural com-
munities through generation and distribution efficiency measures. The group also reviewed the suitability of
available technology for use in rural Alaska, and verified the capital costs and debt service assumptions, along
with long term operation and maintenance costs. The structure and output of the task group is represented in the
following graphic.
Diesel Efficiency Workgroup
74 757475
Efficiency (End-Use)
AEA Program Manager: Rebecca Garrett (771-3042)
TECHNOLOGY SNAPSHOT: ENERGY EFFICIENCY
Resource Distribution
The cheapest unit of energy is the one unused.
Increase efficiency and conserve in order to lower
the cost of energy.
Number of communities impacted
Resource potential exists throughout the state.
Energy conservation and efficiency are ongoing
projects that are changing and developing constantly.
Technology Readiness
Mature – energy efficiency requires more mind-set
than technology. The most important infrastructure
will be an educated public.
Education and marketing are valuable components
of end-use energy management.
Environmental Impact
End-use efficiency also requires proper design to
consider user needs and comfort. Proper disposal of
old equipment is necessary. The result is a reduction
of energy used, the amount of fuel used, and related
emissions.
Economic Status
The rate of return for conservation and efficiency
is extremely high. This is a necessary step to take
before any kind of new infrastructure is considered.
That said, payback depends on energy efficient
measures.
This section describes end-use conservation, existing programs to promote end-use
conservation measures, and other sources of information on end-use conservation for
rural Alaska.
74 757475
The goal of energy conservation and efficiency
is to decrease the amount of energy used, without
sacrificing comfort. Examples of energy efficiency
policy or best practices are building codes, appliance
and equipment standards, and efficiency mandates.
Energy efficiency also means operating and
maintaining facilities or homes in the most efficient
manner, by adding insulation, maintaining boiler
systems, or testing the air flow.
Alaska has traditionally focused on energy supply as
opposed to efficiency. Many Alaskan communities
rely on diesel generation. When diesel prices are
low, conservation tends to literally slip out the
window.
Energy efficiency and renewable energy are twin
pillars of a sustainable energy policy. Becoming
more energy efficient is seen as one solution to
common, critical problems such as energy security,
global warming, and fossil fuel depletion. Good
energy conservation policy is primary when
addressing these critical issues. The reduction of
demands of infrastructure should be the first thing
Alaskans do for energy end-use control. This
reduction in demand will lead to a lowering in
energy supply development cost.
Energy efficiency should be viewed as an
investment, in which an initial cost is weighed
against a subsequent reduction in expected energy
use. Costs may continue to rise, but high costs can
be mitigated by energy efficiency. Increased end-use
energy efficiency will bring net economic benefits to
Alaskan homes and businesses.
Energy conservation focuses on where the energy
goes. The red area in the figure below highlights
sectors on the demand side of the Alaskan energy
flow.
Introduction
76 777677
Major Organizations and
Programs
The list below provides an overview of entities that
promote energy efficiency in rural Alaska.
- Alaska Housing Finance Corporation (AHFC)
http://www.ahfc.state.ak.us/
- Alaska Energy Authority (AEA)
http://www.akenergyauthority.org/
- Cold Climate Housing Research Center (CCHRC)
http://www.cchrc.org/
- Alaska Craftsman Home Program
http://www.alaska.net/~achp/
- Alaska Building Science Network
http://www.absn.com/
- Cooperative Extension Service
http://www.uaf.edu/ces/
- Weatherization Assistance Program Providers
overview: http://www.alaskacdc.org/
e.g.: http://www.ruralcap.com/
Existing Conditions
Table 1: Climate Zones for Alaska
76 777677
Alaska Housing Finance Corporation efficiency
programs address residential energy conservation,
low-cost loans for energy-efficient structures,
technical assistance, and weatherization.
Home Energy Improvement Program
In May 2008 the Alaska legislature appropriated
$300 million to AHFC for three programs to help
Alaskans reduce energy bills and make their homes
more energy efficient. The three programs are:
1. Home Energy Rebate Program
The program allows homeowners who make their
own energy efficiency improvements to receive
a rebate for some or all of their expenditures. It
requires a home energy rater to evaluate homes
before and after the improvements. The rebates
cover the cost of ratings up to $500 and cover the
cost of improvements up to $10,000.
2. Second Mortgage Program for Energy
Conservation
The program allows borrowers to apply to AHFC for
financing to make energy improvements on owner-
occupied properties. If the Home Energy Rebate
Program does not fully cover energy efficiency
improvements, the Second Mortgage for Energy
Conservation program enables AHFC to loan up to
$30,000 to qualified borrowers.
3. Weatherization Program
The Weatherization Assistance Program (WAP)
enables low-income families to permanently reduce
their energy bills by making their homes more
energy efficient.
During the last 30 years, the U.S. Department of
Energys (DOE) Weatherization Assistance Program
has provided weatherization services to more than
5.6 million low-income families.
By reducing the energy bills of low-income families
instead of offering aid, weatherization reduces
dependency and liberates funds for spending
on more pressing family issues. On average,
weatherization reduces heating bills by 32% and
overall energy bills by $358 per year at current
prices. This spending in turn spurs low-income
communities toward job growth and economic
development.
Residential Energy Efficiency
AHFC also published minimum insulation
requirements for buildings in Alaska based on the
International Energy Code (IECC) 2006 Sections
402.1 through 402.3. IECC describes the prescriptive
method for compliance and establishes minimum
thermal envelope insulation requirements for
buildings in general. AHFC encourages builders
to exceed these minimums. For this reason, AHFC
published a list of Alaska-specific amendments to the
IECC 2006 and the ANSI/ASHRAE Standard 62.2-
2004, Ventilation and Acceptable Indoor Air Quality
in Low-Rise Residential Buildings, (ASHRAE 62.2-
2004). These amendments shall be limited to new
construction only.
AHFC established 5 new IECC climate zones and
assigned a zone to each Alaskan community based on
heating degree day ranges (Table 1).
Alaska Housing Finance Corporation
78 797879
Alaska Energy Authority (AEA) promotes energy
conservation in Alaska through several programs.
As an equal participant in the State Energy Program
(SEP), AEA is able to offer small technical assistance
grants that help communities get a handle on supply
and demand side management and seek funding for
implementation. AEA promoted the Village End
Use Efficiency Measures Program (VEUEM) and is
seeking to implement the Alaska Energy Efficiency
Program and Policy Recommendations for the future
of their end use programs.
The final “Alaska Energy Efficiency Program and
Policy Recommendations” report was completed
by Information Insights, Inc. for the Cold Climate
Housing Research Center in June 2008. The report
was funded by the Alaska Energy Authority and
the Alaska Housing Finance Corporation. It is
a comprehensive review and analysis of energy
efficiency policies and programs in the State
of Alaska. With primary emphasis on Railbelt
communities, the review focuses on programs
that address end-use energy consumption in space
heating and electrical needs of residential and
commercial users.
The report outlines energy efficiency measures that
can be rolled into the Alaska State Energy Plan and
implemented immediately. These energy efficiency
measures, undertaken at low cost, pay back initial
investment in a matter of months or a few years and
provide long-term cost savings.
Alaska Rural Energy Plan
The Alaska Rural Energy Plan published in 2004
by AEA identified and widespread opportunities
for reducing costs of power and heat. After a
preliminary screening analysis that identified end-
use efficiencies as a potential source of economic
benefits for rural households, Section 4 of the 2004
Alaska Rural Energy Plan examined end-use energy
efficiency in rural Alaska households and rural
schools in communities that are eligible for Power
Cost Equalization (PCE) Funding. The objective
of the study was “to evaluate the costs and benefits
of end-use energy efficiency systems that are
suitable for rural Alaska and determine the extent
to which these systems could potentially reduce
the cost or improve the reliability of electricity
for rural communities” and, to review program
implementation alternatives with the goal of
maximizing program effectiveness.
Thereby the study distinguished between the
engineering economic potential (avoided cost
if adopted) and market potential (estimate of
participants) of end-use energy efficiency measures.
The study makes this distinction to account for the
fact that despite extremely favorable engineering
economics, customers may not purchase the most
economic alternative.
The Alaska Rural Energy Plan also addresses
some utilities concern that “in low or no-growth
markets with adequate generation capacity, a large
investment in energy efficient light bulbs may have
adverse effects by noticeably reducing demand and
causing generating plants to operate lower on their
fuel efficiency performance curve”.
As an example, an annual $224 savings per
household in rural Alaska could be achieved by
switching to fluorescents light bulbs, assuming seven
incandescent bulbs that would be replaced with small
compact fluorescents.
Alaska Energy Authority (AEA)
78 797879
Village End-Use Energy Efficiency
Program
Community impact is exactly what Alaska Energy
Authority (AEA) is considering when coming up
with the Village End-Use Efficiency Measures
(VEUEM) program. Communities are selected
based on recently having received or being about to
receive a Rural Power System Upgrade (RPSU) or
other energy infrastructure project. The intent is to
reduce usage and properly size new power systems.
This covers both demand and supply side issues.
The village end-use energy efficiency program
performs energy efficiency upgrades on rural
Alaskan community buildings. AEA, with funding
from the Denali Commission, works with villages
to help them achieve energy savings by replacing
or installing energy-efficient lighting, switch boxes,
motion sensors, set back thermostats, weather
stripping, and low mass boilers.
The program helps communities to achieve
significant progress toward energy efficiency.
In Phase I, the average grant fund per village was
$37,771 with a total program grant fund of $642,116.
Significant in-kind contributions from the local
school districts helped expand the reach of this
program. Full Phase I reports can be found here:
http://www.akenergyauthority.org/
programsalternativeVEUM.html
The figure below provides a community overview
of finished (Phase I, blue) and ongoing (Phase II &
III, black & red) projects. Additional communities
will be included in the program if funding becomes
available.
Alaska Energy Authority (AEA)
80 81
The potential cost savings of energy conservation
and efficiency is extremely difficult to get a handle
on. During a time of rising fuel costs, efficiency
may simply keep costs stable while actually reducing
usage. Energy conservation and efficiency should
always be looked at in usage numbers as opposed to
cash payback.
In small communities, the economy of scale is at
stake. If the school is the largest electric user in the
community and they reduce their usage by 30%, the
utility must still recover their fixed costs from the last
fuel delivery and pay for employees. The community
may experience a rate increase. However, exploring
both supply and demand side efficiency opportunities
can reduce any community-wide impact.
The community of Koyuk participated in Phase I of
the village end-use energy efficiency program. In total,
5 community buildings and 7 teacher housing units
received energy efficiency upgrades. The city-owned
buildings got retrofitted with 93 linear fluorescent
fixtures with T8 lamps and electronic ballasts, and
seven compact fluorescent light bulbs were installed.
The pre-retrofit energy use for all lighting was 14,852
watts. The energy use for all lighting post-retrofit
is projected at 10,550 watts. This equals an energy
reduction of 29% or 4,302 watts. The estimated annual
savings under different assumptions are shown in the
table below.
Hours Per Day /
250 Days Per Year
Electrical Savings Avoided Diesel
Use
Avoided Diesel
Costs
4 Hours $1,570 315 Gallons $589
7 Hours $2,748 552 Gallons $1,031
10 Hours $3,926 788 Gallons $1,473
Case Study: Koyuk
80 81
The “Alaska Energy Efficiency Program and
Policy Recommendations” report was completed
by Information Insights, Inc. for the Cold Climate
Housing Research Center in June 2008. The report
was funded by the Alaska Energy Authority and
the Alaska Housing Finance Corporation. It is a
comprehensive review and analysis of the energy
efficiency policies and programs in the State of
Alaska. The review focuses on programs that
address end-use energy consumption in space
heating and electrical needs of residential and
commercial users, with primary emphasis on Railbelt
communities.
The need for such a report was recognized because
demand side management (energy efficiency
measures) and conservation are often overlooked by
decision makers in favor of supply side solutions,
which offer constituents new projects and funding
opportunities. The report states that supply side
solutions are necessary in Alaska, but efficiency
measures should be step one in any energy plan.
Efficiency measures are the best way to decrease
demand and save money.
The report outlines energy efficiency measures
which can be rolled into the Alaska State Energy
Plan and implemented immediately. These energy
efficiency measures can be undertaken at low cost,
paying back initial investment in a matter of months
or a few years, and, they would provide long-term
cost savings.
The report also points out, that using energy more
efficiently does not necessarily mean seeing a
decreased level of service. With advances in
technology and simple changes in behavior,
significant savings can be realized without
compromising level of service.
The authors evaluated possible policy
recommendations based on:
• Return On Investment (ROI)
• Benefit/Cost Analysis (B/C)
• Carbon Reduction
• Present Value of Savings (PVS)
• Ease of Implementation
These recommendations are broken out into nine
categories:
1. State Leadership
2. Funding Energy Efficiency Programs
3. Public Education and Outreach
4. Collect Baseline Data
5. Existing Residential Buildings
6. New Residential Construction
7. Existing Commercial Buildings
8. New Commercial Construction
9. Public Buildings
The report also provides a preliminary budget
for costs of implementing and maintaining
recommended energy efficiency programs and
policies.
Alaska Energy Efficiency Program and Policy Recommendation
82 838283
The future of Alaska demands that every resident
get the most energy out of each unit purchased.
Energy efficiency has the highest return on
investment of any energy source. The environmental
implications are extremely high as well. Many
facility owners and operators tend not to think about
their usage, yet it is the easiest and fastest way
to keep costs down. End-use efficiency can keep
energy prices stable while reducing the need for new
supply-side infrastructure, or providing the extra
time to build that infrastructure. Careful project
design can mitigate comfort issues that may arise
from new lighting systems and different building
controls.
The technology is mature, but constantly evolving.
Owners and operators must keep current on the
changes. Before implementing changes they
must assure proper testing has been completed.
Conservation has a strong future in slowing the
advancement of global warming by reducing or
displacing production of greenhouse gases from the
electricity sector.
Efficiency and conservation easily become a way
of living. Constant education and outreach will be
required to reinforce good habits. Safe removal
and disposal (recycling) of old equipment should
be ongoing. Much like the Federal Government
does through mandatory reductions and use of
alternatives, the State of Alaska should lead all of
Alaska by example.
The Cold Climate Housing Research Center tests
new building technologies in Alaska.
The Alaska Craftsman Home Program, Inc. educates
Alaskans in energy-efficient building technology
specifically for northern regions and their diverse
climatic zones.
The Alaska Building Science Network promotes
energy efficiency as an essential component of
durable, safe, and affordable housing in Alaska.
Cooperative Extension Service of the University of
Alaska Fairbanks operates the Energy and Housing
Program. This program focuses on providing the best
possible housing technology information to Alaskan
home owners and builders.
There are five weatherization assistance program
providers in Alaska and fifteen regional housing
authorities. Each provider is responsible for a
specific Alaskan region. The program providers are:
RurAL CAP
Tanana Chiefs Conference
Interior Weatherization, Inc.
Alaska Community Development Corp.
Municipality of Anchorage
Other Organizations Conclusions and Recommendations
82 838283
Beaver Washeteria - Public buildings
such as washeterias afford
opportunties for energy projects, particu-
larly space heating from biomass
or waste heat recovery from diesel en-
gines. The community of Tanana, for
example, installed two cordwood boilers
in 2007 to heat their washeteria.
84 858485
TECHNOLOGY SNAPSHOT: HYDROELECTRIC
Installed Capacity (Worldwide)654,000 MW
Installed Capacity (Alaska)Approximately 423 MW
Resource Distribution
Resource potential exists throughout many areas of the state, with
most developed projects in the southeast and southcentral portions
of the state; Alaska has 40% of U.S. untapped hydropower (192
billion Kwh energy potential)
Number of communities/
population impacted 100+ (potentially +80% of Alaska’s population)
Technology Readiness Commercial (mature)
Environmental Impact Requires proper design to mitigate impacts to downstream aquatic
life, downstream water quality, and recreational uses
Economic Status
Unit costs are variable and site specific. Where found to be
economic, hydroelectric installations provide reliable, inexpensive
renewable energy
HYDROELECTRIC POWER GENERATION
AEA Program Manager: Douglas Ott (771-3067)
84 858485
Alaska has enjoyed a long and rich history with
hydroelectric power. By 1908, southeast Alaska
alone had over 30 developed water power sites with
a capacity of 11,500 kW. The vast majority, built
by private developers, provided power for industrial
operations, mainly for the gold mining works in
Juneau and on Douglas Island. Today hydropower
in Alaska provides 24%1 of the statewide electrical
power. Major developers include the State of Alaska
and public and privately owned utilities. These
power plants have proven to be long-term, reliable,
and relatively inexpensive sources of power.
Hydropower installations have the reputation for
being robust and durable, operating successfully at
some sites for more than a century. Hydropower’s
low operation and maintenance costs coupled
with long lifetimes result in stable power rates. In
Alaska, hydropower is currently the largest and most
important producer of electricity from a renewable
energy source. With increased interest in replacing
fossil-fuel-powered generation with renewable
energy resources, the statewide inventory of installed
hydropower capacity will continue to expand.
Introduction
Hydroelectric power is the generation of electric
power from the movement of water flowing from a
higher to a lower elevation. In contrast, hydrokinetic
technology (covered in a separate technology chapter
in this report) is a pre-commercial technology that
uses river current to generate electric power. A
hydroelectric facility requires a dependable flow of
water and a reasonable height of fall of water, called
the head. In a typical installation, water is fed from
a reservoir through a conduit called a penstock into a
hydraulic turbine. The pressure of the flowing water
on the turbine blades causes the shaft to rotate. The
rotating shaft is connected to an electrical generator,
which converts the shaft motion into electrical
energy. After exiting the turbine, water is discharged
to the river in a tailrace.
Technology Overview
Figure 1.
Typical High-Wall Reservoir Hydroelectric Dam Structure.
Source: Army Corp of Engineers
Figure 2.
Cross section of hydraulic turbine
generator.
Source: Army Corp of Engineers
86 878687
Before a hydroelectric power site is developed,
engineers must assess how much power will be
produced when the facility is complete. They also
review the natural conditions that exist at each
site: surface topography, geology, river flow, water
quality, and annual rainfall and snowfall cycles.
Extensive studies are conducted to evaluate the site’s
environmental conditions, land status and other
factors that may influence the configuration of the
hydro plant and the equipment selection.
A given amount of water falling a given distance
will produce a certain amount of energy. The head
and the discharge at the power site and the desired
rotational speed of the generator determine the type
of turbine to be used. The greater the head, the
greater the potential energy to drive turbines. More
head or faster flowing water means more power.2
The steep mountains, abundant rain and snow, and
relatively mild winter temperatures in Southeast and
Southcentral Alaska provide the ideal hydrologic
conditions for hydroelectric power.
South Fork Drainage, Prince of Wales
Island, Southeast Alaska.
Source: Alaska Energy Authority, 2008.
To find the theoretical horsepower (the measure of
mechanical energy) from a specific site, this formula
is used:
THP = (Q x H)/11.81
where: THP = theoretical horsepower
Q = flow rate in cubic feet per
second (cfs)
H = head in feet
11.81 = a constant
A more complicated formula is used to refine the
calculations of this available power. It takes into
account losses in the amount of head due to friction
in the penstock and variations due to efficiency
levels of mechanical devices used to harness the
power. To determine how much electrical power can
be produced, the mechanical measure (horsepower)
must be converted into electrical terms (Watts). One
horsepower is equal to 746 watts (U.S. measure).
Impulse and reaction turbines are the two most
commonly used types. Other types of turbines
include fixed pitch propeller and crossflow (also
called the Ossberger or Banki turbines). Each has
a specific operating range in terms of hydraulic
head and power output. In order to optimize the
power output and reduce capital costs, the specific
turbine to be used in a power plant is not selected
until all operational studies and cost estimates are
complete. The turbine selected depends largely on
site conditions.
A reaction turbine is a horizontal or vertical wheel
that operates with the wheel completely submerged,
a feature that reduces turbulence. In theory, the
reaction turbine works like a rotating lawn sprinkler,
where water at a central point is under pressure and
escapes from the ends of the blades causing rotation.
Francis or Kaplan turbines are reaction machines that
utilize both hydraulic pressure and kinetic energy to
create rotating shaft work. Reaction turbines are the
type most widely used in Alaska.
Technology Overview
86 878687
An impulse or Pelton-type turbine is a horizontal
or vertical wheel that converts the fluid’s change in
potential energy (hydraulic head) into kinetic energy
by water striking its buckets or blades to make the
extractable rotating shaft work. Pelton or Turgo
impulse turbines may have single or multiple nozzles
that accelerate flow to produce high velocity jets
that impinge on a set of rotating turbine buckets to
transfer their kinetic energy. The wheel is covered
by a housing, and the buckets or blades are shaped
so they turn the flow of water about 170 degrees
inside the housing. In contrast to a reaction turbine,
the fluid contained in the impulse turbine does not
completely fill all available void space, and the
turbine operates at ambient pressure. After turning
the blades or buckets, the water falls to the bottom of
the wheel housing and flows out.
Source: Bureau of Reclamation, 2005.
Source: Bureau of Reclamation, 2005.
Technology Overview
88 898889
Low-Head Hydropower
A low-head dam is one with a water drop of less
than 65 feet and a generating capacity less than
15,000 kW. Large, high-head dams can produce
more power at lower cost than low-head dams, but
construction of large dams may be limited by lack
of suitable sites, by environmental considerations, or
by economic conditions. The key to the usefulness
of low-head units is their lower capital costs and
the ability to satisfy local power needs with the
available resource.
Run-of-the-River
Run-of-the-river hydro facilities use the natural flow
and elevation drop of a river to generate electricity.
Facilities of this type are optimally built on rivers
with a consistent and steady flow.
Power stations on rivers with great seasonal
fluctuations require a large reservoir in order
to operate during the dry season. In contrast,
run-of-the-river projects do not require a large
impoundment of water. Instead, some of the water
is diverted from a river and sent into a pipe called
a penstock. The penstock feeds the water downhill
to the power station’s turbines. Because of the
difference in elevation, potential energy from the
water upriver is transformed into kinetic energy
and then to electrical energy. The water leaves the
generating station and is returned to the river with
minimal alteration of the existing flow or water
levels. With proper design, natural habitats are
preserved, reducing the environmental impact.
Run-of-the-river power plants typically have a
weir or diversion structure across the width of the
river. This weir contains an intake structure, often
consisting of a trash rack, an intake screen, and
de-sanding elements to conduct the water into the
penstock. These installations have a small reservoir
behind the diversion to keep the intake flooded and
reduce icing problems.
The output of the power plant is highly dependent
on the drainage basin hydrology. Spring breakup
will create a lot of energy, while flow diminishment
during winter and dry seasons will create relatively
little energy. A run-of-the-river power plant has
little or no capacity for energy storage, and so cannot
coordinate the output of electricity generation to
match consumer demand. Most run-of-the-river
applications are small hydro.
Small, Mini, and Micro
Hydropower
Small hydro is the development of hydroelectric
power on a scale that serves a community or an
industrial plant. The definition of a small hydro
project varies, but a generating capacity of up to 10
MW is generally accepted as the upper limit of what
is termed small hydro. Small hydro can be further
subdivided into mini hydro, usually defined as less
than 1,000 kW, and micro hydro, which is less than
100 kW. Micro hydro applications might serve
for single families or small enterprises, while mini
hydros might be appropriate for small communities.
A small hydro plant might be connected to a
conventional electrical distribution network
as a supplemental source of renewable energy.
Alternatively, a small hydro project might be built
in an isolated area that would be uneconomic to
serve from a network, or in areas where there is
no electrical distribution network. Small hydro
projects usually have minimal reservoirs and civil
construction work, consequently a relatively low
environmental impact.
A large and growing number of companies offer
standardized turbine generator packages in the
approximate size range of 200 kW to 10 MW. These
water-to-wire packages simplify the planning and
development of the site, since one vendor looks after
most of the equipment supply.
Technology Overview
88 898889
Non-recurring engineering costs are minimized,
and development cost is spread over multiple
units, so the cost of such systems is improved.
While synchronous generators capable of isolated
plant operation are often used, small hydro plants
connected to an electrical grid system can use
economical induction generators to further reduce
installation cost and to simplify control and
operation.
Micro hydro plants may use purpose-designed
turbines or industrial centrifugal pumps connected
in reverse to act as turbines. While these machines
rarely have optimum hydraulic characteristics when
operated as turbines, their low purchase cost makes
them attractive for micro hydro class installations.
Regulation of small hydro generating units may
require water to be spilled at the diversion to
maintain the downstream stream habitat. Spilling
will also happen when the natural flow exceeds the
hydroelectric system capacity, since the project will
generally have no reservoir to store unused water.
For micro hydro schemes feeding only a few loads,
a resistor bank may be used to dissipate excess
electrical energy as heat during periods of low
demand. In a sense this energy is wasted, but the
incremental fuel cost is negligible so economic loss
is minor.
Since small hydro projects may have minimal
environmental and licensing procedures, the
equipment is usually in serial production. Civil
works construction is also limited. The small size of
equipment also makes it easier to transport to remote
areas. Fore these reasons, small hydro projects may
reduce development time.
Small hydro and mini hydro can be used as
alternative energy sources in off-grid communities
with small loads. Small hydro tends to depend
on small water turbines fed directly by rivers and
streams. When compared with other renewable
energy alternatives like wind and solar, run-of-the-
river hydroelectric generators are able to deliver a
relatively consistent electric supply throughout the
day.
Run-of-the-river hydroelectric generators in Alaska
do not provide the same seasonally consistent
electric supply that larger hydroelectric projects
do. This is a result of the seasonal changes in the
flows of Alaska rivers, with diminished flow rates
during the winter months. The dams and reservoirs
of larger hydroelectric projects provide for energy
storage, holding water to be used to generate
electricity when flows are lower. Unfortunately,
most Alaska electric loads are highest during the
winter, the same time that river flow (and the electric
power generation capability of small and run-of-
the-river hydro) is at its lowest. This lowers the
amount of run-of-the-river hydro capacity that can
be installed without significant amounts of excess
capacity in the summer.
Conventional Hydroelectric
Storage Projects
When suitable hydraulic heads are not present
or when power needs are substantial, dams are
constructed across rivers to store water and create
hydraulic head to drive the turbomachinery. Dams
typically last for 50 to 100 years and so, are
constructed of durable materials like reinforced
concrete, roller-compacted concrete, earth, and
crushed rock. Smaller dams may be constructed of
steel or timber crib design. They vary substantially
in terms of height and storage volume, depending
upon local topography. There are several design
approaches used for concrete dams, including solid
and hollow, gravity and arch geometries.
Technology Overview
90 919091
In addition to the actual dam structure, there are a
number of other major design considerations. For
example, the penstock inlet manifold (usually with
screens to keep debris and fish from entering the
turbine) and the discharge or tailrace system must
be designed to maintain the hydraulic head and
minimize the effects of sedimentation, silt, and ice
build-up. Substantial effort goes into the design
of the dam spillway to safely direct extreme flows
downstream of the dam when the available reservoir
storage is inadequate to contain it.
Where the topography allows, several successful
design concepts are available to help mitigate the
environmental impacts of conventional storage
hydropower projects. In regions with high-elevation
natural lakes, lake taps may be utilized to feed a
power tunnel bored in rock to carry water to the
downstream powerhouse. This approach reduces the
need to construct a dam; the tunnel serves in place
of the penstock; and the lake is utilized as a natural
storage reservoir. At other sites, natural barrier
waterfalls can facilitate licensing of upstream hydro
development through their function as fish migration
barriers. Fish protection and passage facilities
and eco-friendly turbines can also be designed to
mitigate fisheries impacts of hydroelectric facility
construction. In order to be constructible, all
hydro projects must pass rigorous assessment.
Environmental effects must be determined.
Mitigation measures, compliance monitoring,
and environmental follow-up programs must be
established.
A strong attribute of conventional hydropower
is the dispatchability that results from the ability
to control the rate of power production through
storage and release of water contained behind the
dam. Given the general increase in electrification
that is occurring worldwide, the demand for using
hydropower reservoirs for both base-load and
peaking applications is rising. Other factors may
also lead to increased interest in conventional
hydropower. The variable nature of other renewable
energy sources like wind and solar makes pairing
with hydro energy storage an attractive option for
integrated supply systems.
Additionally, the scale of energy production
attainable with hydroelectric storage lends it to
connection with large electrical grids to displace
conventional fossil fuel-based power sources with
clean, non-carbon-based power. Fuel switching to
inexpensive hydropower may be possible in some
situations for home heating and (someday) for plug-
in hybrid cars.
Power Creek Hydro project
90 919091
The Alaska Division of Energy published the
Rural Hydroelectric Assessment and Development
Study in 1997. The study developed a database
of existing and potential hydroelectric projects in
Alaska. At that time, a total of 1,144 potential
hydroelectric sites were screened, resulting in two
potential projects with positive net benefits. These
two projects, and another two that were close to
potential positive net benefits were subjected to
additional engineering review.
In 2007 Crimp, Colt, and Foster updated the capital
cost estimates in the hydroelectric project database
to year 2005 dollars.3 The estimated capital cost per
installed kW in 2005 dollars ranged from $1,500 to
$250,000 (mean = $25,800). Annual operation and
maintenance (O&M) costs for each hydro project
were also estimated for the project’s screening
process in the earlier study, generally equal to 3% of
capital cost. Project viability was re-screened under
pessimistic, mid-case, and optimistic scenarios.
The high capital cost of hydro (both absolute and
especially on a per kW basis for smaller projects)
is the chief impediment to its economic feasibility.
This cost tends to decrease over time as the
original capital costs are paid down from power
sales revenue and the low O&M cost features of
hydropower prevail, however, higher fuel prices in
the 2007 analysis, relative to those considered in
1996, were sufficient to propel several projects into
the ranks of potentially feasible projects.
As part of the state energy plan process, a new
screening of available hydro site studies and
investigations was conducted by AEA. Utilizing a
team of hydropower experts (the Hydro Technology
Working Group) as a sounding board, this team
took a fresh look at potential hydro sites closest to
existing communities and used a variety of high
level screens to identify the sites most viable for
further investigation. See the Hydro Technology
Working Group Recommendations found later in
this narrative). The data identified from this process
have been incorporated into the energy plan’s master
database of energy technologies. Though not all
sites are economic at today’s fuel prices, some 99
sites have been identified in this screening as having
potential for future hydro development. Further
information on these sites is available upon request.
Potential Reduction in Cost of Energy
92 93
CASE STUDIES
The State of Alaska studied, built, or considered
building several large hydroelectric facilities in the
early 1980s, when state coffers were flush and oil
prices were high. With the low natural gas prices of
the late 1980s and 1990s, it appeared that many of
these hydroelectric projects were uneconomical with
a cost/benefit ratio under 1. These projects may now
have net benefits with the recent increase in prices.
As a result of the large upfront capital costs of these
facilities, screening for their economic viability
and benefits is vulnerable to assumptions about
oil and natural gas prices and the actual swings in
their market prices. These projects could benefit
from a longer-term assessment and assumption of
statistical ‘most probable diesel’ and natural gas
prices. The state’s roles as proponent, developer,
engineer, rate payer (through the Power Cost
Equalization program), regulator, and banker
through its various agencies and fiduciary bodies
also result in conflicting tensions when assessing
project feasibility. Yet, large infrastructure projects
are typically financed with public dollars under the
philosophy that the public enjoys the derived benefits
for many years after the project’s completion.
92 93
The Four Dam Pool projects are four
hydroelectric facilities (dams and lake tap projects)
built by the State of Alaska in the early 1980s
in Kodiak, Valdez/Glennallen, Ketchikan, and
Wrangell/Petersburg. The State paid for a portion
of the dams, and it provided loans through the
Power Development Revolving Loan Fund for the
remainder of the cost. The total cost for the project
in 2007 dollars is estimated at $811 million: $493
million in state funding, and $318 million in grants
and loans.4
Facility Name Communities Served
Swan Lake Ketchikan
Tyee Wrangell and Petersburg
Terror Lake Kodiak
Solomon Gulch Valdez and Glennallen
Case Study: Four Dam Pool
The projects were originally owned by the State of
Alaska, Alaska Power Authority, with electricity
sold to local utilities through Power Sales
Agreements. In January 2002, AIDEA loaned up
to $82 million to the utilities to acquire the dams
from AEA: $77 million for the dams and up to $5
million to construct an intertie between the Swan
Lake hydroelectric project and the Lake Tyee
hydroelectric project to move surplus energy from
Wrangell/Petersburg to Ketchikan.5 The Swan-
Tyee Intertie is expected to cost over $100 million
when construction is completed in 2009. The Alaska
legislature provided for non-payment or forgiveness
of a non-current loan owed to the AEA upon closing
of the bond sale; this was the outstanding balance of
the original loans.6
94 95
The Bradley Lake hydroelectric project was
constructed by the Alaska Power Authority on the
Kenai Peninsula near Homer, Alaska. The Alaska
legislature appropriated $168 million for what was
estimated to be a $245 million project. The project,
which cost over $300 million (including reserve fund
balances, of $479 million 2007 dollars), went into
commercial operation in 1991. The project includes
a concrete-faced and rock-filled gravity dam, 610
foot long, 125 foot high, and a 3.5-mile power tunnel
and steel-lined penstock. The project transmits
power to the state’s main grid via two parallel 20-
mile transmission lines. Homer Electric Association
under contract with AEA now operates the project.
Bradley Lake serves Alaska’s Railbelt from Homer to
Fairbanks as well as the Delta Junction area.7
The power from Bradley Lake is shared among the
Railbelt utilities via the intertie, according to a formal
sharing agreement.
Utility Share of Bradley Lake Share
Chugach Electric Association 30.4%
Anchorage Municipal Light and Power 25.9%
Homer Electric Association 12.0%
Matanuska Electric Association 13.8%
Seward Electric Utility 01.0%
Golden Valley Electric Association 16.9%
Also in Southcentral Alaska, the Eklutna hydroelectric
facility was brought on line in 1955 by the federal
Case Study: Bradley Lake Hydroelectric Project
government. In 1994 it was taken over by Anchorage
Municipal Light & Power. As the cheapest energy
source connected to the Railbelt energy grid, it
currently produces power at a rate of a few cents per
kWh.
The Cooper Lake hydroelectric facility is owned and
operated by Chugach Electric Association. It began
operation in 1960 and was recently relicensed by the
Federal Energy Regulatory Commission.
A number of smaller hydroelectric projects owned by
individual utilities are located across the state, mostly
in Southeast Alaska. There are also some very small
private facilities, most of which are owned by fish
processors.
A list of the larger facilities serving utilities follows:
Facility Installed Capacity (MW)
Annex Creek 3.6
Beaver Falls 5.4
Black Bear Lake 4.5
Blind Slough 2
Blue Lake 6
Bradley Lake 126
Chester Lake 1
Cooper Lake 16.7
Dewey Lakes 0.9
Eklutna 30
Falls Creek 0.8
Goat Lake 4
Gold Creek 1.6
Green Lake 18.6
Humpback Creek 1.3
Kasidaya Creek 3
Ketchikan 4.2
King Cove 0.85
Lake Dorothy 14.3
Larsen Bay 0.4
Pelican 0.7
Petersburg 2
Power Creek 6
Purple Lake 3.9
Salmon Creek 6.7
Silvis 2.1
Skagway 1
Snettisham 78
Solomon Gulch 12
South Fork Black Bear 2
Swan Lake 22.4
Tazimina 0.8
Terror Lake 20
Tyee 20
Total 423.35 MW
94 95
Hydroelectric generating facilities and diesel
generators provide a significant portion of the
electric power generation in Southeast Alaska. The
state and the federal government, as well as certain
communities and utilities have developed existing
hydroelectric generating plants in Southeast Alaska.
Hydroelectric facilities provide the majority of the
power requirement in Juneau, Ketchikan, Sitka,
Petersburg, Wrangell, Skagway, Haines, Metlakatla,
Craig, and Klawock.8 The largest in Southeast Alaska
is the Snettisham hydroelectric facility, providing
80% of the power used by Juneau and Douglas. Built
by the USCOE in the 1979s, and sold to the State of
Alaska in 1998, Snettisham is operated by Alaska
Electric Light and Power under contract with AIDEA.
In some communities the hydroelectric facilities
are capable of providing electricity in excess of the
community load. In response, electric customers in
these communities are replacing or supplementing
diesel space and water heating systems with electric
once. If enough customers convert to electric
heating, the surplus electric capacity will dissipate
and diesel generators will be needed to meet the load
requirements. One method of addressing this issue
is interruptible electric space and water heating when
reservoir levels are low or electric use is high during
the winter. During low water years in Sitka, the utility
has had to ask people to heat with wood or diesel9
while it interrupts electric service to electric heaters.10
Transmission line damage from avalanches disrupted
the flow of hydroelectric power from the Snettisham
hydro project to Juneau for six weeks in 2008. During
this period, power was restored using back-up diesel
generation at roughly 5x the power sales rate of
Snettisham hydropower.
Case Study: Southeast Alaska
Snettisham Hydroelectric facility. Above: Long Lake;
Below: Outside view of the Snettisham Hydroelectric
facility.
96 97
Many communities on Prince of Wales Island
are electrically intertied and are supplied power
primarily from the Black Bear Lake hydro project
(BBL).11 However, over the last 10 years system
load growth fully utilized the capacity and energy
available from BBL. Supplemental diesel-powered
generation was required to meet this increased
demand. To minimize dependency on high-
cost diesel-generated energy, Alaska Power &
Telephone Company began investigating renewable
resource energy sources on the island. Research
led to the selection of South Fork enhanced by its
close proximity to existing roads and power and
communication lines servicing BBL,as the most
feasible project.
With grant/loan assistance from the Denali
Commission and the Alaska Energy Authority,
construction of this 2 MW run-of-the-river
hydroelectric project began in the spring of 2004 and
came on line December 2005. AP&T was the general
contractor of the project, securing necessary permits,
providing engineering design, and constructing the
project with their own work force and seasonal labor.
The South Fork hydroelectric facility has already
accumulated over 1,000 hours of operation,
supplementing the BBL facility. The power plant
controls were incorporated into the BBL SCADA
system, enabling plant operators to remotely monitor
and control the new facility. While South Fork has
limited storage capacity, it will significantly reduce
the energy requirement from BBL, enabling BBL to
maintain water in storage for low rainfall periods.
This will significantly reduce the area’s dependence
on diesel-generated energy.
Case Study: South Fork Prince of Wales Island
South Fork Impoundment.
96 97
Three hydropower projects are now under
construction in Alaska. Falls Creek near Gustavus
is being built by Gustavus Electric Company,
Kasidaya Creek, between Haines and Skagway, by
Alaska Power and Telephone Company, and Lake
Dorothy by Alaska Electric Light and Power.12
FERC licenses have also been issued for hydropower
projects at Reynolds Creek and Mahoney Lake, and
soon to be issued for Whitman Lake.
Recent Grant Applications
AEA sought interest in study and development
of alternative and renewable energy projects
through three different grant application cycles
in 2008. Applications for hydropower project
development and construction have been received
for 64 projects. Requested grant funds total $159.8
million for facilities costing $3.35 billion in capital
costs. Because the applications are currently under
review and funds requested exceed grant funds
available, not all applications will receive the
amount requested. However, this information is an
indication of the current level of interest in hydro
development in Alaska.
Chakachamna Hydroelectric
Project
The Chakachamna hydroelectric project is currently
under study by TDX Power. Located on the
western side of Cook Inlet, the project would entail
a lake tap, 12-mile power tunnel, and a 40-mile
transmission line extension to provide 330 MW of
energy to the Railbelt grid at 1600 MWh annually.
Originally studied by the Alaska Power Authority in
the 1980s, the project as currently envisioned would
divert water from the Chakachatna River to the
McArthur Drainage Basin.
Susitna Hydroelectric Project
The hydroelectric potential of the Susitna River
has been studied over many decades.13 The initial
studies were done by the Bureau of Reclamation
in the early 1950s; in the 1970s , studies by the
New Hydro Projects
Corp of Engineers reconfirmed the feasibility of
Susitna River hydropower development. In 1980
the Alaska Power Authority (now Alaska Energy
Authority) was commissioned a review of studies
to date and a comprehensive feasibility study to
determine whether hydropower development on
the Susitna River was a viable option.14 Based on
these and other studies and the urging of the Alaska
Legislature, the AEA submitted a FERC license
application in 1983. The license application was
amended in 1985 for the construction of a two-dam,
three phase construction project. The estimated cost
of that project was $5.9 billion.
Arriving at a plan for bond financing was found to be
difficult for a project of this scale, one which was to
be constructed in phases over a 20-year time period.
Cash payment of a portion of the construction costs
was proposed as a means of reducing power costs to
customers.15
As a result of the high cost of the project, the
relatively low cost of gas-fired electrical generation
in the Railbelt, and the effect on the state budget
of the declining price of oil in the early 1980s, the
project was terminated by the Board of Directors
of the Power Authority in March 1986. At that
point, approximately $227 million had been
appropriated to the project from FY79-FY86 ($382
million 2007 dollars) and $145 million had been
spent. Extensive field work, biological studies, and
activities to support the FERC license application
were conducted with these funds. Though the
conclusion reached in 1986 was that the impacts of
the project were manageable, the license application
was withdrawn. The project data and reports
were archived to be available for reconsideration
sometime in the future.
More recently the Alaska Energy Authority was
authorized $2.5 million in funding to perform a
Susitna Hydro Feasibility Study and Cost Estimate
as part of the FY 2009 Alaska capital budget. Two
distinct tasks were identified in the legislation. First,
the 1984 cost estimate for construction of the Susitna
hydro project using current construction and design
technology will be reviewed and updated ($1.5
98 999899
million). This renewed analysis will produce four
alternatives of development for the project, with
energy output and costs.
Second, a Railbelt wide integrated resource and
transmission study will consider the four incremental
Susitna development alternatives, in conjunction
with other Railbelt wide generation projects
(1.0 million). The analysis will make use, to the
maximum extent possible, of the phased project
development considered in 1984, but key to the
analysis will be new assessment of long-term
Railbelt load growth, and matching the project the
realistic future Railbelt needs.
This integrated resource plan will yield an
economic plan for construction of power
generators, transmission lines, and fuel aggregation
infrastructure to meet the capacity, energy and
reliability needs of the Railbelt over the next 50
years. The plan will include creation of a diversified
power portfolio, and robust transmission system by
year 10 that can supply reliable postage stamp rate
power for all Railbelt utilities. The Susitna project
will be a key economic element in the creation of
this plan.
According to a November 2008 presentation to the
Alaska Energy Authority, the two dam configuration
of the Susitna hydro project would be capable of
producing approximately 7 million MWh annually.16
Hydro Technology Work Group
Recommendations
The hydro technology work group met several times
during the summer and fall of 2008. The work
group membership consisted of consulting engineers,
resource managers, interested citizens, and AEA
personnel. Assistance was provided in selecting the
steps in the hydro resource screening and evaluation.
The working group provided peer review and
validation of preliminary screening results. Specific
recommendations of the group included the
following:
Hydro projects do not lend themselves to •
utilization of unit cost factors in preparing
estimates of capital cost; rather, site-specific
analysis is required to arrive at optimal hydro
development schemes and their associated capital
costs.
Where excess hydropower is available, fuel •
switching to electric home heating is likely to
occur in communities with low-cost hydropower.
This impact will substantially increase the power
sales.
The work group recommended a 50-year working •
life be used in economic evaluation of hydro
facilities.
Pumped storage hydro projects are not viable in •
Alaska at present, since the power rate structure
currently used by utilities here offers no rate
differential for peak versus off-peak generation;
if possible this could be feasible for energy
storage, should large wind farm generation be
brought online in the future.
Research is needed to discover ways to reduce •
intake icing conditions and integrate schemes
for small hydro in village settings. Needed also
are standardize plans for propeller and crossflow
turbine runners (to reduce manufacturing costs
and promote use of materials such as composite
blades and others not requiring extensive
metal casting), to utilize heat recovery for heat
load dumps used for hydro energy frequency
regulation. Tests on coanada intake screens for
cold weather hydro applications are needed, as
are water conservation schemes for preservation
of reservoir storage during frequency regulation.
Standardized plans for small hydro applications
such as intakes, powerhouse, induction plants,
and tailraces are needing research. Alaska-
friendly fish passage designs for in and out
of a lake/reservoir, how best ways to provide
for flushing flows and sediments to replenish
spawning gravels in fish streams, optimal winter
instream flow releases for traditional hydropower
projects, and improved methods to predict snow
melt and runoff for modeling reservoir operations
The group recommended that prior hydro studies •
be made available online to promote future
development opportunities.
The group recommended working toward the •
establishment of a fair, efficient, and timely
authorization permitting process for new
hydropower projects, particularly for run-of the-
river hydros.
New Hydro Projects
98 999899
Alaska Energy Authority, Susitna Project Files,
www.akenergyauthority.org/SusitnaFiles/
SusitnaEnergyEstimatesFINAL_Nov08.pdf
Alaska Energy Authority, Financial Statements, June 30,
2002, p. 15.
Alaska Energy Authority project descriptions:
http://www.aidea.org/aeaprojects.htm
Alaska Department of Labor and Workforce Development,
Consumer Price Index, March 2003.
Alaska Industrial Development and Export Authority
Revolving Fund, Financial Statements, June 30, 2002, p.
22-23.
APRN, 2008. http://aprn.org/2008/02/25/sitka-asked-to-cut-
back-even-further-on-electric-usage/
Crimp, Peter M., Steve Colt and Mark A. Foster,
2007, Renewable Power in Rural Alaska: Improved
Opportunities for Economic Deployment, prepared for the
Arctic Energy Summit.
Dzinich, Kurt, Susitna Hydropower Options, Alaska State
Legislature, Senate Advisory Council, February 26, 1986.
Fay, Ginny, State Funding for Power Cost Equalization
and Four-Dam Pool Projects and an Overview of Proposed
Railbelt Electrical Intertie Proposals, Alaska State
Legislature Research Agency, Research Request 90.142
(revised), December 6, 1989.
Fay, Ginny and Gretchen Keiser, Railbelt Energy Analysis,
Alaska House of Representatives Research Agency,
Research Request 87.114, March 18, 1987.
Juneau Empire, 2008. http://www.juneauempire.com/
stories/103108/reg_350325319.shtml
Leavitt, Richard, Glen Martin, and Corry Hildenbrand,
Small Hydro Construction in Alaska. Hydro Review, Vol.
xxvii, November 2008. pp. 36-43.
Legislative Affairs Agency, Legislative Finance, TPS
Report 50454.
Alaska Energy Authority, Renewable Energy Atlas of
Alaska. July 2007
The future looks bright for hydropower
development in Alaska. Hydroelectric projects
produce power that is reliable, renewable and non-
polluting. Though they can be expensive to license
and construct, hydroelectric facilities produce long-
term dividends of power sales at some of the lowest
cost rates available today. Hydropower rates are not
subject to the price swings and escalation that fossil
fuels experience. Careful project design can mitigate
environmental impacts that are resolved during the
licensing stage in collaboration with resource agency
consultation.
Hydropower technology is mature and not subject
to performance risks inherent with some of the
new energy technologies that have yet to reach
commercial-stage development. Alaska has abundant
hydroelectric potential, especially in the Southcentral
and Southeast portions of the state; other potential
sites are available in the Aleutians, Southwest, and
the Interior. Transmission of power from large hydro
sites can be accomplished through grid interties to
neighboring communities, thus displacing fossil fuel
generation. Hydropower integrates well with wind
power in community power systems. It has a strong
future in retarding the advancement of global warming
by reducing or displacing production of greenhouse
gases from the electricity sector. The domestic
energy security available from utilizing hydropower
is unsurpassed and promotes the goal of energy
independence.
In its latest World Energy Outlook published
in November 2008, the International Energy
Agency has requested decisive action to secure
supplies of affordable, reliable energy and create
an environmentally benign energy system. The
development of hydroelectric facilities is a positive
response to that call for action.
References
Alaska Energy Authority, Alternative Energy,
Hydroelectric website
www.aidea.org/aea/SouthFork.html
Conclusions
100 101100101
Southeast Alaska Intertie Study, 2003. http://www.aidea.
org/aea/EnergyPolicyTaskForce/Phase2-Report-Final.pdf.
Teal, David, Susitna Feasibility, Alaska State Legislature
Research Agency, Research Request 83.137, May 13, 1983,
p. 2.
Tester, Jefferson, Elisabeth Drake, Michael Golay,
Michael Driscoll and William Peters, Sustainable Energy –
Choosing Among Options, MIT Press, 2005.
U.S. Department of the Interior, Bureau of Reclamation,
Power Resources Office, Hydroelectric Power, July 2005.
Footnotes
1 Renewable Energy Atlas of Alaska, Alaska Energy Au-
thority, July 2007. P. 10.
2 U.S. Department of the Interior, Bureau of Reclamation,
Power Resources Office, Hydroelectric Power, July 2005.
3 Crimp, Peter M., Steve Colt and Mark A. Foster, 2007,
Renewable Power in Rural Alaska: Improved Opportuni-
ties for Economic Deployment, prepared for the Arctic
Energy Summit.
4 Fay, Ginny, State Funding for Power Cost Equalization
and Four-Dam Pool Projects and an Overview of Proposed
Railbelt Electrical Intertie Proposals, Alaska State Legisla-
ture Research Agency, Research Request 90.142 (revised),
December 6, 1989.
5 Alaska Industrial Development and Export Authority
Revolving Fund, Financial Statements, June 30, 2002, p.
22-23.
6 Alaska Energy Authority, Financial Statements, June 30,
2002, p. 15.
7 http://www.aidea.org/aeaprojects.htm
8 Southeast Alaska Intertie Study, 2003. http://www.aidea.
org/aea/EnergyPolicyTaskForce/Phase2-Report-Final.pdf.
9 APRN, 2008. http://aprn.org/2008/02/25/sitka-asked-to-
cut-back-even-further-on-electric-usage/.
10 Juneau Empire, 2008. http://www.juneauempire.com/
stories/103108/reg_350325319.shtml
11 Alaska Energy Authority, Alternative Energy, Hydro-
electric website, www.aidea.org/aea/SouthFork.html
12 Leavitt, Richard, Glen Martin, and Corry Hildenbrand,
Small Hydro Construction in Alaska. Hydro Review, Vol.
xxvii, November 2008. pp. 36-43.
13 Unless otherwise cited, information on the Susitna hy-
droelectric project is from: Dzinich, Kurt, Susitna Hydro-
power Options, Alaska State Legislature, Senate Advisory
Council, February 26, 1986.
14 The Susitna Hydroelectric project was actually a series
of dams on the Susitna River.
15 Teal, David, Susitna Feasibility, Alaska State Legisla-
ture Research Agency, Research Request 83.137, May 13,
1983, p. 2. Alaska Department of Labor and Workforce
Development, Consumer Price Index, March 2003.
16 www.akenergyauthority.org/SusitnaFiles/SusitnaEner-
gyEstimatesFINAL_Nov08.pdf
100 101100101
TECHNOLOGY SNAPSHOT: Wind
Installed Capacity
(Worldwide)Over 100,000 MW worldwide
Installed Capacity
(Alaska)4,505 kW installed; 4,415 kW under construction
Resource
Distribution
Potentially available to communities in all regions of Alaska although generally
focused in coastal areas and throughout low-lying delta plains.
Number of
communities
impacted
At least 134 rural communities have viable wind resource. Additional communities
along the Railbelt have yet to be assessed.
Technology
Readiness
Wind-diesel systems are commercial to early-commercial depending on level of wind
penetration to existing load. Larger turbines appropriate for the Railbelt are fully
commercial.
Environmental
Impact
Impacts on local and migratory bird populations although little impact currently
documented. Potential for noise and visual impacts when sited close to a community.
Most impacts can be minimized by appropriate siting, design, and operation.
Economic Status Wide disparity on payback. For rural areas payback is highly dependent on associated
balance of system costs and price of offset diesel fuel.
Wind Energy Technologies
Wind Turbine at Selawik
AEA Program Manager: Martina Dabo (771-3027)
102 103102103
Wind is caused by temperature and pressure
fluctuations in the atmosphere as the sun warms the
earth. Wind devices are powered by air. Air moving
relative to an object such as the blades of a wind
turbine (or the winds of a plane) imparts a force on
that object.
Wind turbines use this aerodynamic force to convert
the kinetic energy of the wind into mechanical
energy that can be harnessed for use. The energy in
the wind can be defined for a specific unit of area
that the wind is flowing through in a unit of time.
Wind energy is directly related to the area swept
by the turbine blades, air density, and the cube of
wind speed. A doubling of the wind speed increases
the power from the wind by eight times. For this
reason, the most important factor in calculating
wind power is determining wind speed. This fact is
important when considering the integration of wind
into existing power systems. In most instances we
need our power to be constant, and wind energy is as
variable as the blowing wind.
A wind turbine generator (WTG) uses a wind
turbine rotor, with turbine blades to transform wind
energy into mechanical energy; and a generator, to
transforms that mechanical energy into electrical
energy. Many different types of wind turbines are
available. Sizes vary. Small (10 kW or less) wind
turbines which are typically used for individual
homes or small businesses. Medium-sized (50kW -
1000kW) ones are used for remote communities and
other grid-connected, distributed generation. Large
turbines (1MW or more) are generally used in large
wind farms.
This section focuses on medium and large wind
turbines. without addressing the application of
small wind turbines. More information on small
wind turbine applications can be found on the Wind
Powering America, small wind website at http://
www.windpoweringamerica.gov/small_wind.asp, or
Introduction
the Alaska Energy Authority website at http://www.
akenergyauthority.org/programwindenergybasics.
html. Various publications like Wind Power:
Renewable Energy for Home, Farm, and Business,
by Paul Gipe (2004), might also be helpful.
In rural communities now using diesel generators,
it is important to understand that wind energy
alone cannot replace diesel generation. In most
applications, when the wind is blowing, wind energy
is used to reduce dependence on and consumption of
diesel fuel. Diesel power is relied on when available
wind energy is insufficient. These wind-diesel
power systems are described in greater detail in the
next section.
Alaska has significant potential for wind technology
development throughout the state, but the best
resources are concentrated near the coast and on the
large coastal plains and river deltas, like the Yukon-
Kuskokwim region. Communities in interior Alaska
may also have wind resources, but they are generally
confined to passes, hills, or ridge tops. In nearly all
cases, specific assessments will likely be required.
Obvious opportunities exist, but there are
environmental and technical challenges related to
the deployment of wind devices in Alaska. Some of
these challenges are common to installations in any
location, while others are more specific to Alaska.
Most environmental concerns relate to potential
impacts on birds. Often, coastal regions with good
wind resources also have strong bird populations,
including the King Eider, Black Scoter, and the
Steller’s Eider, which is an endangered species.
Two general laws govern turbine impacts on birds,
the Endangered Species Act and the Migratory Bird
Treaty Act. At this point there is a limited amount
data on the impacts of Alaska’s current wind projects
on local species and population.
Survivability and performance of turbines in the
102 103102103
Arctic is another consideration. Wind turbine
performance in Alaska has been good, however there
is relatively limited information due to the small
number of installed wind systems. Additionally
there is little in-state maintenance support for
most wind turbines at this time, however, with the
continued growth of wind power in Alaska, this
expertise is being developed. Some areas of Alaska
are also subject to substantial amounts of rime icing
and extremely low temperatures, these conditions
may have a significant impact on wind turbine
performance and reliability.
Challenges still exist with the integration of wind
technologies into new or existing diesel power plants.
Combined systems can be complex, and care must be
taken during the development of the project to insure
that the resulting system will perform satisfactorily.
Also, the operational complexity of the system
changes as the amount of wind energy increases as
compared to the load.
Although a wind map has been completed for the
state, additional local wind assessments are required to
justify project development on any meaningful scale.
The installation of an anemometer and collection of
enough data to understand the local wind resource can
take over a year.
By the end of 2008, nine remote communities will
have wind turbines installed. An additional six projects
will be under construction. There is a single 100
kW wind turbine installed on the Railbelt near Delta
Junction. Studies are being undertaken to assess other,
much larger projects from Homer to Fairbanks.
104 105104105
For any location with a known wind resource,
there are several factors that can be used to predict
electrical generation from a wind turbine. The most
important include the power curve, the cut-in wind
speed, the rated wind speed and power output, and
the cut-out wind speed. These factors along with
turbine availability all contribute to the capacity
factor of a turbine. All of these terms are explained
in more details as follows.
Wind Turbine Power Curve
The main way to assess the performance of a
wind turbine is through the examination of a wind
turbine power curve, (see in Figure 1). On the
vertical axis, the power curve depicts the expected
electrical output of the turbine, at specific wind
speeds, which are shown on the horizontal axis.
Wind turbine power curves can be calculated either
based on the design of the turbine, or measured
from actual turbine operation. For smaller
permanent magnet generators it is especially
important to get a measured power curve from a
manufacturer since this curve can be different from
the calculated version. Furthermore, a power curve
is not universally valid. It depends on turbulence,
atmospheric pressure, and ambient temperature at
the measuring location. A power curve is usually
corrected to sea level and 68°F ambient temperature.
Cut-in Wind Speed
The lowest wind speed at which the turbine will
generate power is called the cut-in wind speed.
Although at face value this parameter should be
clear, there are several nuances. Because of the mass
of the rotor, a spinning turbine will produce power
at a lower wind speed than a turbine starting from a
standstill. If the power curve is calculated based on
the properties of the turbine, the cut-in wind speed
tends to be lower, as it does not account for the
rotational mass of the rotor. A low cut-in wind speed
is generally desired, since this translates to more
time when the turbine is producing at least some
power.
There are many different wind turbine designs,
but all of them have things in common. The main
component that transforms the wind energy into
mechanical energy is the rotor, which includes the
blades. Based on this commonality, wind turbines
are classified by the structure of the rotor and its
location in the airflow. The two main types of wind
turbine are horizontal axis and vertical axis, referring
to the axis of the blade rotation. At this time, the
only type of configuration commercially available
for medium and large installations is the horizontal
axis turbine, so it is the only one considered here.
The rotor of a horizontal axis wind turbine
rotates around a horizontal axis, parallel to the
wind direction. The blades of the rotor are
arranged rigidly in a plane, that is always oriented
perpendicular to the wind. These turbines generally
have an eclosed part or nacelle that houses all of the
wind turbine’s mechanical infrastructure such as the
generator, gearbox, break, and power electronics.
While most smaller wind turbines have a tail, tails
are not common on larger turbines. All horizontal
axis wind turbines are mounted on top of a tower,
which is either tubular or lattice frame in design.
Wind Power Technology Overview
Wind Turbine Performance
104 105104105
Rated Wind Speed and Rated Output
Power
The rated wind speed and output power are relative
values that give an indication of wind speeds
required for the turbine to produce large amounts
of power. If the rated wind speed for the turbine is
much higher than the typical wind speed for the site,
it is probably not a good turbine to use. There will be
little time when the turbine is producing significant
amounts of power. Usually, a generator with lower
rated wind speed is better than a similar one with a
higher rated wind speed. This is because the turbine
with a lower-rated wind-speed will reach fall rated
output under more likely wind speeds.
Cut-out Wind Speed
Cut-out wind speed defines the speed at which the
wind turbine is designed to be shut down to prevent
damage to the wind turbine. The wind speed is
usually monitored by the turbine control system,
and if the cut-out wind speed is reached, the turbine
braking system is applied and the turbine will not
operate. Typical cut-out wind speeds are around 25
m/s (56 mph). By oversizing specific components,
wind turbines can be designed to have higher cut-
out wind speeds. Small wind turbines with furling
mechanisms do not have a cut-out wind speed.
Instead, as the wind speed increases, the furling
mechanism engages, turning the turbine rotor out of
the wind, and thus reducing the turbine strain and
power output.
Survival Or Maximum Wind Speed
The survival wind speed is the maximum wind speed
that the wind turbine is designed to withstand safely.
Most wind turbines have a specified survival wind
speed of 50 m/s - 65 m/s (112 mph - 145 mph), and
in many cases this value is regulated by national
standards. Wind turbines can also be specified to have
higher survival wind speeds for installations in unusual
or special environments. Small wind turbines with
furling mechanisms will still be generating power up
to the survival wind speed, while non-furling turbines
will not be operating at wind speeds higher than
the cut-out wind speed. The survival wind speed is
really more of an insurance or a safety consideration,
as wind turbines typically do not suffer any damage
from winds higher than the stated survival speeds.
Availability
Availability describes the amount of time that a wind
turbine is ready to produce energy. It is defined
as the ratio between the number of hours the wind
turbine operates divided by the number of windy
hours over the same time period. A high availability
describes a turbine that is producing power whenever
the wind is blowing. Availability is a term used to
describe the operational and maintenance condition
of the wind turbine. In modern wind turbines,
availabilities over 95% are expected. For small wind
turbines, availability over 99% is not unusual.
Capacity factor
Wind turbine capacity factor describes the amount
of energy that the wind turbine produces compared
with theoretical production if it were running at
full, rated power. The capacity factor is reported
over a fixed time period, usually a month or a year,
and is calculated by dividing the turbine’s energy
production over that time by the energy production
if the turbine were running at rated power over the
same time period. Capacity factor describes the
power production expectations of the wind turbine.
It is most strongly related to the wind resource at the
site. Capacity factors of 25%-40% are typical, while
values up to 60% have been reported.
Wind Power Technology Overview
106 107106107
Wind Turbine Types
As would be expected with any power generation
technology, not all wind turbines are created equal.
Additionally, specific design features make some
turbines more appropriate for remote or Alaskan
installations. One of the primary problems with
wind turbines installed in rural Alaska during the
1980s (many remains of which can still see be
seen), is that little thought was given to appropriate
application of the turbines or the long-term
sustainability of the projects.
Wind Turbine Class And Certification
The International Electro-Technical Commission
(IEC), an international standards development
organization, has developed a classification system
for wind turbine systems. It specifies the design
conditions for particular wind turbines. Class I, II,
and III specify the design wind speeds for a specific
turbine product. Manufacturers who are certifying
wind turbines must pick one of these classes.
Class I turbines are designed to operate in the
harshest climates, with strong annual average wind
speeds and turbulent wind. Class II turbines are
designed for most typical sites and Class III turbines
are designed for low wind resource sites. Typically
Class II and III turbines have a larger turbine rotor
(longer blades) to capture more of the wind energy at
lower wind speeds. They may look more appealing
from an energy capture point of view, even at high
wind speed sites; but this should not encourage
people to install higher class turbines for lower class
sites. The class of wind turbine should be selected
based on the conditions at a particular site.
The IEC has also developed standards for many
other parameters, such as power performance,
noise, and electrical characteristics. Most large
wind turbines have been certified to IEC standards;
however, this is not as common for medium wind
turbines, due in large part to the cost. Turbine
Class and certification should be considered when
selecting a turbine.
Turbine Design Types
Interconnecting a wind turbine into a remote
or weak grid network can be complicated, and
specific wind turbine design characteristics play a
key role in determining just how hard the job will
be. Traditional wind turbines with a synchronous
generator, stall regulated control, and no power
electronics can cause large power spikes and/or
power variability depending on the wind conditions
or during start-up. Turbines using synchronous
generators but active pitch control allow better or
smoother power quality. Variable speed wind turbine
technology with active pitch control can actually
allow the control system to specify a desired power
output from the turbine, as opposed to being limited
to accepting whatever energy the turbine produces.
Additional devices may also be purchased to smooth
out power fluctuations from the wind turbines, such
as capacitor banks, turbine soft starts, and variable
motor drives. In any case, the turbine selection
process should consider the level of turbine and
power quality control depending on the application
and system requirements.
Other Design Selection Criteria
A multitude of other selection or design criteria
should also be considered when determining the
turbine model for a particular application. Turbine
weight and installation height will be determined
by the equipment available to move and install the
turbine. Tower type (lattice or tubular, tilt-up or
crane-installed) will depend on the site conditions
and manufacturer’s options. Some turbine
manufacturers have cold weather packages that
allow turbines to operate at lower temperatures and
in icing conditions. Finally, there are applications
where it makes sense to install an older turbine,
which may have lower performance and limited
control options, but which can be maintained more
easily in rural areas rather than to purchase a modern
turbine, which will have better specific performance
and advanced control, but may be more difficult and
costly to service.
Wind Power Technology Overview
106 107106107
Wind Power Technology Overview
Wind-Diesel Applications
Wind-diesel power systems can vary from simple
designs, where wind turbines are connected directly
to the diesel grid with a minimum of additional
features, to more complex systems. Two overlapping
concepts define the system design and required
components: the amount of energy that is expected
from the wind system (system penetration) and the
decision to use thermal loads and/or a storage device
to remedy system energy fluctuations. Given today’s
technology, these issues are usually determined by
the system designers as a starting point for overall
system design. These concepts are described in the
following section.
When incorporating renewable-based technologies
such as wind onto a diesel grid, the amount of energy
that will be obtained from the wind resource relative
to the diesel generators must be determined, because
this will dictate which components will be used. A
three level classification system has been developed
that defines different levels of penetration on the
grid. These classifications, defined as low, medium,
and high penetration, separate systems along power
and system control needs (see the table on the
following page).
Kotzebue Wind Farm
108 109108109
Table 1: Penetration Class of Wind-Diesel Systems (Proposed by Steve Drouilhet)
Penetration
Class Operating Characteristics Penetration
Instantaneous Average
LOW
• Diesel runs full-time
• Wind power reduces net load on diesel
• All wind energy goes to primary load
• No supervisory control system
< 50%< 20%
MEDIUM
• Diesel runs full-time
• At high wind power levels, secondary loads are
dispatched to insure sufficient diesel loading or wind
generation is curtailed
• Requires relatively simple control system
50% – 100%20% – 50%
HIGH
• Diesels may be shut down during high wind availability
• Auxiliary components are required to regulate voltage
and frequency
• Requires sophisticated control system
100% – 400%50% – 150%
Wind Power Technology Overview
Renewable Penetration
108 109108109
smaller unit will be turned on. This in turn will
reduce plant diesel consumption and diesel engine
operation. It might also make the system vulnerable
to potential shortfalls, assuming the loss of one or
more of the wind generators or diesel engines.
In addition, with a large penetration of energy being
produced by the wind turbines, it will become
harder for the operating diesel units to tightly
regulate system voltage and maintain an adequate
power balance. There are options to insure that
the high-power-quality requirements of the power
system are maintained, even with half of the energy
provided by wind. Some of these options include
power reduction capabilities within the wind turbine
controller, the inclusion of a secondary load to insure
that no more than a specified amount of energy will
be generated by the wind, installation of capacitor
banks to correct power the factor, or even the use of
advanced power electronics to allow real-time power
specification.
Spinning reserve on medium-penetration power
systems requires experience with regard to proper
power levels and system commitments, but is not
considered technically complex. Such spinning
reserve issues should be handled on a case-by-case
basis. They can be partially resolved through the
use of advanced diesel controls, the installation
of a modern, fuel-injected diesel engine with fast
start and low-loading capabilities, controlled load
shedding or reduction, power forecasting, and
proper system oversight. Combined with the use
of variable-speed or advanced-power conditioning
available on many modern wind turbines, the control
requirements of medium-penetration systems are
relatively simple. The ability to provide high power
quality in medium-penetration power systems
has been demonstrated for years in a number of
critical locations. The most notable examples are
the military diesel plants on San Clemente Island
and Ascension Island, and the power systems in
Kotzebue, Toksook Bay and Kasigluk, Alaska. All
of these systems have experienced power penetration
at or above the guidelines set for medium-
penetration systems.
Wind-Disel Power System
Configurations
Low-Penetration Systems
The wind farm in Kotzebue is one of many low-
penetration systems that have been installed
worldwide. Low-penetration systems vary from
small to relatively large isolated grids. Some large
grids, such as those found in certain areas of the
United States and Europe, reach a wind power
penetration that would classify them in the same
category as low-penetration systems. In low-
penetration systems, the wind turbines act as just
another generation source, requiring no special
arrangements.
The control technology required at this level of
generation is trivial, especially given the control,
flexibility, and speed of modern diesel and wind
systems. In many systems, no form of automated
control is required; the wind turbines act under their
existing controllers, and an operator monitors all
system functions. Because the diesel engines are
designed to allow for rapid fluctuations in power
requirements from the load, the addition of wind
has very limited impact, if any, on the ability of the
diesel control to supply the remaining difference.
Issues of spinning reserve, a term used to represent
the availability of instantaneous system capacity
to cover rapid changes in system load or energy
production, are addressed by the allowable capacity
of the diesel engines, which in many cases can run at
125% rated power for short periods of time with no
adverse impact.
Medium-Penetration Systems
Systems with larger ratios of wind power fall into
this category. The concept is that by allowing power
penetrations above 50%, any under-loaded diesel
generators in power plants consisting of multiple
generators will be shut off and, if necessary, a
Wind Power Technology Overview
110 111
High-Penetration Systems
Although demonstrated on a commercial basis,
high-penetration wind-diesel power systems
require a much higher level of system integration,
technology complexity, and advanced control.
The principle of high-penetration systems is that
ancillary equipment is installed in addition to a
large amount of wind capacity (up to 300% of the
average power requirements), so that the diesel can
be shut off completely when there is an abundance
of wind power production. Any instantaneous
wind power production over the required electrical
load, represented by an instantaneous penetration
over 100%, is supplied to a variety of controllable
secondary loads. In these systems, synchronous
condensers, load banks, dispatchable loads
(including storage in the form of batteries or
flywheel systems), power converters, and advanced
system controls are used to insure power quality and
system integrity. Spinning reserve is created through
the use of short-term storage or the maintenance
of a consistent oversupply of renewable energy.
Although these systems have been demonstrated
commercially, they are not yet considered a mature
technology and have not been demonstrated on
systems exceeding 200 kW average load. Wind-
diesel systems that employ the high-penetration
system are operating in St. Paul and Wales.
Because of the large overproduction of energy, high
penetration wind-diesel systems are economically
feasible only if there is a use for the additional
energy generated by the wind turbines. In the case
of Alaska, this extra energy can be used to heat
community buildings and homes (thermal energy),
displacing fuel oil. Another use could be to power
electric or hybrid cars, ATV’s, and snow machines.
Storage use in high penetration wind applications
Until recently, it was assumed that high penetration
wind-diesel systems without storage were only
theoretically possible. This is no longer the case.
Commercially operating short-term storage and no
storage systems have been installed in recent years,
demonstrating that both technology choices are
viable.
Wind Power Technology Overview
In systems incorporating storage, the storage is
used to cover short-term fluctuations in power.
During lulls in wind generation, the battery bank
or other storage device supplies any needed power.
If the lulls are prolonged or the storage becomes
discharged, a diesel generator is started and takes
over supplying the load. Studies have indicated that
most lulls in power from the wind are of limited
duration, and using storage to cover these short
time periods can lead to significant reductions in
the consumption of fuel, generator operational
hours, and generator starts. The storage system
does not necessarily need to be able to carry the full
community load, since in larger systems the storage
is only used to smooth out lulls in wind energy or
to buy enough time to start a standby generator.
In these cases, the storage capacity should be
approximately the same size as the smallest diesel
and have an accessible capacity up to 15 minutes.
In wind-diesel applications, the requirements for
storage systems will depend on local wind resources,
the costs of different components, capacity and
power response times, and the power system
performance required. Different storage options are
discussed in a separate section of this report, but care
should be taken to insure that the storage technology
selected meets the specific needs of the particular
wind-diesel application.
All high-penetration systems, with and without
storage, have been installed in northern climates
where the extra energy can be used for heating
buildings or water, displacing other fuels. In these
systems, it may be wise to install uninterruptible
power supplies (UPS) on critical loads. Although
only a limited number of systems have been
installed, the concept is economically attractive
and has the potential to drastically reduce fuel
consumption in remote communities in Alaska.
Project Information110 111
resource data for a large number of Alaskan
communities, but in most locations site specific
wind data collection should take place for a
period of one year before project financing is
obtained.
Detailed Load Assessment
The second key piece of data is the current
and expected load for the community. This
information can initially take the form of a
daily total generation log. As the assessment
process becomes more detailed, it will become
important to have time series data representing a
full year, in a minimum of one hour increments.
This load data should take into account any
new plans for the community, such as new
buildings or services, as well as standard load
growth. Generally speaking, load data should be
collected at the power plant bus bar and should
be an average reading as compared to a series of
instantaneous measurements.
Development Considerations
Other factors play into the decision to implement
a wind-diesel power system. One important
factor is the age and condition of the existing
diesel plant. As introduced previously, wind
is a variable resource, and if harnessed it
needs to be combined with other base load
generation technologies. In most remote Alaskan
communities this means diesel generators.
Diesel generators are specifically designed to
provide power to a fluctuating load. They are a
perfect match to the fluctuating power produced
by a wind turbine.
As discussed in the section on wind penetration,
if the amount of wind relative to the load, and
thus the number of operating diesel engines, is
small, then older diesel technology will be able
to handle the inherent variability in the load and
wind generation. As wind penetration increases,
the controls of older diesels are not able to react
as quickly as needed.
The development of a wind-diesel project can
be a complex process, but with a wind resource
indentified, the first step of the process is already
completed.
Initial Site Selection
The next step is to assess the land availability in
conjunction with the wind resource map. The Alaska
Wind Map can be downloaded from the AEA web
site. This map covers most of the state and can be
used as an initial guideline of where to look, but
it should not be considered completely accurate.
Since the wind turbine needs to be connected to the
existing grid and have good road access, sites close
to the road, river, and/or power lines are preferred.
Once several potential sites have been identified,
they should be surveyed by a wind energy or wind
resources assessment specialist. The sites should
then be ranked based on a number of general criteria,
such as:
• Likely wind resource (higher the better)
• Limited environmental impact
• Siting constraints including land
availability, land cost, proximity to
the airport, accessibility, and historical
significance
• Proximity to the power plant and electrical
distribution
• Geotechnical considerations
At http://www.awea.org/sitinghandbook/ more
information on siting can be found.
Detailed Resource Assessment
Following identification of the most likely sites
for wind turbines, an anemometer tower should be
installed. Typically, the anemometers are installed
at the planned wind turbine installation height. For
most small to medium-sized communities a 30 m
(~100 ft) anemometer tower should be sufficient.
Larger communities may want to install taller
towers. If there are multiple high quality sites that
are not in close proximity, multiple anemometer
towers may be needed. On their website, AEA has
Project Information112 113112113
Additionally, the fuel performance of older
diesels drops off more rapidly at lower loads.
The efficiency of these diesels suffers as more
energy is produced by the wind turbines. This
limits the amount of diesel fuel that can be offset
by the wind turbines. In contrast, modern fuel-
injected diesel engines with electronic controls
can maintain high efficiencies even at low load
levels and should be employed for all higher
wind penetration systems. It should be noted that
the majority of diesel engines deployed in Alaska
are fuel-injected with electronic controls that
help to manage efficiency.
A second consideration is the overall age of the
diesel powerhouse and associated switchgear
and controls. As with any new energy project,
integrating new equipment into an old power
house is problematic, especially when this
integration involves shutting down power to the
community. In low penetration applications,
the additional control panels and integration are
probably not a significant concern, however, as
the level of desired wind penetration increases,
these integration and switchgear issues become
more complicated. For this reason, if the
intention is for wind energy to become a major
supplier of energy to the community, thought
must be given to the state of the diesel plant and
to a complete replacement of the whole power
system, diesel engines and all.
A community should also carefully consider
the motivation behind moving to wind
generation. Usually, the cost of energy is a key
driver; however, this is only one of the issues
to be studied. Other important issues are the
environmental impact of energy generation,
the price volatility of the ‘fuel’ used to create
that energy, the security of the resource supply,
as well as the personal feelings of community
members. Ultimately, the purchase of new
power generation equipment is a long-term
commitment and may not result in near-term
reductions in the cost of energy. While wind
turbines themselves are not more complex in regards
to maintenance and operations compared to diesel
generators, the integration of wind turbines into a
diesel system can add to the overall complexity of
the the entire system. A strategy for ensuring long-
term success must be developed beforehand.
System Analysis: While wind does not require fuel
as a resource, the costs associated with installing a
wind generation system are significant. Determining
if the price of harnessing free energy makes sense
is key to deciding how much wind, if any, to
incorporate into a community’s power system.
Using the data collected it is possible to assess
different power system configurations and different
scenarios for load, fuel prices, wind penetration, and
equipment cost. A software tool like the HOMER
model produced by the National Renewable Energy
Laboratory (NREL) (www.nrel.gov/homer) is a good
tool to conduct these initial assessments. Another
available screening tool is RETScreen, developed
by the Department of Natural Resources Canada.
Both tools have their individual qualities that have
been evaluated depending on the project needs in the
early phases of assessment. It should be noted that as
different options are assessed, care must be given to
insure that all key parameters and system efficiencies
are properly considered. Organizations like AEA or
private consultants can assist with this analysis.
As the project develops, more detailed technical
and economic assessments will be required. For
example, if initial analysis indicates that 500 kW
of wind energy is optimal, consideration of which
turbines could be used would be based on the
available land area. This, in turn, will better define
the cost of the required infrastructure and turbine
foundations, which can then be used to update the
system cost calculations and performance modeling.
At this stage, more detailed performance modeling
using software such as the Hybrid2 model (http://
www.ceere.org/rerl/rerl_hybridpower.html) also
developed through NREL, should be considered.
112 113 Project Information112 113
Environmental Assessment
As with any development project in a community,
environmental impact is expected and must be
assessed. The installation of a wind turbine may
impact birds, local wildlife and, fauna, directly or
indirectly. These impacts can be clear and easily
documented and mitigated; however, some impacts
are more difficult to quantify.
Environmental impacts will be site specific, and a
site environmental survey should be conducted at
any location considering wind power generation.
Depending on the source of funds, different levels
of environmental impact study are required. The
total environmental impacts of any project should
be understood in relation to those of other energy
options. Results of any environmental survey should
be discussed openly so that all options to minimize
these impacts are considered.
Potential Reduction in Cost of Energy
Many factors play into the assessment of
cost of energy from wind systems. The assumed
cost of diesel fuel and the potential level of wind
penetration are key parameters that must be
considered. The higher the penetration, the more
the potential fuel savings, but it is not until diesel
engines are shut off, or until a shift to smaller
and/or more efficient diesels, is made, will large
fuel reductions be possible. Nonetheless, in
operating low to medium penetration systems in
Alaska, fuel savings as high as 25% have been
recorded, and higher fuel savings are technically
feasible. The potential of these fuel reductions
resulting in a lower delivered cost of energy to
the consumer will depend greatly on the cost of
the diesel fuel, the capital costs of the project,
and more specifically on how much of that cost
must be borne by the consumer.
114 115114115
The following list includes turbine manufacturers who have equipment installed or being considered for
installation in Alaska. Many other manufacturers have turbines on the market. It may be appropriate to look at
those products if they have a proven track record in similar operating conditions.
Manufacturer Device Website Size Notes
Entegrity wind
systems E15/50 http://www.entegritywind.com/50 kW
Turbine max
power is closer to
65 kW
Northern Power
Systems Northwind 100 http://www.northernpower.com/100 kW
Various Vestas – V27 Various 225 kW Remanufactured
turbine
Various Vestas – V15/17 Various 65/75
kW
Remanufactured
turbine
General Electr ic GE 1.5s
http://www.ge-energy.com/
businesses/ge_wind_energy/en/
index.htm
1500
kW
Various WindMatic Various 65 kW Remanufactured
turbine
Turbine availability is also an issue, given the strong market for wind turbine technologies outside of Alaska. At
present only a small number of manufacturers are building medium-sized wind turbines in the of 50 kW to 1000
kW range. This limits their availability. A supply of remanufactured wind turbines in this range is available,
however, presenting another option. Remanufactured turbines, often units that were installed on American or
European wind farms in the mid to late 1980s and 1990s, are now being replaced with bigger turbines. In most
cases, these turbines are refurbished to the original manufacturers specifications.
Unlike rebuilt turbines, remanufactured ones are usually outfitted with more modern, and higher performance
blades, breaking systems, and controllers, as well as with performance monitoring equipment. In considering
remanufactured wind turbines, care should be taken to insure that a specific remanufacturer has a strong track
record and can provide ongoing and long-term service and/or support. Most high quality remanufactured
turbines come with a limited warranty. System developers should not purchase used wind turbines and conduct
the rebuild or remanufacture process themselves.
Manufacturer Options
114 115114115
The following describes the current use of medium
to large scale wind development in Alaska.
Existing systems:
Chevak
Delta Junction
Hooper Bay
Kasigluk
Kotzebue
Nome
Saint Paul Island
Savoonga
Selawik
Toksook Bay
Wales
Several additional large wind projects, such as the Fire
Island project along the Railbelt, are in development
but not yet under construction.
The Alaska Center for Energy and Power (ACEP)
at the University of Alaska is also in the process of
developing a Wind-Diesel Applications Center. This
Center would represent a partnership between ACEP,
AEA, several other state organizations involved in
wind-diesel technologies, and NREL. The Center’s
mission would be to advance technology in wind
energy and wind-diesel integration for the benefit of
Alaskans.
Current Activity in Alaska
116 117
In 1999 a high-penetration, no-storage, wind-
diesel power system was installed by TDX Power
and Northern Power Systems to run an industrial
facility and airport complex on the island of St. Paul
in the Bering Sea. The project was largely privately
funded and initially included a 225 kW Vestas V27
wind turbine. This project was later expanded and
now includes three V27 turbines, two 150 kW Volvo
diesel engine generators, a synchronous condenser, a
27,000 liter insulated hot water tank, approximately
305 m (1,000 feet) of hot water piping, and a
microprocessor-based control system capable of
providing fully automatic plant operation.
The electrical load for this industrial facility
averages about 70 kW, but the system also supplies
the primary space heating for the facility, using
excess power from the wind generators and thermal
energy from the diesel plant. When the wind
generation exceeds demand by a specific margin, the
engines automatically shut off, and the wind turbine
meets the electrical demand with excess power
diverted to the hot water tank.
Case Study #1: Saint Paul Alaska
V27 Wind Turbines on St. Paul
Island.
When wind power is insufficient to meet the load,
the engines are engaged to provide continuous
electric supply as well as energy to the hot water
system as needed. The total 500 kW wind-
diesel cogeneration system cost approximately
$1.2 million. According to TDX, the system has
eliminated $200,000 per year in utility electric
charges and $50,000 per year in diesel heating fuel.
The operating wind turbines have had a capacity
factor of almost 32% and good turbine availability
following an initial problem with the original
turbines’ generator. The average penetration for this
system has been almost 55%, with significant times
when the system operates with both of its diesel
generators off. Since January of 2005, wind energy
has saved over an estimated 150,000 gallons of
diesel fuel, about 50% of the expected consumption
without wind energy.
116 117
Toksook Bay is a coastal community located on
the Etolin Strait, approximately 115 miles northwest
of Bethel. This system was installed in the summer
and fall of 2006 as part of a complete plant retrofit
by the Alaska Village Electric Cooperative. The
town has a population of approximately 600
people, but it is interconnected through the land-
based interties to the nearby towns of Tununak
and Nightmute, bringing the total population
served to over 1,160. The average load of all three
communities is just under 370 kW. The power
system includes three Northern Power Systems
Northwind 100kW turbines, diesel engines, and
a computer-controlled resistive heater supplying
community heating loads.
The array of wind turbines has had an average net
capacity factor of 26.0% from August 2007 to July
2008 and good first year turbine availability of
92.4%. The average penetration for this system has
been over 24.2%, with average monthly penetrations
over 30% during winter months, when stronger
winds prevail. In the year ending September 2008,
almost 700 MWhrs of electricity were generated by
wind, offsetting almost 46,000 gallons of fuel.
Case Study #2: Toksook Bay
Northwind 100 Turbines
at Toksook Bay.
118 119118119
Wind Working Group
Recommendations
The wind working group discussed tasks of interest
for wind development in rural as well as urban areas.
The working group agreed that wind development
challenges exist and have to be addressed. Some of
the technical challenges have been outlined above.
Additional areas in need of further study were
identified as follows:
• Identify different business structures that
facilitate and optimize wind projects in rural
and urban energy environments.
• Identify options and discuss the possibilities
and cost of using excess wind energy for
heating and transportation fuel displacement.
• Identify the social impact of community wind
development.
• Create a database of locally available wind
turbine models and system components.
• Identify and list research and development
needs.
• Further study wind integration issues in larger
grids, especially in conjunction with large
hydro installations.
• Identify the Railbelt wind development
potential in regard to viable project locations.
• Approach residential wind issues separately,
but they should be studied when a larger
impact on small community grids is apparent.
There is clear interest and motivation to add wind
technologies to the options available for providing
energy services to remote communities in Alaska.
Although wind or any other renewable technology
is not going to replace diesel technology in the near
term, it is a valid option and should be considered for
communities that have access to a reasonable wind
resource.
The development of a wind-diesel power system or
the incorporation of wind technology into an existing
diesel power system is possible as can be seen by the
recent history of projects installed around the state. At
present, there are quite a few working examples and a
large reservoir of resident expertise that can be tapped
to improve future installations.
Costs and benefits must be assessed on a project-
by-project basis. The economic impacts must also
be weighed against other benefits of using wind
technologies, such as reduced risk to fuel price
volatility, environmental impact, and energy security.
It must also be understood that although wind is a
commercial technology, its application in Alaska will
continue to be challenging.
There are over 300 remote, diesel power stations
in rural Alaskan communities, only 10 of these
incorporate wind. This offers a great deal more
experience to be gained in Alaskan wind applications.
Nonetheless, the track record of wind integration at
all penetration levels indicates that this is clearly a
technology that is applicable for many of Alaska’s
rural communities, as well as for those along the
Railbelt.
Conclusions
118 119118119
References
References for further information:
Ackermann, T. (2005). Wind Power in Power Systems
West Sussex, England: John Wiley and Sons.
Baring-Gould, E.I.; Barley, C.D.; Drouilhet, S.; Flowers,
L.; Jimenez T.; Lilienthal, P.; Weingart, J. (1997). Diesel
Plant Retrofitting Options to Enhance Decentralized
Electricity Supply in Indonesia. Proceedings of the 1997
AWEA Conference, Austin, TX. June 1997.
Baring-Gould, E.I.; Flowers, L.; Lundsager, P.; Mott, L.;
Shirazi, M.; Zimmermann, J. (2003). World Status of Wind
Diesel Applications. Proceedings of the 2003 AWEA
Conference, Austin, TX.
Burton, T.; Sharpe, D.; Jenkins, N.; Bossanyi, E.; Wind
Energy Handbook, John Wiley & Sons Ltd. 2001
Dabo, M.; Jensen, J.; Smith, J.; Regional Economic Wind
Development in Rural Alaska – Part I Technical Potential,
the Arctic Energy Summit, Anchorage, Alaska, October 15
18, 2007.
Drouilhet, S. (2001). Preparing an Existing Diesel Power
Plant for a Wind Hybrid Retrofit: Lessons Learned in the
Wales, Alaska, Wind-Diesel Hybrid Power Project. 13 pp.;
NREL Report No. CP-500-30586.
Gipe, P.; Wind Power, Revised Edition: Renewable
Energy for Home, Farm, and Business; Chelsea Green
Publishing; 2004
Hunter, R.; Elliot, G. (Eds). (1994). Wind-Diesel Systems.
Cambridge, UK: Cambridge University Press.
Lundsager, P.; Madsen, B.T. (1995). Wind Diesel and Stand
Alone Wind Power Systems. Final Report May 1995, BTM
Consult and Darup Associates ApS.
Manwell, J.F.; McGowan,, J.G.; Rogers, A.L.; Wind Energy
Explained, by John Wiley & Sons Ltd. 2002.
Shirazi, M.; Drouilhet, S.; Analysis of the Performance
Benefits of Short-Term Energy Storage in Wind-Diesel
Hybrid Power Systems. 13 pp.; NREL Report No. CP-440
22108. (1997)
Web based resources:
Alaska Energy Authority, wind energy program: http://
www.aidea.org/aea/programwind.html
Danish Wind Industry Association guided tour and
information on wind energy and wind turbine siting: http://
www.windpower.org/en/tour/
HOMER power system optimization model (www.nrel.gov/
homer)
Hybrid2 power system assessment model (http://www.
ceere.org/rerl/rerl_hybridpower.html
National Renewable Energy Laboratory, National Wind
Technology Center: www.nrel.gov/wind/ Wind Powering
America: http://www.windpoweringamerica.gov/small_
wind.asp
120 121120121
Biomass Energy Technologies
TECHNOLOGY SNAPSHOT: BIOMASS
Installed Capacity
(Worldwide)
Globally, biomass is the fourth largest energy resource after
coal, oil, and natural gas. Uses: heating, cooking (biomass),
transportation (biofuels), and electric power generation
(biopower). NREL estimates 278 quadrillion BTUs of
worldwide installed biomass capacity. EIA estimates >2.8
quadrillion BTUs of U.S. biomass energy consumption
(2004)
Installed Capacity
(Alaska)
Biomass – (heat & cooking) widely used
Biopower - 0 kWe (currently no commercial installations)
Biofuels – (biodiesel, ethanol) demo projects
Resource Distribution
Potentially available to communities in all regions of Alaska
with adjacent or transportable biomass resources.
Alaska has >10 times more unused biomass energy resource
potential than needed to offset all its diesel fuel used for
power production in rural Alaska.
Number of communities
impacted 100+ SE Alaska and Interior
Technology Readiness
Biomass – commonly deployed (heat)
Biopower – Pre-commercial to early commercial.
Biofuels – limited deployments (fish oil/biodiesel)
Environmental Impact
With proper management, impact on local forest land and
species is generally considered to be positive. 1.5 million
acres are lost annually to wildfire in Alaska, and thinning
reduces fire risk.
Economic Status
High confidence in cost savings and localization of benefits
for heat. O&M creates local jobs and savings. Bio-Power
has high projected cost with limited potential at this time.
AEA Program Manager: Ron Brown (771-3064)
120 121120121
Introduction
Biomass energy, in the form of heat and
power, is created by the
combustion or gasification
of carbon-based plant
matter. Biomass energy
is considered demand
energy, available as/when
needed. Woody biomass
is the most commonly
used form of biomass
fuel. It is used directly
as firewood, or it can be
processed into woodchips
or densified into pellets or
bricks. Woody biomass
is inherently a distributed
resource: finding,
acquisition and gathering,
stacking, and storage are
the initial challenges with
biomass fuel.
Processing biomass ranges
from the simple (bucking
logs into suitable lengths),
to chipping or chunking
(chippers are commonly
available machinery),
to the more complex
(densification that involves
chipping, drying, and
compressing biomass into
pellets, bricks, or logs). As
the levels of complexity
rise, the benefits of proper
handling and storage of
the fuel become more
pronounced.
Hydronic (hot water)
furnaces and boilers
combust stick-wood to heat
water or other fluid, which can then be transported
and used nearby as district heating for buildings, for
example, or process heat for manufacturing.
Alaska has nearly 12 million acres of available
forested land, with an estimated 1.9 million cords
(3.7 million tons) of
annual growth. On
average, over 1.5
million acres per year
of forested land are
subject to wildfires and
beetle-kill. Some of the
wood on these affected
lands is salvageable as
biomass fuel. Alaska
grows substantially more
biomass than it uses for
energy.
Despite the obvious
opportunities, there
are also significant
transportation and
technical challenges
related to the deployment
of biomass energy devices
in Alaska’s urban or rural
communities. Some
challenges are common
to installations in any
location, while others are
more specific to Alaskan
off-road communities (see
box).
Larger scale wood-fired
power systems are quite
common throughout
Europe, the United States,
and Canada, especially
at forest-products
manufacturing facilities,
places that have the basic
ingredients for economic
and technical feasibility:
large demand for power,
heat required for lumber drying or other processes,
and plentiful wood waste that needs to be disposed or
used. Conventional biomass-fired plants totaling over
60 MW in capacity operated at pulp and sawmills in
Transportation and Technical Challenges to
Biomass energy:
• Environmental concerns, especially those related
to air quality and the health impact of smoke from
inefficient heating systems in small communities
must be addressed. Efficient stoves and boilers
required by federal regulations are more expensive
than many people can afford. Less efficient devices
are common in remote communities. As opposed
to individual user systems, community-scale and
industrial-scale systems for heat or power are easier
to regulate and present less of a threat to health.
• Biomass is a high-volume fuel requiring handling
equipment and protected storage facilities.
• Many Alaskan rural communities are in severe
physical environments and have limited human
resources for technical operations and maintenance
of complex or hazardous equipment.
• Heat and power are essential needs, especially
in winter. Equipment breakdowns and technical
challenges are magnified in these communities, so
diesel backup is necessary.
• Sustainability of forest resources is a sensitive and
essential issue involving the cooperation of many
stakeholders.
In addition to providing savings over diesel, harvest and
utilization of biomass can benefit communities in
other ways:
• Properly designed forest land use can lessen risks of
wildfire and improve wildlife habitat.
• Higher quality logs can be used for house logs or
milled into lumber; lower quality material can be
used for energy.
• Wood harvest and marketing for energy provides jobs
and keeps money in the community.
122 123122123
Greenhouse at Dry Creek heated with wood.
The hydronic fin tube and piping run under-
neath the plant platforms.
122 123122123
Ketchikan, Sitka, Metlakatla, Haines, and Klawock
into the 1990s. Retrofitting and re-permiting existing
coal power plants to co-fire wood and other biomass
represents another common bioenergy alternative in
the Lower 48. In Alaska, Eielson Air Force Base’s
coal power plant co-fired densified paper separated
from the Fairbanks borough waste stream until 2007.
Stand-alone, small biopower or combined heat and
power (CHP) technology is generally considered pre-
commercial in the U.S. While European and Asian
firms have commercial experience and demonstration
projects abound in the Lower 48, most systems are
complex and have significant technical and economic
challenges.
Cordwood is commonly used
for heating throughout Alaska.
Cordwood-fueled community-
scale heating systems have
been demonstrated in several
communities in Alaska, in
Dot Lake and Tanana, for
example. A woodchip-fired
school and community pool
heating system was recently installed in Craig, and
that heating system has been considered for other
communities as well.
Small, wood-fueled Combined Head and Power
(CHP) systems are planned by Chena (400 kW) and
by the Alaska Cold Climate Housing Research Center
(CCHRC) in Fairbanks (25 kW).
Biomass Technology Overview
Other systems such as fuel cells are not included in
this discussion, because they are still in early stages of
development and not close to commercialization.
Wood is composed of several chemical components
that react differently when burned. In a wood fire
approximately 80% of the solid wood or volatile
matter converts to gas before it burns. This gas
made up of carbon monoxide and hydrogen is
commonly called producer gas or wood gas. If it
is burned directly in a stove or furnace, its heat is
transferred directly to the living space or to water
where its heat can be distributed to buildings by
means of hot water or steam.
Producer gas can be
separated from the solids
and burned as a fuel gas.
Producer gas must be used
close to the source because
of its low heating value and
low energy density. This
gas has only 15% of the
heating value of natural gas
or propane, but it can be
burned directly in boilers, as a fuel gas in engines,
or externally to heat other heat transfer devices such
as Organic Rankine Cycle (ORC) fluids or Stirling
engines attached to generators. These devices are
currently being developed for generating power at a
small scale suitable for applications in Alaska.
As the gas and volatile components of producer
gas cool, several components condense to form tars
and oils. These oils can be converted to pyrolysis
oil, also known as bio-oil, which can be used as a
transportable liquid fuel. Technologies for making
bio-oil are still in development.
About 20% of wood is in the form of fixed carbon.
Fixed carbon converts to charcoal (char) when
heated. The charcoal does not convert to gas, but
burns in direct contact with air. Charcoal burns at
much higher temperatures than wood gas, so it is
preferred as a cooking fuel around the world.
Biomass technologies appropriate for Alaska fall into
in three categories:
1. Domestic heating appliances like stoves and
small boilers;
2. Community-scale heat and/or power systems
based on boilers or engines
3. Larger-scale power generators based on
steam or wood gas.
124 125
With devices that make gas or oil, the char is
recovered or burned to provide heat to make
producer gas. In a stove or furnace the charcoal
burns once the gases have evolved and air is
available for direct combustion.
Domestic heating devices and small boilers
sometimes use gasification principles to burn the
wood efficiently, but in these appliances all the wood
is converted to heat. Many older-style outdoor wood
boilers (OWBs) are inefficient burners. They cause
significant air pollution from incomplete combustion
and convert only 35% of the energy available in the
wood to heat energy in water. Newer, more efficient
boilers burn with a clean stack and convert more
than 70% of the energy in the wood to heat in the
form of hot water or steam.
Community-scale heat and power systems are
usually based on boilers that convert the heat to
hot water or steam for distribution. Larger boilers
can produce steam at a high enough temperature
and pressure to generate power in a steam engine
or turbine. Steam engines and small turbines
are usually very inefficient, so other fluids and
generating devices such as ORC and Stirling engines
are under development. In parts of Europe that have
extensive district (community) heating systems,
some plants are being modified to generate power
using gasifiers with engines or furnaces with ORC
and Stirling engines.
Large-scale power generators are usually based
on wood boilers that can operate at sufficient
steam temperature and pressure to make electricity
efficiently. A small power boiler, 10 MW, would be
enough to power a sizeable town. These systems are
not suitable for small villages with moderate heat
and power loads and limited technical expertise.
Wood biomass energy devices require a fuel
handling system, a combustion vessel (furnace,
boiler, or gasifier), ash removal, and general
maintenance. In the simplest case of manual loading
the equipment is needed to cut, gather, and store the
wood; manpower is needed to load the unit regularly.
In chip-fed systems, a chipper is added to the
equipment list, a loader to handle woodchips,
and a bin and feeder (moving floor and/or auger).
Woodchips are more vulnerable to moisture than
logs and require protection from weather. In
many systems the woodchips require screening
for oversized or undersized material, and they are
subject to bridging, a resistance to flowing.
Pellet-fed systems require more ‘upstream’
processing to deliver pellets to the system, but less
complex fuel handling; pellets can flow. Along with
higher delivered cost, all forms of densified biomass
have more predictable handling and combustion
characteristics than stick-wood or woodchips.
Hydronic (hot water) systems add the costs of water
or other fluid tanks, temperature and pressure control
systems, insulation, and piping to end-users.
CHP gasification systems require a more complex
temperature, pressure, and electrical control system;
wood gas cleanup equipment; a generator, turbine or
fuel cell; fail-safe switching; and a connection to the
electrical grid and/or battery bank.
ORC systems require heat and cooling to create
a temperature differential for electric generation.
Biomass-fired ORC systems are in development in
the United States after the successful demonstration
of a geothermal-fired system at Chena Hot Springs.
For some time these systems have been in operation
in Europe.
System and fuel types
Project Information124 125
The high capital cost and projected operation and
maintenance (O&M) costs of CHP systems will
likely be feasible only in larger communities with
high power demand, high diesel prices, and a way
to use the substantial amount of heat from the
system. As the technologies are refined and costs
are reduced, smaller-scale applications may become
feasible.
The sustainability of biomass supplies requires
planning and coordination, and it will vary widely
by area. Regional facilities that gather and process
biomass could become a feasible option for upriver,
forested communities to supply fuel to downriver
communities. Mobile equipment could be shared
by several villages in a region on a rotational basis.
Road system communities could also benefit from
medium-scale regional facilities.
In order to put together a biomass energy
project, the initial information required is heat
and electrical consumption estimations and fuel
resource availability. Forest biomass resource
information has been recently gathered for many
areas of rural Alaska.
Mapping Forest Biomass Resources:
Further successful deployment of biomass
energy systems requires secure and sustainable
wood supplies. Many rural areas do not
currently have an existing infrastructure for
harvesting, processing, and delivering wood.
Communities that could benefit from a wood-
fired CHP system must first complete wood
supply surveys and organize fuel acquisition
and handling plans. It is important that wood
harvest operations be planned in the context
of overall land use objectives to minimize
conflicts with other users.
Environmental Assessment:
Biomass heating or power systems must
comply with air quality and waste disposal
regulations. Design considerations include the
height of boiler stacks and protection of water
discharge. Solid residues from wood burning
are mostly non-toxic ash and useful as a soil
amendment.
126 127
Abundant wood fuel at relatively low cost is
the primary source of savings in biomass energy.
Savings are highest when available wood fuel is a
byproduct of wood processing (lumber mill, wood
product manufacturing) as in the case of wood chip
boilers. The cost of wood increases and savings
decrease where wood fuel is from round wood and
forest residue.
Installation and operation costs of biomass energy
systems may be higher than diesel or natural gas
systems. Operation and maintenance (O&M),
insurance, permitting, design, and environmental
monitoring costs may be substantial for the earliest
biomass installations. The application of lessons
learned will reduce costs on subsequent installations.
Potential reduction in cost of energy
Biomass heating systems are predicted to offset
heating costs in many communities where they are
not already in use. Biomass CHP systems could
result in long-term reductions in electrical generation
costs in communities with appropriate biomass
resources, heat and power demand, and escalating
diesel fuel costs.
A 2007 study suggests that at $2.25-3.00/gal diesel
fuel prices and current technology costs, only larger
communities are likely candidates for CHP systems.
That list includes Aniak, Dillingham, Fort Yukon,
Galena, Hoonah, Tok, and Yakutat. If fossil fuel costs
escalate and CHP technology evolves, more small
communities may also be come viable candidates.
The same study also concludes that woody biomass
resources are adequate for fuel requirements in most
of the forested communities being considered for
biomass systems.
126 127
UTC Power
200 kW
Purecycle
ORC
www.utcpower.com Chena Hot Springs
Commercial
demonstration with
geothermal, biomass
project planned
for 2009
Danish
Stirling
35 kW
Stirling www.stirling.dk Denmark Demo
Manufacturer Options
Decton Chip and
sawdust boiler www.decton.com Dry Creek Industrial and
community use
Decton Chip and
sawdust boiler www.decton.com Kenney Lake
Regal Saw Mill
Industrial and
community use
Crorey
Renewable
Resources
25 kW gasifier www.croreyrenewable.
com CCHRC Fairbanks
Prototype in
development, not yet
delivered
There are several options for heating, fewer for power generation. Listed below are some examples of high
efficiency boilers and some new designs for small-scale power generation being used or considered for use in
Alaska.
The following list includes developers who, at a minimum, have built a prototype device.
Manufacturer Device Website Location Level of
Development
Garn
High efficiency
Hydronic
Wood Fired
Heaters
www.garn.com
Dot Lake, Tanana,
Ionia, Homer (private
individual)
Commercial 25 years
High fuel efficiency
(75.4%), low
emissions
Chiptec Gasifier-boiler www.chiptec.com Craig 130 installed
1 - 30 MMBtu
AgriPower 100+kW www.agripower.com New York Demo
128 129128129
Case Study #1: Tanana, Heating System
Wood for winter heating is piled
up along the Yukon River at Ruby.
In November 2007 the community of Tanana installed two cordwood boilers to heat a washeteria with a system
similar to one operating in Dot Lake since the late 1990s. Cordwood is burned to heat a large reservoir of water.
Wood is burned with 75.4% efficiency at a high temperature for about two hours, twice a day. The water stores
the heat and circulates it to the washeteria and other buildings as needed.
The Tanana project represents an efficient method of burning wood. Other boiler systems are now being
developed to operate at high efficiency. Compared to the low-efficiency OWBs (Outdoor Wood Boilers), these
boilers use half the wood fuel. Many communities could benefit from these systems. They are heat-only systems
and have not yet been integrated into CHP systems capable of generating power.
System: Two (2) 1850 gallon hot water boilers, 425,000 Btu/hr each
Manufacturer: Garn, Minnesota
Fuel: cordwood substitutes for 9,000 gallons diesel per year (250 gals/day)
Wood fuel (spruce) at $225/cord is equivalent to diesel at $2/gallon
Schedule: installed November 2007
Budget: $170,000 including photovoltaic solar panels on roof of Washeteria
Assuming 72 cords/yr are necessary to displace 9,000 gal/yr of diesel, increased labor costs of $1,100/yr over
the existing oil system, $850/yr for power and other wood system O&M, $225/cord of spruce, and $5.00/gal for
heating fuel, annual savings are approximately $26,700/yr. Therefore the simple payback on the initial system
cost is $170,000/$26,700; approximately 6.5 years.
128 129128129
Case Study #2: City of Craig, Heating System
In 2004 the city of Craig began investigating ways to reduce the cost of heating their community swimming
pool and pool-house, as well as their elementary school and middle school. The three buildings are adjacent to
one another on city property in the middle of town. One study suggested converting the propane-heated pool
to oil (14,000 gallons/year). Further study showed that a woodchip-burning boiler could substitute for both the
propane used for the pool and the oil in the schools (~ 24,000 gallons of oil per year). Chipped wood would
come from a local sawmill. The project looked feasible with oil at $2.50/gallon, so a detailed engineering
design was developed and the boiler was finally commissioned in the spring of 2008. It was turned off in May
and restarted in September.
Wet chips are delivered to the 24-ton storage bin (a 10-day supply at 2.2 tons per day). Hot water from
the boiler heats air used to dry the chips to the desired moisture content. The wood is burned in a staged
combustion system. It is first gasified, and the gas is burned in the boiler. Hot water from the boiler is pumped
on demand to heat exchangers at the pool and schools. If the wood boiler failed, the existing propane and oil
boilers would continue to supply heat to the facilities. For three months the system required about 8 - 10 hours
per week of maintenance time, which included a weekly cleaning. The boiler has excess capacity and may
supply additional buildings in the future.
By January 2009, the City of Craig will release a report describing the development of the project. It will
probably take another two years to obtain more detailed operating characteristics and costs for the project.
Experience in similar Lower 48 installations has shown that it takes time to adapt to the inherent variability
of local fuel and heating loads. For example, in 2009 the City will try substituting less expensive hog fuel, a
mixture of sawdust and bark, for the more uniformly sized and drier chips currently supplied by the sawmill.
Assumptions and preliminary economics:
• 85% displacement of 22,300 gal/yr of #2 heating oil and 39,000 gal/yr of propane used by the pool and
school buildings
• $4.10/gal for heating oil and $2.50/gal propane
• O&M costs of approximately $24,000/yr (1/3rd labor and 2/3rd power and consumables)
• 753 tons/yr of 50% moisture content chips at $20/ton
• 65% efficiency for wood combustion versus
• 70% efficiency of the previous system
Annual savings will be approximately $122,000 per
year. Simple payback on the initial system cost
is $1,510,000/$122,000, approximately 12.4 years.
Given the spare capacity, system economics will
improve if the project serves additional facilities.
Given an estimated useful project life
of 20 years, the economics of the current project are
acceptable under the above assumptions.
Lessons learned at this installation can be used to save time
and reduce cost in other communities.
System: 4MMBtu/hr gasifier, hot water boiler
Manufacturers: Chiptec (Vermont), Design Engineer:
R&M (Ketchikan),
CTA (Missoula).
Fuel: woodchips from Viking Sawmill, Klawock,
displace equivalent of 24,000 gal diesel/year.
Schedule: Commissioned April 2008.
Installed cost: $1.51 million
130 131130131
The Cold Climate Housing Research Center
(CCHRC) is engaged in a biomass gasifier testing/
demonstration project with a proposed 25 kW gasifier
that is being manufactured by Crorey Mechanical in
Oregon. It is designed to run on wood chips. The
target delivery date was set for October 2008, but
the manufacturer is behind schedule. Now it might
be ready for shipment after January 1, 2009. The
manufacturer has previously successfully field tested
units using wood pellets and coffee waste as fuel, but
their product has not yet been commercially installed.
The intention is to run the gasifier in tandem with
a diesel genset displacing a portion of the diesel
fuel. Success with this first test could lead to pairing
the gasifier with a spark ignition genset and eventually
a microturbine to demonstrate other available options
potentially appropriate for specific applications.
The gasifier will be operated and assessed over a
testing period and, if successful, CCHRC will then
develop a feedstock conveying and drying system
appropriate for the Alaskan environment. This will
facilitate the subsequent placing of a unit in another
remote location for further testing and demonstration.
The first phase of this project is funded by the
Fairbanks North Star Borough and the State of Alaska
DCED at a level of $300,000. Additional funding will
be required for development of feedstock conveying
and drying equipment. In addition to this project,
CCHRC continues to search for a residential-scale
biomass CHP system for testing and demonstration at
their Fairbanks facility.
Proposed system: 25 kWe gasifier
Manufacturer: Crorey Mechanical (Oregon)
Fuel: wood chips
Schedule: tentative delivery date of January 2009
Budget: Phase 1: gasifier and testing ($300,000)
Source: Fairbanks North Star Borough
Phase 2: fuel handling ($$ unknown at this time)
Source: Unknown
Case Study #3: Village Power,
CCHRC 25kW Gasifier Demo
130 131130131
United Technology Corporation (UTC) and
Chena Power have proposed a biomass/ORC power-
generating demonstration project for a site near the
community of North P ole. Wood waste and waste
paper will be separated from the waste stream and
combusted in a Wellons thermal oil heater to deliver
heat to a UTC PureCycle 200 power plant module.
The boiler is rated at 2.5 MW thermal capacity with
an efficiency of 85%. UTC is currently redesigning
the PureCycle to operate at 20% efficiency converting
heat to electricity, which means that the proposed
system could supply up to 450 kWe (net 400 kWe).
The system will have excess thermal capacity that can
be used for space heating.
Four main components comrise the UTC/Chena Power
project:
• Shred-Tech STQ 100 Shredder and
Conveyor System
• Wellons Live Floor Feed System
• Wellons 2.5 MW Boiler
• Two UTC PureCycle 200 Power Plants
Case Study #4: Community CHP –Fairbanks
The shredder reduces the biomass to a uniform size
that is easily combustible and delivers it to the live
floor. The live floor stores the shredded biomass until
it is required by the boiler, at which time the rake
and auger system in the live floor feeds biomass into
the boiler. The boiler generates heat, which heats
thermal oil, which in turn heats refrigerant in the UTC
PureCycle 200 power plant. The refrigerant expands
and turns a turbine that generates electricity. On the
other side of the turbine, the expanded refrigerant is
air cooled. It condenses back into a liquid, completing
the cycle.
Proposed system: 400 kW
Manufacturer: Wellons, Inc. (Oregon), UTC
Power (Connecticut)
Fuel: woodchips, paper, cardboard
Schedule: Projected 2009-2010
Budget: $5 million
Future plans: if a successful demonstration,
this technology could be used at other sites
Based on: 400 kW ORC (UTC Power)
generator currently in use at Chena Hot
Springs
Case Study #4: Community CHP
Fairbanks 400 kWe ORC
132 133
Wood Energy Working Group Recommendations
The Working Group agreed that the need for
small to medium-sized biomass projects for space
heat is critical to help combat the high cost of
energy in rural Alaskan communities. They also
recommended ongoing research to find suitable
biomass technologies for generating power while
simultaneously providing space heating in smaller
communities.
The Working Group is aware of the impending
Alaska Energy Authority RFP process for Renewable
Energy Projects and is encouraging communities
that have biomass resources readily available to
apply. The consensus is that most applications will
be submitted for small to medium space heating
projects and district heat loops.
The group is interested in seeing wood pellet
manufacturing take place in Alaska. Several
firms from Outside with years of pellet production
experience are looking at developing projects in
Alaska, partnering with entities with resources and
Left: High Efficient Low Emission GARN
hydronic wood-fired heater being tested at
Tanana. Twin units will heat the 5,000 sq. ft.
washeteria and provide domestic hot water
for showers and washing machines. They
will also add heat to the community water
loop to help deter freeze-ups during winter
months.
funding capabilities. The consensus is that wood
pellets are desirable because they burn cleanly,
and that the appliances and boilers that use them
are a proven commodity. Wood pellets are easy to
transport and store, and they are the closest fuel to
liquid or natural gas that can be easily manufactured
in Alaska.
The group also recommends wide promotion
of EPA-certified wood stoves to insure efficient
wood resource utilization. They also recommend
promoting only High Efficiency, Low Emission
(HELE) Hydronic Wood-Fired Heaters for larger
projects that meet minimum standards for overall
efficiency (combustion efficiency x heat transfer
efficiency) and EPA particulate standards for
emissions.
132 133
Biomass CHP systems are in the early stages of
development and demonstration. They require more
development to perform reliably. Existing systems
do not show any savings over systems powered by
oil and gas at today’s oil and gas prices.
Facilities to manufacture densified biomass fuel
(pellets, bricks, and logs) will develop in tandem
with deployment of systems for delivery and use of
densified fuel.
Biomass for space heating to help reduce trhe high
cost of energy in rural Alaska has a high probability
of success. The following are requirements for
successful projects:
Projects must be economically viable•
Must be technologically feasible•
Must be supported and endorsed by owner/•
operators, the local community, fuel suppliers,
and state and local governing bodies
Must have a local champion•
Must have long term reliable and sustainable fuel •
sources
Several biomass heating systems are currently in
operation as successful examples.
References
Renewable Power in Rural Alaska: Improved Opportunities
for Economic Deployment, Peter Crimp, Steve Colt, Mark
Foster, Institute of the North, Anchorage, 2007, The Arctic
Energy Summit Technology Conference, Anchorage,
Alaska, October 15-18, 2007. https://www.confmanager.
com/communities/c680/files/hidden/Abstracts/
UploadedAbstracts/Renewable_Power_in_Rural_Alaska-
Crimp.doc
Feasibility Assessment for Wood Heating, Final
Report, August 2006 prepared by T. R. Miles Technical
Consultants, Inc. for Alaska Wood Energy Development
Task Group (AWEDTG), Juneau Economic Development
Council/Wood Products Development Service,
Sitka, AK http://www.jedc.org/forms/AWEDTG_
WoodEnergyFeasibility.pdf
Dave Misiuk, Cold Climate Housing Research Center,
Fairbanks http://www.cchrc.org/
Craig, Alaska Wood Energy Project Update, Jon Boling,
City of Craig, Alaska Wood Energy Conference, Fairbanks,
November 14-15, 2007 http://www.tananachiefs.org/
natural/forestry/AWEC/Day1/Field%20proven%20
wood%20energy%20systems/Jon_Bolling.pdf, http://www.
craigak.com/index_files/wood.htm
Draft Proposal, Chena Wood Energy Project, May 7, 2007
Building a Better Wood Stove in Tanana, Milkowski,
Fairbanks Daily News-Miner, November14, 2007 http://
nl.newsbank.com
Conclusions
134 135134135
134 135134135
Geothermal Energy Technologies
TECHNOLOGY SNAPSHOT: GEOTHERMAL
Installed Capacity (Worldwide)approximately 10,000 MW
Installed Capacity (Alaska)680 kW installed
Resource Distribution Dispersed resources exist across southeast Alaska,
the Interior, and the Aleutians.
Number of communities impacted Limited
Technology Readiness Commercial
Environmental Impact Minimal, small plant footprints, little or no CO2
emissions, reduced surface flow of thermal springs
Economic Status
Payback of 5 to 8 years expected for the Chena Hot
Springs Project, project economics vary widely
depending upon size of project and sales price of
electricity
Hothouse tomatoes are grown at
Chena Hot Springs year round
with the geothermal project.
AEA Program Manager: David Lockard (771-3062)
Right: Alaska’s abundant geothermal
sources provide hot water at close
proximity.
136 137136137
Introduction
Geothermal is a general term describing the heat
generated and contained within the earth. Over 90%
of the total volume of the earth has a temperature
exceeding 1000oF, and only a small amount of
this heat gets close enough to the earth’s surface
to be utilized by conventional technology and be
considered an energy resource. When it does, the
elevated heat manifests itself in uncommon geologic
occurrences like lava flows and volcanic eruptions,
steam vents or geysers, hot springs, or elevated
geothermal gradients creating hot rock. In normal
geologic situations, the majority of the heat slowly
dissipates into the atmosphere by unseen heat
transfer processes known as conduction, convection,
and radiation.
At the surface of the earth, heat can also be gained
from the sun during daylight hours. The sun,
especially during the summer months, can heat to
depths of 100 feet. When ground source heat pumps
are used for heating buildings, the energy may come
from either solar or geothermal sources. Below a
depth of several tens of feet, any heat recovered
from the earth will usually be geothermal in origin.
Geothermal heat comes from two main sources:
the original heat of the earth generated at its
formation about 4.5 billion years ago and the
more recent decay of the radioactive isotopes of
potassium, uranium, and thorium.
Geothermal resources are found on all continents
and have been used for a wide variety of purposes,
ranging from balneology (the science of soaking
in hot springs or hot mud baths) to industrial or
direct use processes such as space heating, from
process heat for drying things like fish or lumber
to electrical power generation. Industrial uses
require temperatures ranging from 150oF to around
300oF. For large-scale electrical power generation,
(measured in megawatts or millions of watts)
temperatures in the neighbourhood of 300oF to 650oF
are needed. In Alaska with its cold climate and
abundant cold water resources it is possible to use
much lower geothermal temperatures for small-scale
electrical power generation.
In fact at the Chena Hot Springs Resort, 500 gallons
per minute of 163oF water is making around 200
kW of electricity, the amount of electricity used by a
village of about 300 residents. The combination of
high flow rates of hot water and low surface water
temperatures in use allow Chena to be the lowest-
temperature geothermal power plant in the world.
For geothermal energy to be technically and
economically feasible, a number of conditions must
be met. These conditions include: (1) an anomalous
thermal gradient or accessible heat in a near-surface
region, (2) sufficient porosity and permeability
within the section of ‘hot rock’ so that fluids can
move freely and transfer heat, and (3) some form
of conduit that allows a hot fluid to flow to the
surface in sufficient quantities. There the energy
can be converted into a usable form. Clearly, the
higher the near-surface temperature and the higher
the permeability and flow rates, the more feasible
the resource becomes. Unfortunately, out of the
thousands of natural springs in Alaska, only a few
have sufficient temperature and flow rates necessary
to produce electricity. In some limited cases where
high near-surface heat exists, these fluid flow and
heat transfer systems can be enhanced by drilling
and fracture technology if geologic conditions are
right (see EGS below).
Globally, geothermal resources have been found
in four generalized geological environments: areas
of active volcanism and igneous activity; areas of
thinned continental or oceanic crust; large crustal
scale faulting; and some sedimentary basins. Power
plant outputs from these geothermal fields vary from
about 1 MW to over 700 MW. The most prolific and
widespread geothermal resources are contained in
areas of dramatically thinned crust and associated
igneous activity, such as Iceland and to a lesser
degree Nevada and southern California.
136 137136137
Technology Overview (Steam & OCR)
With the possible exception of weakly
developed rifting on the Seward Peninsula, this
geologic environment does not exist in Alaska.
Producing tens of megawatts, moderate-sized
geothermal resources are associated with linear
belts of volcanoes which form when one plate is
subducted beneath another. Active Alaska volcanoes
like Mt. Spurr west of Anchorage and others along
the Alaska Peninsula and Aleutian Islands are
subduction-related. Some of these volcanoes host
what are apparently the hottest geothermal resources
in Alaska.
Other, smaller geothermal systems are closely
associated with crustal scale strike-slip fault systems
in southeastern Alaska and through the Interior. A
complete list of these known geothermal resources
can be found at www.dggs.dnr.state.ak.us in
publication MP-8.
Hot springs located along large faults in the earth
are relatively widespread. These faults can extend
well into the crust of the earth. If the fractures
remain open under the great amount of pressure,
these faults might allow water to percolate more
than 2-3 miles deep. If this happens, the water will
become hot by virtue of the significant depth reached
(a typical geothermal gradient has a temperature of
about 270°F at 3 miles depth). If the fault maintains
porosity and permeability, this heated water can be
forced to the surface (or near surface) and become a
geothermal spring.
There are numerous sedimentary basins in Alaska,
the most famous of which underlies the North
Slope and hosts the Prudhoe Bay oilfield. Excellent
porosity and permeability can be maintained in
sedimentary rocks at depth, and if the geothermal
gradient is sufficient, hot fluid can be produced
from these formations. For example, the reservoir
temperature at Prudhoe Bay at 7500 to 8000 foot
depth is approximately 180oF to 200oF. Depending
on the geothermal gradient of the basin and the relic
permeability at depth, production of this hot water
may become a viable small-scale energy source
for oilfield operations, or even for communities in
the immediate area. The high cost of drilling and
permeability enhancement, along with relatively
low geothermal temperatures, makes these resources
difficult to economically develop on a stand-alone
basis.
138 139138139
Enhanced Geothermal Systems (EGS)
Technology Overview (Steam & OCR)
In making electricity from geothermal steam or
hot water, two basic types of equipment convert the
heat energy into electrical energy. If the geothermal
fluid temperatures are greater than about 350oF, a
conventional low-pressure steam turbine is utilized.
As the steam passes through a series of blades
known as a rotor, the pressure is reduced. The
steam expands, thus spinning the rotor. The rotor is
attached by a straight shaft to a generator that spins
and makes electrical power. In a few rare places in
the world, geothermal production wells flow steam
with no water. The steam is transported directly
from the well to the turbine. In most cases a mixture
of steam and hot water is produced by the well,
and the water must be removed with a separator so
that only pure dry steam enters the turbine. The
geothermal liquid and the condensed steam are sent
to an injection well, where they are returned to the
reservoir to be utilized again and again. Essentially,
a geothermal power plant ‘mines’ heat from a
geothermal reservoir.
If the geothermal fluid temperatures are less than
about 350oF, a different type of turbine is needed.
Instead of steam passing through the turbine, a
lower-boiling-point liquid, a working fluid such as
isobutene, isopentane, or a refrigerant, is heated in a
heat exchanger by the geothermal water. It becomes
a vapor and is then sent through a turbine. No water
(either as liquid or steam) passes through the turbine
in this instance. Once through the turbine, the vapor
is condensed and pumped back through the heat
exchanger again and again. The geothermal fluid
in this case is also returned to the reservoir to mine
more heat.
Most of the earth is not near volcanoes or major
active faults so it lacks open space or fractures
that can heat the fluids necessary for a shallow
geothermal system. The geothermal industry has
long known that developable heat exists within
drillable depths in most areas of the globe, yet a
technically economically feasible way to transfer
that heat to the surface in economic quantities has
been elusive. If this methodology can be developed,
a tremendous energy resource can be tapped. One
interesting aspect of this research effort is the use of
techniques developed by the oil and gas industry to
fracture rocks far below the surface, Huge volumes
of fluid are pumped at high pressure into the deep
strata. The theory is that once the rocks are broken
and permeability is established, it is possible to
pump cold water down one hole into hot rocks and
recover it from a second hole located thousands of
feet away. If all goes according to plan, the water
will mine heat from the fracture surfaces between the
two holes. It will become hot enough to utilize for
direct use and/or electrical power generation. This
concept is called enhanced geothermal system, or
EGS.
Projects are now operating in France, Germany, and
Austria, where six small EGS projects are generating
between 0.25 MW and 3.5 MW of electrical power
from wells between 7000 feet and 16,000 feet deep
and at temperatures from 300oF to 500oF. After the
power is generated, additional heat is sometimes
removed from the water for space heating as a
part of some of the projects. These expensive,
government-supported research projects have taken
many years to develop. With this experience in hand,
Germany has recently announced plans for over 100
future projects with outputs as high as 8.5 MW for
some of them. In Australia numerous press releases
tout much higher potential megawatt outputs, but no
projects are yet on line.
138 139138139
Enhanced Geothermal Systems (EGS)
Alaskan Resource Potential
Relatively little is known about the most effective
methods for implementing an enhanced geothermal
system. Many variables such as the temperatures,
the temperature gradient, the type and characteristics
of rocks present, and the existing stresses on
the rocks, need to be considered in planning an
enhanced geothermal project. Within Alaska there
must be some areas where the overall conditions are
more favorable for such a project than other areas.
Each area is unique, and all variables need to be
assessed to determine the feasibility of an enhanced
geothermal system. Development of enhanced
geothermal systems will continue to be mostly
experimental in the next years. The EGS concept
bears close watching because enhanced geothermal
systems could be part of Alaska’s future.
Known Geothermal Areas:
Alaska has a number of documented shallow
sources of heat along its southern margin and in the
central part of the state. For physical and economic
reasons many of these resources are under-explored
and undeveloped. These known geothermal areas
range from modest temperature thermal springs
like Pilgrim, Chena, and Manley to large areas of
hot springs found on or near active volcanoes. The
locations of all major thermal springs in Alaska
have been identified, but some lack basic descriptive
information such as flow rate and geochemistry.
These springs represent a thermal and mass
discharge point from a geothermal system that may
support development.
Blind Geothermal Systems:
Blind geothermal systems are those without surface
manifestations. These systems are the subject of
much debate within the geothermal community.
Whether blind systems exist in Alaska is unknown
at this time. Precious little subsurface temperature
data exist to indicate the presence of such systems.
Nevertheless, a significant amount of additional
geologic information is available to help determine
if an area is likely to contain such anomalous
features. In the absence of detailed thermal gradient
information is impossible to say categorically
that small geothermal anomalies do not exist, but
substantial supportive geologic information can help
in the evaluation of potential areas for exploration.
Project Information140 141140141
In order to put together a geothermal power
plant project, details about the resource and
where and how the electricity will be consumed
must be known. In the simplest possible case
(similar to the case of Chena Hot Springs
Resort), a small amount of power is developed
and used within a small area by the owner of
the resource. However, ownership is often
complicated when the surface and subsurface
(including the geothermal resource) are owned
by different entities, or when there are numerous
landowners in the vicinity of the site.
Developing a geothermal resource includes a
number of critical steps that must be strictly
adhered to. The first and most important step
is that of identifying and characterizing the
resource potential and capabilities for economic
power generation. The simple occurrence of a
hot or warm spring at the surface is not sufficient
evidence for a developable resource. The size,
flowability, sustainability, and ultimate heat flow
are all difficult determinations that must be made
with great care. The initial exploration phase can
be costly and has a high risk of economic failure.
The exploration and development phases
needed to characterize and sanction power plant
construction will involve procuring permits,
expertise, and equipment to collect and interpret
data on geology, geochemistry, geophysics,
and temperatures, so that wells can be sited and
drilled into the reservoir. Once one or more
wells have been drilled and the reservoir is
identified, flow testing and reservoir engineering
assessments are needed to determine the possible
size and productivity of a reservoir, and also to
determine how the reservoir will be produced
and managed. At this time, the power plant can
be designed and equipment can be chosen to best
suit the reservoir. Adequate financing will be
needed for construction of the power plant and
any transmission line.
After the power plant is built and in operation,
reservoir monitoring and management are needed to
optimize the system and to determine strategies for
maximizing the life of the resource. It commonly
takes ten years from the start of exploration to
the commissioning of a power plant for projects
exceeding 10 megawatts in capacity. Small projects
of < 1 megawatt to 2 or 3 megawatts can be
completed in 2 or 3 years.
Operational geothermal power plants have an
excellent worldwide record of reliably producing
power for decades with modest environmental
impacts and low operation and maintenance costs,
provided that the resource is properly managed and
not overdeveloped.
140 141 Project Information140 141
Potential Reduction in Cost of Energy
Most geothermal resources that could now be developed in Alaska are larger than needed to satisfy
local demand, or significantly remote requiring substantial investment in transmission lines. According
to the paper, ‘Factors Affecting Costs of Geothermal Power Development;’ published by the Geothermal
Energy Association, capital costs for a geothermal project can be broken down as follows. It is important
to note that these relative costs can vary significantly depending on remoteness of the resource and access
to equipment and technologies:
Total capital costs, including all elements of development shown in the figure above, ranged from
$3000 - $3900 per kW for a large (100MW) plant in 2007 dollars. A smaller plant, such as the one
installed at Chena Hot Springs, is expected to cost more. Considering exploration and all other elements of
the Chena project, the total capital cost of the project was $6275 per kW.
Operating and maintenance costs for a geothermal power plant are an estimated $15 MW-$30 per MW, or
1.5¢-3¢ per kWh. For the Chena project, O&M costs were calculated at 2¢ per kWh.
142 143142143
Manufacturer Options
Manufacturer Options
The following lis a ist of manufacturers and engineering firms who build geothermal turbines and/or power
plants:
Manufacturer/
Contractor Location Device Name Website
Steam
Turbine or
Binary
Fuji Electric
Group Japan Steam turbines www.fujielectric.com Steam
Mitsubishi Japan Steam turbines www.mitsubishitoday.
com Steam
Toshiba Japan Steam turbines www3.toshiba.co.jp Steam
Ormat Israel Geothermal
turbines www.ormat.com Both
Rotoflow USA Geothermal
turbines www.rotoflow.com Binary
Mafi-Trench USA Geothermal
turbines www.mafi-trench.com Binary
United
Technologies USA Geothermal
turbines www.utc.com Binary
Power
Engineers Idaho Plant design and
construction www.powereng.com Both
Geothermal
Development
Associates
Nevada Plant design and
construction www.gdareno.com Both
The Industrial
Company Colorado Plant design and
construction www.tic-inc.com Both
Processes
Unlimited
International
California Plant design and
construction www.prou.com Both
Manufacturer Options
142 143142143
Current Activity in Alaska
Chena
Hot Springs
Northeast of Fairbanks, Chena is home to the only operating
geothermal power plant in Alaska. See the case study for more
information.
Pilgrim
Hot Springs
Pilgrim was the site of another Department of Energy drilling
program. The resource appears to have development potential
using binary power generation equipment, but the source of
the geothermal fluid was never identified. Pilgrim is located
approximately 50 miles from Nome, and a recent study suggests
that if proven adequate, it may be economical to develop the
resource to supply power to Nome.
Unalaska
The Makushin geothermal resource near the community of Dutch
Harbor on Unalaska (Aleutians) is the only proven high temperature
geothermal system in Alaska that could be used for power
generation. An exploratory drilling program, which took place in
the early 1980s and was funded by the Department of Energy, made
this determination.
Akutan
The community of Akutan (Aleutians) is considering options
for developing a nearby resource located in Hot Springs Bay,
approximately 10 miles from the community.
144 145
Current Activity in Alaska
Naknek
The Alaska Peninsula community of Naknek is conducting a
geothermal exploration program.
Manley
Hot Springs
Manley, on the Tanana River, is a resource similar to the one at
Chena. It has the potential to supply 100% of the power and
possibly the heat to the community; however, the project is
complicated by land ownership issues.
Mt. Spurr
The Mt. Spurr volcano, across Cook Inlet from Anchorage, is a
unproven resource, but its proximity to Anchorage, makes it worth
further assessment. Ormat, a geothermal developer and power
plant manufacturer, recently won a competitive bid process and
purchased all but one lease section on the volcano.
Other regional assessments have been proposed, as well as development of other resources. However, no
additional activity has taken place at other sites in the past 10 years.
144 145
Case Study: Chena Hot Springs Resort
Chena Hot Springs Resort is a privately owned
facility located 60 miles northeast of Fairbanks.
Chena is located 33 miles from the nearest electric
grid and maintains its own generation facility and
approximately 3 miles of distribution lines. Prior to
2006, Chena used diesel engines to supply power to
the site, with an average load of 180 kW. In 2006,
Chena installed a 400 kW geothermal power plant
consisting of two 200 kW PureCycle 200 modules
designed and manufactured by United Technologies
Corporation. Chena is currently in the process of
installing a third 280 kW production model PureCycle
200, for a total installed capacity of 680 kW.
The power plant is unique because it was designed
to work using geothermal fluids at 165°F, which is a
significantly lower temperature than that of the fluids
used at other geothermal sites for commercial power
generation. The United Technologies equipment is
based on refrigeration components from its subsidiary
company, Carrier Refrigeration. Originally designed
for industrial waste heat applications, the power
plant modules were and modified for this geothermal
application. In the winter, the units are air cooled or
water cooled (via a cooling pond installed in 2008),
and water cooled in the summer. Project capital costs
totaled $1,926,962, which was partially offset by a
$246,288 grant from the Alaska Energy Authority.
This included the drilling of a geothermal production
well, but it did not include any exploration costs.
Those were partially covered under a Department
of Energy grant. The project also used numerous
recycled components including 4200 ft of pipeline and
a 1.5 MWh UPS system, which reduced the cost of the
project significantly.
During its first 27 months of operation, the power
plant logged 18,722 hours at 99.4% availability,
excluding five weeks of repairs after a fire occurred in
the building in May 2007. During this repair period,
the unit operated with an average capacity factor of
87%, with an average net output of 174 kW per unit.
The reduced capacity factor is due to flow rates on the
hot water side averaging approximately 60 gpm below
the rate for which the system was designed. When
both units are online, this flow rate is further reduced
per unit for a total plant output of 280 kW (70%
capacity factor). The power plant is designed to be
dually cooled, using cold water in the summer, and air
or water in the winter. During intermediate seasons,
unit output has been reduced as a combined effect
of less available cooling water flow and inefficient
operation of the air-cooled condensers at temperatures
above 0 °F-10 °F. This issue should be mitigated by
the installation of a cooling pond in 2008.
Installation of the geothermal modules has resulted in
a 50% reduction in gallons of fuel purchased at Chena
(compared with fuel purchases prior to the installation
during times the power plant was operating). Greater
fuel savings have not yet been realized, because
the generators were designed to be grid connected,
they use induction generators that require a stable
frequency and voltage to operate properly. A 1.5
MWh UPS system was installed to provide grid
stability, but there were initial problems integrating
it into the existing power generation system. This
resulted in challenges with completely eliminating the
diesel engines and operating both power plant modules
simultaneously without overpowering the grid. For
this reason, in 2007 and the first half of 2008, only one
power plant module was typically in service at a time,
and thus actual fuel saving were just half of what was
expected. This issue has been resolved, and now both
units are operating for a total net output of 280 kW.
The third unit, a larger 280 kW PureCycle module, is
expected to be online by the end of 2008, bringing the
total installed capacity to 680 kW.
Overall fuel offset in the first 26 months of operation
was 228,000 gallons for a total savings of $650,873.
146 147
Above: The 400 kW geothermal power plant at Chena Hot
Springs. Named the Chena Chiller. This unit is unique in
that it is designed to work with geothermal fluids much
cooler than any other plant.
Right: This artesian well is located at Chena Hot Springs
Resort and flows at around 300 gpm.
Facing page top: An old greenhouse at Chena Hot Springs
is surrounded by naturally heated water.
Facing page bottom: An injection well is being drilled for
the geothermal power plant at Chena.
Case Study
146 147
Chena Hot Springs Resort
This takes into account a 116% increase in site load,
to an average of 430 kW since installation of the
geothermal power plant. This increase is due to the
installation of a production greenhouse (75 kW load),
the addition of electric appliances in the hotel rooms
and restrooms, addition of plug-ins for vehicles, and
an increase in site pump loads. Assuming output
remains constant, the simple payback at current (2008)
fuel prices will be realized in just over 6 years (the
end of 2012) from the date of installation. O&M
and debt load for the project are currently $73,500
per year. The addition of these values results in a net
payback of 8 years from an installation date at the end
of 2014. This could be reduced to 5 years if all units
are operated simultaneously and greater fuel savings
are realized.
Chena is also planning to drill a deeper well in 2009
to access the deeper reservoir to produce higher
temperature fluids. This improved efficiency of the
power plant will reduce the total volume of water
required for operation.
148 149148149
It could be argued that geothermal energy is
one of the most sustainable and environmentally
friendly energy resources that can be developed.
Unfortunately, geothermal heat needs to be close
enough to the surface and in the right geologic
setting to make it economically feasible for
development. This rare occurrence in Alaska. It
is tantalizing to presume that if one drills deep
enough there will be a heat resource that can be
exploited, but experience in the development
of deep subsurface fluid flow systems shows a
sobering reality regarding the extreme costs and
risks associated with these activities. Nevertheless,
in areas where large geothermal resources are
present and relatively easily accessible, geothermal
electrical power generation has been shown to be
cost competitive with large-scale coal, natural gas, or
nuclear power generation. In remote areas, such as
the islands of Indonesia, Japan, and the Philippines,
where other forms of energy are expensive and
difficult to come by, geothermal power generation,
is the dominant method of power generation and
some fields have now been operating for almost
50 years. The primary challenge for developing
geothermal power when the potential exists is
locating, developing, and managing the resource in
an economic manner.
With continued research and development, a
wide variety of geothermal power plants has been
designed and built to operate on a wide variety
of resources with temperatures ranging from
165OF - 650OF. Continued research in areas such
as EGS will be important in furthering the value
of geothermal energy as a substantial energy
alternative.
As new technology is brought forth, the geothermal
resources present in Alaska should be constantly
evaluated and developed where physically and
economically feasible. The remote location of
a number of geothermal resources relative to
population centers and transmission grid is a difficult
hurdle to overcome. In Alaska, developing strategies
for using geothermal resources is likely to prove as
difficult as actually developing the resources, yet
given the potential, this development is well worth
the effort.
Conclusions
Create regional geothermal development plans •
to combine resources (drill rig, exploration
equipment, expertise)
Consensus is that power is highest use of •
geothermal in power generation, however there
should also be an assessment of the potential
for other uses such as for greenhouses (food
production), mineral processing center operation
in Aleutians, absorption chilling, and producing
alternative fuels. Mineral recovery from
geothermal brines is also a possible area for
research
Develop a state drilling program as part of the •
state energy plan
Put together set of criteria that helps rank and •
prioritize projects throughout the state
Consider ground source heat pumps in areas •
where appropriate
Alaska Geothermal Working Group
Recommendations:
148 149148149
Conclusions
References
Alaska Energy Authority Geothermal
Webpage: http://www.akenergyauthority.org/
programsalternativegeothermal.html
The Geothermal Resources Council in Davis, California
(www.geothermal.org) has an excellent website devoted to
geothermal development. For its members it has the most
extensive on-line library in the world. A second website
for accessing technical geothermal papers is the U. S.
Department of Energy Office of Scientific and Technical
Information (www.osti.gov).
Hance, C., (2005), Factors affecting costs of geothermal
power development, Geothermal Energy Association,
Washington DC.
The Future of Geothermal Energy – Tester et. al. Published
by the MIT press, 2006.
Nome Energy Study
150 151150151EvaporatorCondenserHeat out Heat in
Compressor
Expansion Valve
Basic Heat Pump Configuration
Heat pumps for space and water heating,
while increasingly common in the Lower 48, are
often overlooked in Alaska. Most systems are
designed to provide space heat in the winter and
air conditioning in the summer. Traditionally, they
have been installed in moderate climates, often in
buildings that would otherwise use electric resistance
heating. Now several varieties of heat pumps are
available for colder climates and may be suitable
for use in Alaska. Ground-source heat pumps differ
Heat Pumps for Space Heating
Introduction
from traditional geothermal heating; they can be
installed across a wide range of geographic locations
and ground temperatures. In contrast, traditional
geothermal heating is restricted to relatively confined
areas with abnormally high temperature gradients,
such as near hot springs, and can thus be used to
heat indoor spaces without the use of a heat pump.
Approximately 50,000 Ground-source heat pumps
and over 500,000 total systems are installed in the
United States each year.
AEA Program Manager: David Lockard (771-3062)
150 151150151
Heat pumps, while electrically operated, are
distinctly different from resistance electrical heaters.
Heat pumps are devices that transfer heat from a
lower temperature reservoir, usually the ambient
environment, to a higher temperature sink. The low
temperature reservoir is usually the air, the ground,
or a body of water, and it is essentially an unlimited
source of heat. This heat, while unlimited, does not
come without cost; work in the form of electricity is
required to pump it to the high-temperature sink.
Heat pumps work on the same principle as
refrigerators and air conditioners. All remove heat
from a cold temperature source and pump it to a
higher temperature sink. The difference is simply in
the desired effect – cooling vs. heating.
A simplified heat pump contains four main parts: a
cold source heat exchanger called the evaporator,
a compressor, a high-temperature heat exchanger
called the condenser, and an expansion valve. This
system is filled with a working fluid, such as the
refrigerant R-410A. A diagram of this system is
shown on the previous page.
In the evaporator, heat is absorbed, vaporizing
the refrigerant. This vapor is then compressed,
raising its temperature and pressure. The now hot
refrigerant vapor is piped to the condenser, where
its heat is removed and used for heating. During
this heat transfer process, the refrigerant condenses
back to a liquid. This liquid then passes through
the expansion valve to the low-pressure side of the
system, and the cycle repeats.
The effectiveness of a heat pump is called its
Coefficient of Performance (COP). The COP is the
ratio of heat output to work input. For example, a
heat pump operating with a COP of 5 will produce 5
kWh of heat for every 1 kWh of electricity supplied.
For this reason, the ‘efficiency’ of a heat pump is
often listed as greater than 100%.
The COP is largely dependent on the temperature
difference between the source and sink, and the
greater the difference, the lower the COP. For
example, a heat pump operating between a ground or
air temperature of 45°F and an inside temperature of
70°F has a much higher COP than the same system
operating between 0°F and an inside temperature of
70°F. Typical COPs for heat pumps tend to be in the
range of 1.5 to 6. This is sometimes described as an
efficiency of 150% – 600%.
Heat pumps are classified as either air-source heat
pumps or ground-source heat pumps. Air-source
heat pumps, as their name implies, extract heat
from the ambient air. They are the easier and less
expensive type to install. Because the COP is a
function of the outdoor air temperature, it will vary
widely. This variable COP shows one of the air-
source heat pump’s main disadvantages in cold
climates – peak heating demands coincide with the
unit’s lowest COP. Heat is therefore most expensive
when it is most needed. Nonetheless, there are a
number of recent innovations that have led to the
development of air-source heat pumps suitable for
use down to 0°F.
Ground-source heat pumps have been in use since
the late 1940s and use the relatively constant
temperature of the earth instead of the outside air for
the heat source. This allows the systems to operate
with a higher COP in colder weather, making them
more appropriate for use in much of Alaska. As
with air-source heat pumps, the COP is highest when
the difference between the ground temperature and
indoor temperature is lowest. Therefore, the colder
the ground, the less efficient the system.
There are many configurations for ground-source
heat pumps, including an open loop heat pump that
pumps water directly from a well or body of water
and extracts heat before returning the water back
to the same water body or to another one. A dual
source heat pump combines an air-source heat pump
with a ground-source heat pump.
Heat Pump Technology Overview
Project Information152
Heat pumps have been installed in several
parts of the state, including the Mat-Su/
Anchorage area, Juneau, and Kodiak. There
have also been a few systems installed near
Fairbanks, but these were primarily prototype
installations and cost savings have not yet been
demonstrated.
Ground-source heat pump installations require
either horizontal or vertical installation of
heat exchanger loops below the ground. This
requires significant heavy equipment, which
may not be readily available in many parts of
the state. For example, a drill rig is needed for
vertical installations. In addition, these systems
still require electricity to operate and become
expensive to operate in areas where the cost
of electricity, relative to fuel, is high. They
may also be unsuitable for use in areas with
permafrost, or where removing heat from the
ground might result in permafrost growing or
heaving. The combined high installation costs
and potentially high operating costs may make
these systems inappropriate for rural Alaska;
however, they can prove economic in some road-
accessible areas of the state.
There are several installers of heat pump systems
in Alaska, and local engineering firms can often
design a system for a particular application.
Expected payback period for an appropriately
designed ground-source heat pump is 5–10 years.
System life is estimated at 25 years for the in-
home components and 50+ years for the ground
loop.
System retrofits in areas with oil as the primary
heating source and with electrical costs under .13
per kWh have proven to be viable with oil costs
above $2 per gallon. Conversion costs range
from $25,000 to $30,000 for systems coupled to
existing oil boilers with under floor radiant heat
distribution already in place. The existing oil
boiler acts as supplemental or backup heat for
these installations. Systems also come configured
for forced-air heating with the air handler built into
the unit. There would be no backup heat for this
type of installation, since the unit would take the
place of the existing oil-fired air handler equipment.
Hence, sizing would need to be adequate for the
complete heating load of the home, or other backup
systems such as electrical resistance heaters would
be needed.
In organized cities and service areas permits are
required for any heating installation. Lake loops
generally require a permit process with several
governmental agencies involved, such as the Alaska
Departments of Environmental Conservation (DEC),
Natural Resources, U.S. Fish and Wildlife, and Army
Corps of Engineers.
For open well systems, a less rigorous permitting
process is required from DEC. A pilot project is
currently in place and conditionally approved
for permanent operation. Results from this
pilot project and approval will pave the way for
open well systems to become routine for the
permitting process. Other systems such as closed
loop horizontal or vertical installations are more
routine and have not been subject to permitting in
unorganized areas.
153 Project InformationPotential Reduction in Cost of Energy
Heat pumps in the right application can cut heating
costs. The amount of savings is dependent on the
cost of heating fuel, the cost of electricity, and the
environment in which the heat pump is installed.
Furthermore, a change from combustion based heating
(oil, natural gas, propane, coal, or wood) to heat
pumps will eliminate combustion appliances and their
associated risks, pollution, greenhouse gas emissions,
and maintenance.
Because they are electrically operated, a widespread
shift toward heat pumps will have consequences for
electric utilities; distribution system upgrades may
be necessary to accommodate the increased electrical
demand. Building owners may also have to update
their service entrances to handle the additional
electrical load.
One of the primary factors in evaluating a heat
pump is the cost of electricity and the need for air
conditioning. As a rule of thumb, if the cost of
30 kWh is less than the cost of a gallon of fuel, electric
resistance heating may be more economical than
oil heat. A heat pump installation may be more
economical than oil heat if the cost of 12 kWh is
less than the cost of a gallon of fuel.
However, the capital cost of the heat pump is
often significantly more than the cost of electric
resistance heat or an oil heating system unless
air conditioning is required An example can be
found in the Pacific Northwest. The hydropower
supplied by the dams on the Columbia River
has made electricity inexpensive in that region.
As a result, much of the residential heating is
done electrically, either with heat pumps or with
standard resistance heating. A similar situation
may occur in areas of the Alaska Railbelt that use
oil for heating if, for example, the Susitna Dam is
built.
154 155
The Juneau Airport secured funding in October
2008 to install a ground-source heat system. The State
of Alaska provided a grant for half of the cost of the
project, with the City of Juneau paying for the rest.
The system is designed and will be built by Alaska
Energy Engineering LLC.
The system involves 215 vertical wells, each 175 feet
deep with 0.75 inch high-density polyethylene piping.
The heat pumps will supply both heat in the winter
and cool air in the summer by using the ground-source
heat in a reversible compressor/condenser cycle, with
the primary product being winter heat. Alaska Energy
Engineering estimates a 260% energy efficiency for
the system.
Alaska Energy Engineering has calculated the capital
cost of this project at $6.05 million with annual
electric use of 656,000 kWh and annual O&M costs
of $644,000. This project is being built instead of an
alternative fuel oil system. The fuel oil system would
have lower capital and annual O&M costs ($5.23
million and $268,000, respectively). The fuel oil
system would use 40,825 gallons of fuel and 212,000
kWh of electricity annually. Assuming a fuel oil price
of $3.31 and an electric price of 7.9¢ per kWh, the
ground-source heat project is expected to save over
$85,000 in annual energy costs. Note that the need
for air conditioning is an important contributor to the
economics of this project.
A similar project is proposed that will produce 4.1
billion BTUs annually to meet approximately 81% of
heat load for a new pool in Juneau. It is expected to
cost $2 million and to eliminate either 63,200 gallons
of fuel oil or 1.5 million kWh annually. Annual O&M
costs are estimated at $113,220.
Case Study: Juneau Airport
154 155
Heat pumps may become more common in Alaska
in places that have expensive heating fuels and
relatively cheap electricity. They are relatively easy
to engineer, design, and install; and they can save
energy. A general recommendation on when to install
a heat pump over a traditional system is beyond the
scope of this document. The decision must be based
in part on the available thermal resource, the cost and
availability of electricity, the cost of fuel, and capital
costs. Specific recommendations will vary by region
and are currently done on a case-by-case basis.
References
Alaska Energy Engineering LLC, Ground-source Heat
Pump Feasibility Study: Life Cycle Cost Analysis.
December 2007
http://www.juneau.org/airport/projects/documents/
GroundSourceHeatPumpFeasibilityStudy.pdf
Conclusion
156 157156157
TECHNOLOGY SNAPSHOT: SOLAR
Installed capacity (Worldwide)Solar heating – 128 GigaWatts
Photovoltaic electrical – 7 GigaWatts
Installed Capacity (Alaska)100s of kW
Resource Distribution Statewide, best in areas with less precipitation and
with southern exposure
Number of communities impacted Best use is for individual installations where there is
no grid power
Technology Readiness Commercial
Environmental Impact Minimal, small footprints, no CO2 emissions
Economic Status Payback is dependent on fuel oil prices and local
resource
Solar Energy Technologies
A solar paneled roof makes
efficient use of space and
provides a source of power.
AEA Program Manager: Peter Crimp (771-3039)
156 157156157
158 159158159
Energy technologies that use the sun’s radiation
directly are referred to as solar energy technologies.
These technologies may be employed to heat or
light living space directly, to supply energy to a heat
storage system for later use, or to generate electricity.
Solar energy provides a growing but still small
fraction of energy throughout the world. To put
solar energy use into perspective, the U.S. Energy
Information Agency estimates that worldwide
electrical generation from all energy sources for
2005 was 18 trillion kilowatt hours. According to
the International Energy Agency, worldwide solar
photovoltaic electrical generation was approximately
7.7 billion kilowatt hours in 2006, about 0.05% of
total electrical generation. Likewise, heating energy
produced by solar, while about 10 times that of solar
photovoltaic electric energy production, was also a
tiny fraction of total electrical generation.
Direct use of solar energy for heating or lighting
is often referred to as passive solar use. The term
passive is used because a building employs solar
energy by virtue of its design without requiring
additional equipment to actively move or store
energy. In other words, passive solar systems use the
energy of the sun where it falls. A clothesline is a
simple example of a passive solar energy device. In
this same way designers strive to employ generally
conventional materials and building components to
advantageously use the sun’s energy in buildings.
Implementing a passive solar energy strategy
involves many decisions, from the location of the
building and its overall shape, to the placement
of windows and skylights, to the materials to be
used inside the structure. In temperate latitudes this
functions well. There is a pronounced daily solar
cycle. The days are not inordinately short in the
winter, and there is a regular cycle of warmer days
and cooler nights.
Technologies that use equipment to move or store
solar energy from where it is incident to somewhere
else are referred to as active solar systems.
Examples of these active system technologies are
hot water systems where water is heated and the
heat is stored in a reservoir, systems where high
temperatures are generated to produce steam to
generate electricity through conventional steam
turbines, or photovoltaic systems where solar energy
generates electricity directly in a semiconductor
solar cell.
The solar resource in Alaska is significant, but it
varies dramatically with the latitude, time of year,
and weather. In the northernmost portions of the
state, there is abundant sunlight up to 24 hours per
day in June, with no sunlight in December. In less
extreme northern latitudes, the resource potential is
distributed over a greater portion of the year. If solar
energy is used for lighting, systems can be optimized
for direct sunlight or for diffuse sunlight when skies
are overcast, but the strategies differ; it is important
to design for the condition that predominates.
When solar energy is used for heating or electrical
generation, direct sunlight is the most effective form
of solar radiation to use. In either case, building
systems must be able to operate with or without the
solar resource.
Major challenges to using solar energy in Alaska
are its seasonal variability and its dependence on
weather conditions. In general, the solar resource
is most abundant in the summer, when it is least
needed. However, there is a reasonable resource
available for seven to eight months of the year for
all but the most northern areas of the state. Direct
heating and daylighting with the sun require minimal
technology, but they rely on good building design
to prevent overloading in the summer months and
to promote energy gathering during the shorter days
closer to the winter season.
Introduction
158 159158159
Two major factors should be considered when
employing solar energy in Alaska: the abundance of
sunlight when the energy is needed and the cost of
other forms of energy. Technologies other than solar
must carry the load during the dark times of the year
in Alaska. For this reason, the addition of a solar
auxiliary system will not reduce the capital cost of a
primary heating or electrical system. Primary systems
must be designed to operate for months without
benefit of significant solar input.
Active systems hold the most promise for Alaskan
applications. These are systems that can store
energy for longer periods of time or be incorporated
as auxiliary energy sources into existing energy
systems. Active systems also lend themselves to being
controlled automatically. Because of the seasonal
nature of the solar resource in Alaska, passive solar
designs yield only modest benefits, since they cannot
store solar energy for an extended period of time.
Passive solar lighting systems use sunlight only during
the daylight hours. Passive heat systems are generally
effective for some hours (in some cases a few days)
after collecting solar energy, and they often require
active participation in the building operation.
Active solar systems most suitable for Alaska are
photovoltaic systems and solar hot water systems.
Except for specific niche applications, it is unlikely
that photovoltaic electrical generation is suitable
for reducing the cost of electricity in Alaska. Grid-
connected photovoltaic systems offer the most
economical means of generating electricity with
sunlight. At current prices an installed, grid-connected
system in Interior Alaska could produce electricity for
approximately $1.50 per kilowatt hour. Connection
to an electrical grid enables a photovoltaic system to
avoid expensive electrical storage.
The cost of solar-generated electricity in remote areas
with no electrical grid available would be significantly
higher due to the cost of additional batteries and
inverters. There have been only two Alaskan villages
with average electrical kilowatt hour costs over $1 per
kilowatt hour for the past five years. Lime Village,
which has an installed photovoltaic system, has
electrical costs of $1.26 per kilowatt hour. Stony River
pays $1.01 per kilowatt hour.
Solar hot water systems offer more promise in
Alaska than photovoltaic electrical generation does,
although the present installed cost of systems is still
expensive. Solar hot water systems suitable for Alaska
can provide hot water for space heat or for domestic
use. The low density of the Alaskan solar resource
precludes the economical use of high temperature
solar technologies, such as systems that generate
steam to produce electricity. As an example of the
difference between the cost of solar hot water and hot
water from fuel oil, consider a household-sized solar
hot water system with an energy cost spread over
twenty years. The cost of the solar energy would be
approximately $100 per million Btu. The cost of that
same energy from fuel oil, if the fuel price were $6
per gallon, would be about $40. There might be some
rural villages where solar could be an economical
component of an energy system. On the road system,
where fuel oil is less expensive, some might wish to
use solar hot water for reasons other than fuel oil price
alone.
Solar Technologies
160 161160161
Solar holds little promise to economically reduce
Alaska’s dependence on fossil energy. Prices for
solar electric systems and solar hot water systems
make them more expensive than conventional fuel
technologies. Although the fuel is free for solar
technologies, the capital cost is not. It is conceivable
that innovative design for specific applications could
reduce the capital cost of a system. Then the solar
hot water system might be able to economically
offset fuel oil use. Solar hot water systems have
many components that are used in conventional fuel
systems, and the capital cost of the solar systems
is a combination of the costs of these numerous
components. On the other hand, the cost of a
photovoltaic system resides primarily in photovoltaic
panels themselves, and this cost is determined by the
worldwide market. It is unlikely that innovations in
end-use design will significantly change the capital
costs of solar electric installations.
In Alaska, the best candidates for solar use would be
sites off of the road system that operate only in the
summer months.
Conclusions
References
Web-based
The website http://www.alaskasun.org/ has excellent
information, including a number of publications related to
solar installations in Alaska, and a list of contractors and
suppliers.
Other
Werner Weiss, Irene Bergmann, Gerhard Faninger
Solar Heat Worldwide, edition 2008, Markets and
Contribution to the Energy Supply 2006, International
Energy Agency Solar Heating & Cooling Programme,
May 2008.
160 161160161
TECHNOLOGY SNAPSHOT: COAL
Coal Resources (Worldwide)Recoverable coal is approximately 998 billion short tons (2004
numbers)
Coal Resources (National)Approximately 491 billion short tons of demonstrated reserves,
estimated 275 billion tons recoverable (2007 numbers)
Coal Resources (Alaska)170 billion short tons identified resources; approximately 5.6 trillion
short tons of hypothetical coal resources
Resource Distribution (Alaska)Distributed in eight major coal provinces and numerous smaller coal
fields and occurrences
Number of communities with
potential coal resources Over 40
Technology Readiness Proven technology for electrical power generation and space heating
Environmental Impact Surface mining requires reclamation. Combustion for electrical
power generation must meet EPA requirements
Economic Status
Economically mined in Interior Alaska (Healy) for power generation
and some space heating, active coal exploration in Western Arctic,
Cook Inlet and Alaska Peninsula
Alaska Coal Energy Resources
The coal powered heat plant at UAF as
seen during Winter Solstice.
AEA Program Manager: Mike Harper (771-3025)
162 163162163
Coal is a brownish-black to black combustible
organic sedimentary rock formed by the
decomposition of plant material, most often in
a swampy or boggy environment. This organic
material or peat is buried, compacted, and hardened
over millions of years. This process is called
coalification. During
coalification, peat
undergoes several changes
as a result of bacterial
decay, compaction,
heat, and time. Peat
deposits vary and contain
everything from pristine
plant parts like roots, bark,
spores, etc. to decayed
plants. In coalification,
peat passes through four
main phases of coal
development: lignite,
sub-bituminous coal,
bituminous coal, and anthracite. These end products
are composed primarily of carbon, hydrogen,
oxygen, and some sulfur along with water moisture
and non-combustible ash. The amount of carbon and
volatiles (water and gas) as well as the amount of
energy content of the coal determine its rank. The
amount of energy in coal is expressed in British
thermal units (Btu) per pound. The higher the rank,
the greater the heating value.
Based on reliability of data, coal resources are
classified into four classes that depend on standard-
distances-from-points-of-thickness measurements.
These are (1) measured, (2) indicated, (3) inferred,
and (4) hypothetical. These four classes of coal
resources are based on degree of geologic assurance
that the rank and quantity of a coal seam (or seams)
have been estimated from high (measured) to lowest
(hypothetical). Identified coal resources include
measured, indicated, and inferred coal resources.
In general, hypothetical resources are located within
broad areas of known coal fields where points
of observation are absent and evidence is from
distant outcrops, drill holes, or wells, and where
coal may reasonably be expected to exist in known
mining districts under known geologic conditions.
Additionally, the
classification of coal
resources is based on
the mineable thickness
of the coal seam.
The United States is
estimated to contain
30% of the world’s coal
resources. Alaska is
believed to hold about
half of that. Most coal
resources in Alaska
are in the hypothetical
resource class because
they have been poorly studied, there are few data
points of measurement, and there has been little
or no drilling to substantiate resource estimates.
Identified resources are about 170 billion short
tons; however, coal-bearing strata underlie about
9% of Alaska’s land. The state’s total hypothetical
resources of coal are estimated to exceed 5.6 trillion
tons.
Introduction
Summary of Total Alaskan Coal Resources
Resource
Category
Total Resources
(in millions of short tons)
Measured resources 6,500
Identified resources 170,000
Hypothetical
resources 5,600,000
Source: Kentucky Geological Survey, http://www.uky.edu/KGS/coal/coalform.htm
162 163162163
The major coal provinces in Alaska are Northern
Alaska, the Nenana area, the Cook Inlet-Matanuska
Valley, the Alaska Peninsula, and in the Gulf of
Alaska and the Bering River. Potentially significant
identified coal resources are present in other
coalfields on the Seward Peninsula, Yukon-Koyukuk,
and Upper Yukon provinces. Numerous smaller coal
basins and minor coal occurrences are distributed
from southeast Alaska to the interior parts of the
state. With a few exceptions, most Alaska coal is
low in sulfur, in many cases containing less than
0.5%. Alaska coals also exhibit low metallic trace
elements, good ash-fusion characteristics, and low
nitrogen content making them favorable for meeting
environmental constraints on combustion in power
plants.
Overview of Alaska’s Coal Basins
Alaska’s coal is dominantly bituminous of
Cretaceous age, or sub-bituminous of Cretaceous
and Tertiary age. Except for Mississippian coal of
the westernmost Northern Alaska Province, Alaska
coal resources formed in widespread deltaic and
continental depositional systems during Cretaceous
and Tertiary time. The younger Tertiary age coals
formed within sedimentary basins are related to
fault systems with complex gravity and strike-
slip motions that controlled basin formation and
influenced deposition by differential settling.
Right: A residential
coal-fed boiler in Healy.
164 165164165
Identified Alaska Coal Resources by Province
Millions of
Province/Coal Field short tons Coal Rank
Northern Alaska province
High-volatile bituminous & sub-
bituminous; extensive lignite and minor
anthracite
150,000 (Identified resources.)
~3,600,000 (Hypothetical resources)
Cook Inlet-Matanuska Province
Beluga and Yentna fields 10,000 Sub-bituminous
Kenai field (onshore only) 320 Sub-bituminous
Matanuska field 150 High-volatile bituminous to anthracite
Broad Pass field 50 Lignite
Susitna field 110 Sub-bituminous
Nenana Province
Nenana basin proper 7,000 Sub-bituminous
Little Tonzona field 1,500 Sub-bituminous
Jarvis Creek field 75 Sub-bituminous
Alaska Peninsula Province
Chignik and Herendeen Bay fields,
Unga I. 430 High-volatile bituminous
Gulf of Alaska Province
Bering River field 160 Low-volatile bituminous to anthracite
Yukon-Koyukuk Province
Tramway Bar field 15 High-volatile bituminous
Upper Yukon Province
Eagle field 10 Sub-bituminous and lignite
Seward Peninsula Province
Chicago Creek field 4.7 Lignite
Overview of Alaska’s Coal Basins
164 165164165
Overview of Alaska’s Coal Basins
166 167166167
Coal was officially discovered in Alaska in
1786, with the first documented production in
1855. Small-scale mining is recorded at numerous
sites throughout the state, with local mines being
developed to fuel river steamboats, placer gold
mines, and canneries before 1900. Significant
production began in 1917 after extension of the
Alaska Railroad into the Matanuska coalfield,
and by 1968, more than 7 million short tons of
bituminous coal had been mined from the Matanuska
coalfield, most of it for electrical power generation.
Significant mining in the Matanuska field ceased in
1968, when Cook Inlet natural gas replaced coal for
electrical power generation in the Anchorage area.
Since the end of World War I, coal has been mined
continuously in the Healy coalfield, which is within
the Nenana coal province. Alaska’s only operational
coal mine today, the Usibelli Coal Mine, produces
sub-bituminous coal from its Two Bull Ridge mine
site near Healy, with an output of 1.357 million short
tons of coal in 2007. Usibelli shipped over 308,146
short tons of coal to Chile and supplied six power
plants in interior Alaska with approximately 900,000
short tons of coal.
In 2007, BHP Billiton Ltd. drilled nine holes in the
western Arctic coalfields on land owned by Arctic
Slope Regional Corporation. The purpose was to
test the thickness of the coal seams and evaluate the
quality of the coal in the historic Kuchiak Mine area,
first tested in 1994. Exploration continued in 2008,
and BHP also began environmental baseline studies
and initiated cleanup activities at the Kuchiak Mine.
PacRim Coal LP has also been active with continued
environmental, permitting, and engineering work
on the Chuitna Coal project west of Anchorage, on
the north side of Cook Inlet. The project is being
designed to mine 3 to 12 million short tons of coal
per year from proven reserves of over 770 million
short tons.
Historical and Current Production and Exploration
166 167166167
Alaska has vast resources of high quality, low
sulfur coal that has great potential for providing
energy locally and for export. Technology exists for
extracting coal and for generating both electricity
and space heating from it. The economics of coal
mining through electrical power generation and
space heating are well known for a given resource
base. These economic models can be extrapolated
for the economy-of-scale necessary for rural
settings. Mine-mouth electrical power plants can
greatly reduce the need to transport large volumes of
coal, and electrons can be transmitted to a number
of communities via power lines rather than by
hauling coal over great distances. Because there
is a lack of detailed information on bed thickness
and lateral extent of coal seams in many of Alaska’s
coal provinces, the total volume of identified coal
resources suitable for mining remains much lower
than what is likely present.
References
American Society of Testing Materials (ASTM),
1995, Standard classification of coal by rank: ASTM
designation D388-82, Philadelphia, 1995 Book of
Standards, v. 5.05, pages 168-171.
Clough, James, 2002, Coal Geology of Alaska, in 2002
Keystone Coal Industry manual, Chicago, Illinois,
Primedia, p. 488-496.
How is Coal Formed? February 26, 2006, Kentucky
Geological Survey, University of Kentucky, http://www.
uky.edu/KGS/coal/coalform.htm
Merritt, R.D., and Hawley, C.C., 1986, Map of Alaska’s
coal resources: Alaska Division of Geological &
Geophysical Surveys Special Report 37, 1 sheet, scale
1:2,500,000
Wood, G. H., Jr., Kehn, T.M., Carter, M.D., and
Culbertson, W.C., 1983, Coal Resource Classification
System of the U.S. Geological Survey. U.S. Geol.
Surv. Circ. 891, 65 pages.
Conclusions
A coal seam shows through an
eroded bank near Healy.
168 169168169
DNR Program Manager; Robert Swenson, 451-5001
Natural Gas
TECHNOLOGY SNAPSHOT: NATURAL GAS
Current Production (US)Over 25 trillion cubic feet annually
Current Production in Alaska North Slope and Cook Inlet, 454 billon cubic feet
Resource Distribution North Slope and Cook Inlet
Some exploration potential in other Basins
Number of Communities Impacted Railbelt and North slope
Technology Readiness Proven exploration and production technology readily
available.
Environmental Impact
Cleanest burning non-renewable. Exploration activity, production
facilities, and pipelines must not adversely affect land and water
resources.
Economic Status Currently economic in Anchorage region and minor railbelt
168 169168169
The term ‘natural gas’ refers to a common and
widespread product of organic decomposition and
it is found in varying quantities in nearly every part
of the planet. Natural Gas is produced in nature
by two distinct methods: (1) organic material is
broken down by bacterial decomposition with the
by-product of methane (such as in peat bogs, land
fills, or the digestive system of cattle), or (2) thermal
decomposition where the by-product is both gas and
liquids (such as coal or organic- rich sediments being
heated up deep within the earth to produce methane,
propane, other heavy gases, and oil).
The key challenge for using natural gas as an energy
source is our ability to economically collect it in
sufficient quantities so that it can be used for heat
and power. Unfortunately, the very common bubbles
seen in lakes and bogs cannot supply enough fuel for
sustained energy production, so it is necessary to find
and tap into a place where nature has accumulated
it over hundreds of thousands of years by a natural
trapping mechanism. The most common forms
of natural accumulation are: (1) conventional gas
reservoirs in porous rock deep within the earth, (2)
thick underground coal seams where the gas is both
trapped and adsorbed to the organic material (coal
bed methane), and (3) a newly emerging potential
natural gas source, hydrates, where the gas molecule
under certain pressure and temperature conditions is
surrounded and trapped by a crystalline structure of
ice.
Natural gas accumulations are a common source of
clean burning energy throughout the world. Natural
gas is used and transported in many forms including
conventional pipeline distribution of gaseous form,
pressurized vessels of liquid propane (LP), and
liquefied natural gas (LNG) as a supercooled liquid
in unpressurized insulated containers. In the United
States natural gas provides nearly 21 percent of the
energy supply, and the US Department of Energy
(USDOE) forecasts that this consumption level will
climb slowly over the next decade, and then start
decreasing through the year 2030 (see figure 2).
The USDOE also reports that natural gas will be the
energy source for 900 of the next 1000 new power
plants being developed in the U.S.
In Alaska, natural gas is used to generate 54% of
the electricity being consumed by industry and
the public. Figure 3 compares the amount of gas
being consumed annually in the Anchorage area
for residential use and power generation. Clearly,
natural gas makes up an important part of the
overall energy portfolio of Alaska and will for the
foreseeable future. The dominant impediment
to increased use of natural gas in other parts of
Alaska is the significant cost of exploration and
development, or of transportation from areas of
large known accumulations to areas where it can be
utilized for heat and power by a smaller population
base.
Introduction
From Alaska Energy Authority, Energy Atlas
170 171170171
Figure 2: Total US consumption and projections of Natural Gas use by sector in Trillions
of cubic feet. From the US Department of Energy
0
10000
20000
30000
40000
50000
60000
70000
Thousand of Cubic Feet MMcf1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007
Year
Residential Consumption
Power Generation
Figure 3: Graph showing consumption of Natural Gas in Alaska for residential and
electricity production for the decade 1997-2007. Data from US Department of Energy.
Introduction
170 171170171
The dominant molecule in most natural gas
accumulations is methane, but in many cases there
are also minor amounts of other hydrocarbons such
as propane, ethane, and butane. Thermally derived
natural gas comes from sedimentary rocks that
contain elevated levels of organic molecules rich
in hydrogen and carbon atoms referred to as source
rocks. The presence of the right kind of source rock
in a sedimentary basin that has been subjected to the
right conditions of burial and increased temperature
may generate a natural gas accumulation, however
many complimentary conditions must be met. To
understand the
requirements for
an accumulation
of natural
gas (and oil),
geologists use the
petroleum system
concept where
a functioning
petroleum system
must include the
following five
elements: 1) source
rock, 2) migration
pathway,
3) reservoir rock, 4) seal rock, and 5) trap.
When source rocks are slowly heated to the right
temperature (between approximately 150°F and
250°F) organic molecules react to form the mix of
chainlike hydrocarbons we call crude oil. Source
rocks heated to temperatures within this range, the
‘oil window,’ are said to be thermally mature for
liquid hydrocarbons, but they commonly also begin
generating natural gas in addition to oil. Source
rocks capable of generating oil are referred to as oil-
prone and are typically derived from marine algae
and other microorganisms. When source rocks are
heated above 250°F they are described as overmature
for oil, but can still generate significant quantities
of natural gas. Source rocks that start out rich in
carbon but leaner in hydrogen (coal, some shale, and
limestone) can generate natural gas, but not the more
hydrogen-rich liquid hydrocarbons found in crude
oil. These types of source rocks are referred to as
gas-prone and typically consist of organic material
derived from land vegetation. These transformations
occur due the rise in temperature with increasing
depth below ground surface; geothermal heat. The
rate at which the temperature increases with depth
is described by the geothermal gradient which, on
average in drilled sedimentary basins of the world,
is about 50°F per 1,000 feet of depth. This means
that the deeper we go beneath the earth’s surface, the
warmer the rocks become. The part of a sedimentary
basin where source rocks are buried deep enough
for temperatures
to be high
enough to cause
these thermal
conversions
is informally
referred to as
the “petroleum
kitchen”.
When
hydrocarbons
are generated
in the kitchen,
their buoyancy
quickly drives them to migrate out of the source rock
following the path of least resistance through the
most permeable strata they encounter. This migration
out of the source rock creates the possibility of
trapping and accumulation in a reservoir rock.
Reservoir rocks are porous and permeable
formations that can store oil and gas in pore spaces
between grains and later allow them to flow out of
the rocks to wellbores, where they can be extracted.
Sandstones, limestones, and dolomites, under the
right conditions, can possess enough interconnected
pores to form good reservoir rocks. Some low
permeability rocks can still function as reservoirs
for natural gas, due to the lower density and greater
buoyancy of gas. In order for the pores in a reservoir
rock to become filled with gas (or oil, if present),
it must be located along a hydrocarbon migration
pathway. If a pathway does not lead to a reservoir
Natural Gas as a Resource
172 173172173
rock, the hydrocarbons may be lost to the surface
environment.
Only where porous and permeable rocks are
enclosed in trapping geometries does gas (and oil,
if present) stop migrating and accumulate in the
reservoir rock to form fields. Effective traps consist
of reservoir rocks overlain and/or laterally bounded
by impermeable seal rock, and are of two basic
types. Structural traps occur where rock layers are
deformed by folding
or faulting to form
concave-downward
shapes capable of
containing buoyant
fluids such as gas.
Stratigraphic traps
occur where porous,
permeable reservoir
rocks are encased
in impermeable seal
rocks as a result
of non-uniform
deposition of
sediments.
For example,
clean sands on
a wave-worked beach may grade laterally into a
muddy offshore setting, and with time, the muddy
offshore zone may migrate over the older beach
sand, setting up a possible future stratigraphic trap,
consisting of a wedge of porous reservoir sands
between the impermeable muds above and below.
Structural traps are usually much easier to identify
and generally host the initial oil and gas discoveries
in a basin. Stratigraphic traps are much harder to
target, and their successful prediction normally
requires more detailed mapping of the subsurface
geology. This is best achieved by interpreting
high-quality, closely spaced seismic data along
with information gained from previously drilled
surrounding wells. In any case, in order for traps to
host gas fields (or oil), they must be created prior to
hydrocarbon generation, expulsion, and migration
from the kitchen. Moreover, they must then remain
intact, uncompromised by later folding, faulting, or
excessive burial.
Coal constitutes a special type of gas-prone source
rock that can generate gas either as a result of the
thermal maturation described above, or through
microbial degradation at shallower depths in the
absence of oxygen. Gas generated through the latter
process is referred to as biogenic gas. In buried coal
seams, biogenic
gas molecules are
typically dissolved in
the surrounding pore
waters and stored
in the coal matrix,
where methane
molecules attach
to coal particles.
As long as the coal
remains buried at
this same depth,
it is subjected to
the pressure of
the overlying rock
and groundwater
(hydrostatic
pressure) and
the methane molecules cannot form bubbles that
can migrate out of the coal. If the coal seam is
subsequently uplifted to shallower depths in the
basin, the hydrostatic pressure is reduced, allowing
the methane to bubble out of solution and migrate
out of the coal seam. Once this migration starts,
the gas follows the path of least resistance, as
noted above, and will either migrate to a reservoir
in a trapping configuration, get stranded in small
quantities in the subsurface, or will eventually
migrate to the surface and be lost to the atmosphere.
Natural Gas as a Resource
172 173172173
Alaska is endowed with enormous proven
natural gas resources. These known resources reside
exclusively on the North Slope and in Cook Inlet
basin. Outside of these two regions, the presence
of natural gas existing in large subsurface traps is
unknown. However, several of the non-producing
sedimentary basins include geologic characteristics
that suggest natural gas accumulations could be
present. These include the Copper River, Kandik,
Nenana, Yukon Flats, and the North Aleutian basin.
These basins are known to include organic-rich
rocks that could be source rocks for natural gas if
buried to depths within the kitchen where thermal
Natural Gas Potential in Alaska
transformation can generate hydrocarbons. The
onshore portion of the Hope basin includes known
coal reserves in the vicinity of Chicago Creek,
southeast of Kotzebue. Coal in this area is lignitic
and submature for thermogenic gas, but under
the right subsurface conditions could generate
biogenic methane. It is not known if the requisite
conditions for biogenic gas generation have been
met in the Chicago Creek area. Other basins have
been recognized around the state, including the
Minchumina, Holitna, and Selawik basins, but their
gas potential is uncertain owing to insufficient high-
quality surface and subsurface data.
174 175174175
Alaska has many sedimentary basins that are
known to include elements required for functioning
petroleum systems. To have a functioning petroleum
system, a basin must include a source rock,
migration pathway, reservoir rock, seal rock, and an
effective trap for gas. Detailed geologic information
is lacking from all of these basins that would allow
realistic evaluation of whether petroleum systems are
present.
Exploring for natural gas in Alaska’s non-
commercial basins will require modern, high-quality
surface and subsurface data. The normal exploration
progression includes conducting detailed surface
bedrock geologic mapping, acquiring reflection
seismic surveys, and finally, probing the most
promising areas by drilling wells evaluated with
modern wireline geophysical log suites. Each
stage of this cycle is typically more expensive
than the preceding step, with costs associated with
a remote exploration program ranging from 40
to 100 million dollars. Currently, legacy datasets
from previous exploration cycles are available
only for limited portions of the Copper River,
Middle Tanana, and Yukon Flats-Kandik basins.
Developing a significant natural gas discovery in
one of Alaska’s non-producing basins could be very
expensive unless the accumulation was located at
a shallow depth and close to both the point of use
(a rural community or group of communities) and
transportation infrastructure. Natural gas discoveries
that do not meet the industry’s commercial economic
metrics due to size, gas production rate, location,
development costs, or other factors, would need to
be evaluated for possible governmental subsidy, or
remain undeveloped.
Natural Gas is a clean burning energy alternative
that enjoys widespread use around the world.
Natural gas is the primary energy source for many
Alaska residents, but because of transportation
difficulty and cost, its use is restricted to the areas
that contain identified fields found during industrial-
scale exploration in the 1960s. The inherent
economic risk and high cost of exploration has
limited the amount of activity in many of the remote
sedimentary basins in the state. Nevertheless, there
are other areas that contain significant potential
and the most economically feasible method of
exploring for natural gas in those areas is to facilitate
industrial scale exploration. The State of Alaska has
a number of programs and incentives that encourage
exploration in these areas, but the economies of
scale has limited the amount of activity. The Alaska
Department of Natural Resources, and the Alaska
Energy Authority are committed to finding ways to
facilitate that activity, and to provide as diverse a set
of energy options for the citizens as possible.
Conclusions Summary
174 175174175
Transmission Lines
Transmission lines are used to deliver electrical
energy from generation source to end-use location.
The electrical energy travels along wires in overhead
lines strung between towers or poles or in under-
ground lines insulated from the earth. The voltage of
the transmission line usually depends on the distance
and the amount of energy being conducted.
Transmission lines can be deployed for several uses:
1) To deliver electrical energy to a distant location
to increase coverage and reduce the overall cost of
delivered energy. AVEC is developing a micro-grid
system that allows for consolidation of generation.
This consolidation can provide reduced overall costs
through delivery of the single generator over a trans-
mission line to a neighboring community. The com-
munities of Toksook Bay, Tununak, and Nightmute
are interconnected through the use of micro-grids.
2) To deliver excess energy to an area that can
utilize it. An example is the Swan – Tyee transmis-
sion line, now under construction, that will deliver
power from the Tyee Hydroelectric project for use in
Ketchikan.
3) To reduce losses. If a single transmission line is
delivering power between two points, adding another
transmission line between those points, adding a sec-
ond line in parallel, will reduce the overall transmis-
sion line losses. The Northern Intertie from Healy
to Fairbanks is an example a second line in parallel
(with an existing line constructed in the 1960s).
4) To increase reliability. Operating two lines
in parallel allows for one line to disconnect from
service while the remaining line continues to deliver
power.
5) Routing a transmission line to interconnect a
new resource. Routing a transmission line by a loca-
tion that can produce energy will allow the energy to
be delivered in either direction along that transmis-
sion line. If a transmission line in the planning stage
is rerouted by a geothermal site, when the site is
developed, the geothermal energy can be delivered
to either end of the transmission line for use in the
system.
Transmission lines can range in cost from $100,000/
mile to $2,000,000/mile depending on the volt-
age, wire size, terrain, icing conditions, accessibil-
ity, and structure type. Lower voltage systems of
15,000 – 25,000 volts can run from $100,000/mile to
$400,000/mile. Higher voltage systems of 69,000 –
230,000 volts can cost $300,000/mile to $2,000,000/
mile.
In recent years, the use of Direct Current (DC) trans-
mission lines to transmit electricity has increased.
There are several trade-offs when using DC rather
than traditional AC electric transmission. Inverter
stations are required at each terminal to convert DC
to AC, and that energy can be run through a trans-
former to increase or decrease voltage. The cost
savings for reduced transmission line facilities may
be masked by the increased cost of inverter stations
and harmonic reduction. The Battery Energy Storage
System described in the Storage Technology sec-
tion uses similar converter technology to convert the
5,000-volt DC source from the batteries to 13,800
volts AC which can be interconnected with the exist-
ing transmission system. DC systems are usually
reserved for long transmission lines that deliver large
amounts of power. ABB has a commercial HVDC
system called HVDC Lite. It is for systems under
100,000 kilowatts of energy transfer, and typically
used to reduce dynamic voltage and power swings to
which AC power systems are susceptible. Convert-
ers on the receiving end must be force-commutated
to provide the constant 60-hertz or cycles per second
that are required of standard AC systems.
DC systems are significantly complex and should not
casually be applied to the distribution of electricity.
Energy Delivery
176 177176177
Pipelines
Pipelines can be used to deliver liquid and gaseous
energy products such as steam, hot water, crude oil,
natural gas, petroleum liquids, and hydrogen. Steam
can be transferred over distances of approximately
one mile, using the steam pressure as the motive
force for delivery. For other product pipelines, com-
pressor stations or pump stations are required. Long
pipelines typically require large transfer volumes to
share the fixed costs to be economical. Short, hot wa-
ter pipelines can be economical if there is adequate
thermal insulation to reduce thermal heat loss from
the pipe system. Small area, neighborhood, hot water
delivery can be economic and can be viewed as an
extension of the hydronic heat delivery systems used
in homes today. Any hot water heat delivery systems
that extend outside the heating envelope must be
protected from freezing through the application of
antifreeze fluids.
Piping systems range in size from small residential
systems that distribute hot water in a residence( ¾
inch to 1 inch piping), to neighborhood or district
hot water systems( 2 inch to 6 inch range), to large
industrial facilities that can deliver steam, natural gas
or crude oil). The largest pipeline in the state is the
42-inch Trans Alaska Pipeline System which delivers
800,000 barrels of crude oil daily from Prudhoe to
Valdez.
Power lines in Beaver deliver electricity
to residential locations throughout the
remote village.
176 177176177
Pipeline travels under the Colville River.
178 179178179
Golden Valley Electric Utility installed
a Ni-Cad battery that has prevented
over 256 power outages.
178 179178179
Energy Storage
AEA Program Manager: Peter Crimp (771-3039)
A battery system is an
uninterruptible power supply.
180 181180181
Renewable resources such as wind, solar, and
hydro are abundant at some times and in some
places, but they are not always available when and
where they are needed. Other energy sources may
be required to allow these renewable resources to be
drawn upon at a later time when needed, or to switch
to another generation source when renewables
become unavailable. Alternatives can take the form
of storage or dispatchable generation technology that
can be used when required.
The use of energy storage
is considered by many as
an essential component
of future utility delivery
infrastructure throughout
the United States. Energy
storage can be used in a
wide range of applications
to improve availability
and reliability of delivered
power, to support variable
distributed generation
(including renewables), to
stabilize transmission and
distribution lines, or to time
shift consumption through bulk storage to achieve
the most efficient use of baseload generation. Many
of these applications require short bursts of power
to balance and control energy, with discharge times
ranging from milliseconds to a few minutes.
System configuration and design philosophy will
largely determine the incorporation of storage.
Storage time can range anywhere from a long-term
seasonal or annual basis, down to an hourly or even
shorter basis.
It should also be noted that in most cases storage is
not an end in itself, but a bridge used as required to
insure power quality or to simplify control. In most
applications, storage is used to bridge a low-cost
energy option like hydro or wind, to a higher-cost
energy option like natural gas or diesel, allowing
a seamless switch between the two. Long-term
storage is typically not economical. When compared,
the capital and maintenance costs of storage
technology are well above the cost of providing
power with conventional
dispatchable generation.
In some instances a case
can be made for storage on
an expanded basis, where
excess renewable energy is
stored for use at a later time,
but this happens most often
in locations with very high
costs for marginal power or in
places where natural storage
options are readily available.
Many strategies can be used
for energy storage, including
chemical storage (hydrogen or biofuels – see section
on alternative fuels), electrochemical (batteries,
fuel cells, and capacitors), electrical (capacitors),
mechanical (flywheels or pumped hydro), or thermal
storage. The appropriate choice is made based
on location, geography, accessibility, climate, and
local resources. All electrical storage systems add
flexibility to the electric grid, increasing the options
available for grid optimization and management.
Which storage technology would perform best
depends on local economics, the proposed
application, and details of the site.
Introduction
Storage can be classified by several key
parameters:
• Rated Power (kW) The rated power
output available from the device under
normal operating conditions.
• Rated Capacity (kWh) The total
amount of available energy within the
storage system.
• Response time (Hz) The speed at
which the storage device can respond
to changes in the power system.
180 181180181
Conventional Hydro
The simplest form of energy storage is seen in
conventional, large-scale hydro, where dams create
large reservoirs that capture maximum runoff in the
spring and release it over the year to provide energy
the following winter. This can be compared to run-
of-the-river hydrokinetic systems, where energy can
be extracted only from the river as it runs. Power is
lowest when the river is lowest, which in Alaska is in
the winter when power demand is highest. However,
conventional hydro systems are costly and can be
built only where geography and markets coincide.
For larger applications, reservoir hydro projects can
be combined with other large renewable power to
allow optimal dispatching of renewable applications.
Pumped Hydro
While conventional hydro simply uses flowing
water as it is available, pumped hydro uses excess
electrical power to move water from a lower
elevation to a higher one. It then runs the water back
through a turbine to generate power during times of
increased demand. Usually these cycles occur on the
time scale of a day or week. When power demand
is low, typically at night, water is pumped into the
reservoir. During the day, when power needs are
generally high, water is released to generate power.
In this way pumped hydro can be used to convert
undispatchable renewable power into dispatchable
power.
Where a suitable location can be found and large
storage capacity is required, a pumped storage
system is the most cost-effective form of storage
available. The right geographical location has
adequate water, a moderate climate, and enough
variation between times of low-cost power and
high-cost power. Most pumped hydro facilities
have been large, and limited attempts have been
made to integrate them into remote power systems.
Capacity and rated power are generally determined
by geographical considerations, and power response
is quite good; however, most conventional pumped
hydro facilities cannot quickly go from consuming
energy (pumping) to providing energy.
Kodiak Electric Association (KEA) is considering
pumped hydro as a way to permit greater penetration
of wind on their grid. As part of the planned Pillar
Mountain Wind Farm project, KEA is a grid-isolated
utility with generation including a combination of
diesel generators and hydropower from their Terror
Lake project. KEA is planning to install 4.5 MW
of wind (from three General Electric 1.5 MW SLE
wind turbines) for the first phase of their Pillar
Mountain project. A second proposed phase would
incorporate three additional GE turbines and push
penetration in excess of 60%, but this is expected
to result in difficulty maintaining grid stability and
frequency regulation. KEA is currently assessing
options for incorporating pumped hydro, as well as a
small, conventional battery storage system to absorb
power variations and insure that power availability
as a whole remains high.
Bradley Lake Hydroelectric Dam provides
energy to residents from the Kenai
Peninsula to Fairbanks.
182 183182183
An idea similar to pumped hydro is compressed
air, which can also be used as a medium for storing
excess energy. Air is compressed during times of
excess energy and run through a turbine when power
is needed. One major hurdle is finding a storage
container of suitable size to hold enough compressed
air to store a useful amount of energy.
Two plants are currently operational worldwide. In
the Mackintosh, Alabama plant, large underground
caverns in salt domes have been created by solution
mining, which forms large scale, gas-tight volumes
ideal for storing compressed air.
In Phoenix, Arizona, a compressed air storage
system has been developed that uses solar energy
to heat the air when it is being released, allowing
more energy to be extracted from the stored air
than the energy required to compress it. Some have
suggested using mines in Alaska for compressed
air storage, but compressed air storage works best
at high pressures to maximize turbine performance.
Leak rates cannot exceed 1%. In near-surface mines,
porosity in rocks and fissures would likely allow too
much air to leak; however, depleted natural gas wells
might provide storage for compressed air in areas
of the state where these wells occur, such as in the
Cook Inlet basin. In most cases, current and planned
CAES systems are installed in conjunction with
natural gas-fired power plants, where the compressed
air is not used to generate electricity directly, but is
fed into the natural gas turbine to boot its efficiency.
As with pumped hydro, CAES capacity and rated
power are generally determined by geographical
considerations. Power response is also good and,
depending on the design, can at least in theory
quickly switch from generation to excess energy
consumption. Because the storage capacity is
determined by the volume of compressed air, CAES
technology has been considered for long-term
storage. At this point a small-scale CAES system
is not commercially available, due in part to the
cost of high pressure and the small storage capacity.
For this reason, CAES is not likely to be useful for
small communities until large-scale, cheap storage
solutions are found.
For electrical systems, batteries are the most direct
way to store electrical energy. Batteries are used for
many conventional systems, such as uninterruptable
power supplies, cell phones, and laptops. Although
large batteries are available for power supply, the
amount of energy stored in typical batteries is much
smaller than the amount of energy used in residential
and commercial buildings, which means that many
batteries need to be combined to provide appropriate
capacity. Batteries are also relatively expensive.
They have high maintenance cost and a limited
lifetime – perhaps five to six years in most remote
power applications. This means that the cost of
storage (the cost of the battery divided by the total
number of kW-hours of storage possible) is often
much higher than the cost of generating new energy
from fuel, which means that batteries are generally
not appropriate for long-term energy storage.
Batteries are more appropriate for providing short-
term energy storage to allow a transition between a
variable renewable energy source and a dispatchable
generator. This is the case in the wind-diesel power
system in Wales, or smaller applications, such as
home or small community systems, where the cost
of dispatchable generators can be quite high. Since
batteries operate on direct current (DC), a power
converter is also required to allow them to supply
(and be charged by) alternating current (AC). There
are many types of batteries with different operating
characteristics. Several battery types can be
considered for rural applications.
Compressed Air Energy Storage (CAES)Batteries
182 183182183
Lead-acid batteries are the most common batteries.
People are accustomed to using them in vehicles.
For remote power systems people typically use deep
discharge batteries. These are inherently different
from car starter batteries in that they are designed
to hold larger amounts of energy for longer periods.
Although batteries are highly reliable, they have
a limited life, are heavy to ship, and contain toxic
materials that usually require removal at the end of
their useful life.
There are many different types of lead-acid batteries,
and they come in many sizes. There are also many
different designs, each of which has different
operation and cost considerations, but also have
differing life cycle performance. As a general
rule, the larger and heavier the batteries, the better
they are for remote applications, as they typically
have higher amounts of lead (longer lasting active
material) and more room for electrolyte. Lead-
acid batteries have a moderate power density and
good response time. Depending on the power
conversion technology incorporated, batteries
can go from accepting energy to supplying
energy instantaneously. Lead-acid batteries are
highly impacted by temperature and must be well
maintained to achieve maximum life expectancy.
There have been some diesel battery hybrid power
systems installed in the state, most notably at the
new visitor center in Denali Park. The diesel
generator charges the system at night and permits
visitors the experience of silence during the day.
Other examples include a 1.4 MWhr system
installed in Metlakatla and a 2.25 MWhr system
installed at Chena Hot Springs in conjunction with
their geothermal power plant. Both systems were
installed for load leveling to improve the quality of
delivery, although the customer in Metlakatla who
spurred the installation shut down three months after
the battery bank was brought online. That battery
now supports the total Metlakatla load. It is charged
almost exclusively by storage hydro, displacing
diesel generation. The original battery cells have
reached the end of their life and are being replaced.
In an additional project, a battery bank was installed
in Lime Village to store energy from its solar array.
Unfortunately that system has experienced repeated
failures, which is not encouraging for the installation
of batteries in rural Alaska.
Lead-acid batteries:
184 185184185
Nickel-cadmium batteries (Ni-Cad) are an alternative
to lead-acid batteries. They are more robust, with
longer life in stationary applications. Although Ni-
Cad batteries are considerably more expensive than
lead-acid batteries, this longer life expectancy and
their usefulness in high power applications might
make them less expensive on a life-cycle basis,
particularly in rural Alaska where long operating life
is beneficial.
In 2003, Golden Valley Electric Utility in Fairbanks
installed a Ni-Cad battery system capable of
providing 27 MW of power for 15 minutes. This
is long enough for the co-op to bring backup
generation online in the event of problems with the
Intertie or power supplied from the Anchorage area.
GVEA’s system has been operating successfully
since installation and, as of mid-2008, has prevented
256 outages. A Ni-Cad battery bank was also
installed as part of the high-penetration wind-
diesel system in Wales to provide approximately 15
minutes of community load. This allows the system
to ride out small lulls in wind production when the
diesel engines are not operating and start a diesel
engine if the lull is extended. Ni-Cad batteries are
not as susceptible to temperature fluctuations, have
good power density, very quick response time, and
discharge consistently, making them appropriate for
storage in wind-diesel applications.
Several battery technologies have been developed
during the past several decades that can be classified
as flow batteries. These batteries store energy in
liquids that contain materials capable of storing
electrons as compared to the electrochemical
reactions that drive more traditional battery systems.
Flow batteries act much like fuel cells, where
electrons are exchanged over a membrane, causing
an electric current. The electrolyte is usually kept
in large tanks, and although the battery itself has
no moving parts, pumps are required to move the
electrolyte past the membrane. This fact allows the
decoupling of power output and storage capacity
that is found in most other batteries: a flow battery
can be designed to provide a specific power output
(by determining the membrane surface area and
electrolyte flow rate) and specific capacity (the size
of the electrolyte storage).
The VRB (Vanadium Red-ox Battery) is one of these
battery types, produced by VRB Storage Systems
(Canada). This technology is currently in the pre-
commercial testing phase, with a small unit being
tested at UAF for the past two and a half years and
at several dozen installations around the globe.
Several flow batteries have been implemented in
remote applications, most notably in a wind-diesel
application on King Island off the coast of Australia.
Kotzebue Electric Company was also interested
in purchasing a battery of this kind to operate in
conjunction with its wind farm. Unfortunately, VRB
Storage Systems recently went out of business due to
lack of funding.
Ni-Cad Batteries:Flow batteries:
184 185184185
Other flow batteries include sodium bromine and
zinc bromine systems. These share most of the
same basic properties and also remain in the pre-
commercial stage. Flow batteries usually have low
power density, meaning it takes a lot of fluid to
provide any significant capacity. They have long
system lives, at least theoretically. Pumps and power
electronics are the typical weak links. Most flow
batteries also have fast response times and can be
sized to meet a specific need.
Depending on the electrolyte type, flow batteries
must be kept at a relatively constant temperature.
The low self-discharge rate and ability to decouple
power and capacity would allow flow batteries to be
used for longer, multi-day, or even seasonal storage.
Other battery types:
Many other battery types have been investigated
for use in remote applications, but their power
density, response time, and cost have not made
them economical when compared to the three types
described above. Increased market focus on high-
quality, lightweight, inexpensive, and high-power-
density batteries for the electric and hybrid car
markets will result in new battery types that hold
promise for remote applications in the coming years.
Photo below: This flow battery is a 10kW VRB
battery undergoing testing at the Alaska Cen-
ter for Energy and Power.
186 187186187
A flywheel is a device that stores kinetic energy in a
rotational mass. Flywheels are not new technology,
but modern materials and other innovations are
spurring research on making flywheel systems
that are smaller, lighter and cheaper, with greater
capacity.
Flywheels have been used in applications
including energy storage such as uninterruptable
power supplies, grid conditioners for high-cost
manufacturing, and even vehicle powering. (The
gyrobuses used in Sweden in the 1950s were
powered by flywheels.)
Flywheels have storage characteristics comparable to
batteries in that their capacity is generally fixed but
the capacity can be drawn down quickly or slowly
depending on need. Often flywheels are used in
remote applications to smooth out power fluctuations
and allow the starting of a dispatchable generator
when necessary. As compared to batteries, typical
storage times at rated power in the order of minutes
are expected. Flywheels, however, have several
advantages. They have long cycle life, require
minimum maintenance, and have fast response
time. Although the limit of strength of the material
used for the spinning rotor places upper limits on
speed and thus capacity, most commercial flywheels
are modular. Both capacity and rated power can be
increased by using multiple units.
Flywheels
There have been catastrophic failures from
overloaded flywheels; however, these are typically
in research settings. Although recent developments
such as magnetic bearings have reduced losses,
flywheels have a parasitic energy loss to keep the
unit spinning and a relatively quick self discharge if
additional energy is not provided.
PowerCorp (Australia) has successfully integrated
its flywheel system with wind systems and wind-
diesel hybrid projects, and for grid stability typically
in mining applications. The use of flywheels has
allowed wind-diesel systems to operate at reportedly
high penetrations (as high as 90%) of wind power
to offset diesel generation. In this scenario the
flywheel, which ranges in size from 250 kW to 1
MW, acts as a spinning reserve and can provide
frequency and voltage control.
186 187186187
A conventional capacitor is a passive electrical
component that can store energy. Capacitors are
commonly used in personal electronic devices to
store energy to maintain the power supply while
batteries are being changed. Capacitors have no
moving parts, thus a very high cycle life, fast and
consistent response, but low power density. This
means that large capacitor arrays are required to
store meaningful amounts of energy. Conventional
foil-wrapped capacitors are used extensively on
electric grids today to provide voltage support.
While maintaining a very high cycle life (>100,000
cycles), electrochemical capacitors, also known as
ultracapacitors and supercapacitors, are able to store
significantly more energy than conventional ones,
but less energy than pure batteries. Capacitors have a
higher power capability than batteries, but they store
much less energy. Both capacitors and batteries are
systems with multiple components and high capital
costs; however, capacitors and batteries can be
distributed throughout the system and do not require
any specific geology. Capacitors are also expensive,
and currently there are no commercial manufacturers
of large-scale capacitor storage systems.
The use of hydrogen as a power system storage
medium has received a great deal of attention in the
last few years. Several remote wind-PV-hydrogen
systems have been installed, where excess energy is
converted into hydrogen using an electrolyzer and
stored as a compressed gas. This stored energy is
then either burned in a modified internal combustion
engine or run through a fuel cell when renewable
energy is insufficient to cover the load. Hydrogen
systems are expensive because of the high quality
hydrogen needed for most fuel cell applications, and
the cost of suitable storage tanks. They have very
low round trip efficiencies, typically around 30%.
As with flow batteries, the rated power and storage
capacity can be decoupled, with the fuel cell driving
the rated power and the hydrogen tank size driving
available capacity. When compressed gas is used,
power density is usually good, but hydrogen systems
do not typically have good response times. They
are sometimes installed with a small battery bank to
smooth out power fluctuations. Due to the ability
to store hydrogen in external tanks, it is typically
considered as a multi-day storage medium, although
the high cost of current storage capacity limits
hydrogen’s use for longer storage times. At present
the use of hydrogen storage has been primarily in
technology demonstrations or experimental systems.
Due to its cost, hydrogen is not economically viable
given the current state of the technology. As costs
come down, as component efficiency increases, and
as lower cost storage media are introduced, hydrogen
may become a more viable storage medium for
remote power systems.
Capacitors Hydrogen
188 189
Lundsager, P.; Manwell, J.; Ruddell, A.; Svoboda, V.
(2005). Life Prediction of Batteries for Selecting the
Technically Most Suitable and Cost Effective Battery.
Journal of Power Sources. Vol. 144, 2005; pp. 373-384;
NREL Report No. JA-500-38794.
Wenzl H., Baring-Gould I., Kaiser R., Liaw B.Y.,
Lundsager P., Manwell J., Ruddell A., Svoboda V.,
(2004) Life Prediction OF BatterIES For Selecting the
technically most suitable and cost effective battery,
Proceedings of the 9th European Lead Battery Conference,
9ELBC, Berlin, Sept, 2004 and Journal of Power Sources.
Web-based resources
European Union Benchmarking Project on components
for Renewable Energy Systems: www.benchmarkingeu.org
RESDAS: Renewable Energy Systems Design Assistant
for Storage: http://www.ecn.nl/resdas/
Australia Department of Primary Industries and Energy,
1993. Rural and Remote Area Power Supplies for
Australia.
Baring-Gould, E. I.; Wenzl, H.; Kaiser, R.; Wilmot, N.;
Mattera, F.; Tselepis, S.; Nieuwenhout, F.; Rodrigues, C.;
Perujo, A.; Ruddell, A.; Lindsager, P.; Bindner, H.;
Cronin, T.; Svoboda, V.; Manwell, J. (2005). Detailed
Evaluation of Renewable Energy Power System Operation:
A Summary of the European Union Hybrid Power System
Component Benchmarking Project; Preprint. 24 pp.; NREL
Report No. CP-500-38209. http://www.nrel.gov
publications/
Bindner, H.; Cronin, T.; Lundsager, P.; Manwell,
J.; Abdulwahid, U.; Baring-Gould E.I. (2005), Deliverable
4.1: Lifetime Modelling, http://www.benchmarking.eu.org
Publications/Deliverables
Corbus, D.; Newcomb, C.; Baring-Gould, E. I.; Friedly,
S. (2002). Battery Voltage Stability Effects on Small Wind
Turbine Energy Capture: Preprint. 12 pp.; NREL Report
No. CP-500-32511. http://www.nrel.gov/publications/
Crompton, T.R.. Small Batteries, John Wiley & Sons, New
York. 1982
Desmettre D., Mattera F., Malbranche P. and Métais S.
(2000), Publishable Final Report of project “Qualibat,
Investigations for a QUicker Assessment of Lifetime and
other key characteristics of photovotlaic BATteries”,
GENEC, CEA Cadarache, F-13108 St. Paul-lez-Durance,
France
Hunter, R., & Elliot, G. (1994)., “Wind Diesel Systems”,
Cambridge University Press, Cambridge, UK.,1994.
Perez, R.A. (1995). The Complete Battery Book, First
edition, Tab Books, Blue Ridge Summit, PA.
Ruddell A. (2004), Deliverable D3.2 of the Benchmarking
project, Definition of test procedures for batteries used
in different categories, www.benchmarking.eu.org
Publications /Publications.htm
Wenzl, H.; Baring-Gould, I.; Kaiser, R.; Liaw, B. Y.;
References
188 189
190 191190191
TECHNOLOGY SNAPSHOT: HYDROKINETIC
Installed Capacity (Worldwide)1500 kW worldwide, all demonstration projects
Installed Capacity (Alaska)0 kW installed
Resource Distribution Potentially available to communities in all regions of Alaska located near
a major waterway or tidal basin, excluding the North Slope
Number of communities impacted Not assessed yet
Technology Readiness Pre-commercial to early commercial
Environmental Impact
Impacts on local hydrology and aquatic species must be assessed on a
case by case basis. AEA anticipates that these impacts can be minimized
by appropriate siting, design and operation.
Economic Status
A 2008 EPRI study calculates paybacks in the 3-9 year range for three
proposed hydrokinetic sites in Alaska, however this has not been verified
by a commercial installation.
In-Stream Hydrokinetic Energy Technologies
(In-River, Tidal, and Ocean Current)
Alaska’s first in-stream
hydrokinetic turbine, located in
Ruby.
AEA Program Manager: David Lockard (771-3062)
190 191190191
In-Stream Hydrokinetic Energy Technologies
(In-River, Tidal, and Ocean Current)Hydrokinetic devices are powered by moving
water and are different from traditional hydropower
turbines in that they are placed directly in a river,
ocean or tidal current. They generate power only
from the kinetic energy of moving water (current).
This power is a function of the density of the water
and the speed of the current cubed. The available
hydrokinetic power depends on the speed of the
river, ocean, or tidal current. In contrast, traditional
hydropower uses a dam
or diversion structure to
supply a combination
of hydraulic head
and water volume to
a turbine to generate
power. In order to
operate, hydrokinetic
devices require a
minimum current and
water depth. The
minimum current
required to operate a
hydrokinetic device
is typically 2-4 knots.
Optimum currents
are in the 5-7 knot
range. Water depth
is an important factor
in the total energy
that can be extracted
from a site, since rotor
diameter is dependent
on adequate water level
above the installed
device. Hydrokinetic devices are ideally installed
in locations with relatively steady flow throughout
the year, locations not prone to serious flood events,
turbulence, or extended periods of low water level.
Alaska has significant potential for hydrokinetic
development in both rivers and tidal basins. Most
inland communities in Alaska are situated along
navigable waterways that could host hydrokinetic
installations, and Alaska, with 90% of the total U.S.
tidal energy resource, is home to some of the best
tidal energy resources in the world.
While there are obvious opportunities, there are also
significant environmental and technical challenges
related to the deployment of hydrokinetic devices
in Alaska’s rivers and
tidal passages. Some
of these are common
to installations in
any location. Other
concerns are more
specific to Alaskan
waters.
As of 2008,
hydrokinetic devices
are considered pre-
commercial. The
Yukon River Inter-
Tribal Watershed
Council installed a
5 kW New Energy
Encurrent turbine in
the Yukon River at the
community of Ruby for
one month in 2008. A
100 kW UEK turbine is
planned for installation
in the Yukon River at
Eagle in 2009. The
New Energy EnCurrent machine, in 5 and 10 kW
size, is available for purchase from ABS Alaska
in Fairbanks, and New Energy Corporation is
developing 25kW, 125kW, and 250kW devices
as well. This technology is still being refined for
Alaskan applications. Its performance is unproven.
Introduction
Some challenges facing hydrokinetic device
deployment
Environmental concerns, especially with regard •
to impacts on fish must be addressed. Fishery
resources in Alaska have unparalleled value for
subsistence, sport, and commercial use. It is critical
that hydrokinetic energy development be fully
evaluated for impacts on these resources.
Survivability and performance issues must be •
examined. Alaskan waters have many hazards
for hydrokinetic devices, including high rates of
sediment transfer in river beds, debris, and ice.
These issues also complicate the design of anchoring
and cabling systems.
Resource assessment is necessary. There is a •
shortage of river velocity and depth data, particularly
for winter months.
Effects on navigation are important. Many of the •
fast flowing rivers in Alaska with potential for
hydrokinetic development are also major waterways
for barge delivery of bulk materials to isolated
communities. A major consideration is that these
devices not impede river traffic.
Hydrokinetic devices typically use vertical
or horizontal axis turbines similar to those
developed for wind generation; however,
because water is approximately 850 times denser
than air, the amount of energy generated by a
hydrokinetic device is much greater than that
produced by a wind turbine of equal diameter. In
addition, river and tidal flow do not fluctuate as
dramatically from moment to moment as wind
does. This predictability benefit is particularly
true for tidal energy. It can be predicted years in
advance and is not affected by precipitation or
evapo-transpiration.
In Alaska’s riverine environments, water flow
fluctuates, often dramatically, on a seasonal
basis. Snowmelt from glaciers and seasonal
snow accumulation contributes significantly to
the total water volume in Alaska’s waterways.
Generally, flow rates are the highest during
spring snowmelt, but this higher flow is
associated with significant debris flowing within
the water channel. Debris is often directed to
the fastest area of flow (the thalwag) and is
not necessarily confined to the surface. In the
winter, river flow often drops off dramatically
and is largely supplied by local groundwater.
This fact coupled with challenges associated
with ice/turbine interactions leaves open to
question whether hydrokinetic devices would
be cost effective during winter months in most
Alaskan rivers. If hydrokinetic devices are only
deployed seasonally in riverine environments,
an imbalance between resource availability and
electricity demand (which is often highest in the
winter months) will result.
It is possible that in dealing with resource and
load fluctuations on short time periods, energy
storage could be utilized or excess energy could
be dissipated for heating purposes (see the
Energy Storage section for more information).
An ocean current is a continuous, directed flow of
ocean water that can run for thousands of miles.
Surface ocean currents (restricted to the upper 1000
ft or so) are largely wind driven, while deep ocean
currents are driven by density and temperature
gradients. Unlike tidal currents, which change
direction and flow rate, ocean currents are relatively
constant and flow in one direction only. In Alaska,
the Aleutian passages have been identified as an area
for potential development of ocean current energy
extraction.
The type of turbine to be installed on an ocean
current resource is similar to a tidal or in-river
hydrokinetic one. As of late 2008, there are no
commercial ocean current turbines in operation;
however, several companies are exploring options
for ocean-current energy extraction.
Hydrokinetic Technology Overview
Ocean Current
193 Project InformationTo put together a hydrokinetic project, the exact
conditions of the project site must be determined.
This process includes collecting information on river
flow, depths, and fish data. Some of this data can be
obtained from public sources.
Mapping Streamflow and Depths: Federal agencies
including the USGS, the EPA, and the U.S. Army
Corps of Engineers maintain detailed historic
precipitation and runoff databases that are useful in
project planning. In particular, the USGS has daily
streamflow statistics for 485 sites around Alaska.
This information can be found on their website at
waterdata.usgs.gov/ak/nwis/sw.
Unfortunately, the gauging stations where these
data are collected are often widely distributed,
particularly in rural areas of the state. Additionally,
because the amount of power that can be generated
is a function of the cube of the velocity of the water:
Power(kW) = k(velocity)3 where k=constant, the
exact location of a hydrokinetic device within the
water column will have a large impact on how much
power is ultimately generated. It is recommended
that local measurements of depth and water flow be
obtained.
The best tool for measuring river or tidal flow in a
specific location over time is the Acoustic Doppler
Current Profiler (ADCP), which maps velocities at
all depths through the water column. ADCPs are
often deployed from a survey boat or barge. The
timing of these surveys is important, and long-term
data create a more accurate picture of the total
potential. However, data collected by an ADCP
can be adjusted using daily historical averages and
extremes. This greatly reduces the time required to
determine optimal locations.
Equipment can be readily purchased to measure
local streamflow, however processing data
requires some expertise. Alternatively, there
are several companies that can conduct local
resource assessments for both tidal and in-stream
applications, as well as complete a bathymetric
map of the floor of the water body (river or tidal
basin). This is useful not just in determining
water depth, but also in predicting how the flow
through the channel might change over time, due
to silting and/or flood events. It is important to
remember that installing a hydrokinetic device
will in itself change the flow of a river and can
result in sediment deposition over the course of
time.
Since they are relatively consistent and
predictable from year to year, obtaining data on
current flow for tidal energy resources is easier
than for river environments. Basic data on
Alaska’s tidal energy resources can be obtained
from the EPRI reports, ‘Knik Arm Tidal Energy
Report’ and ‘Southeast Alaska Tidal Energy
Study.’ In addition, there are data available from
the Alaska Energy Authority on tidal energy
resources in the Aleutians, Kodiak, Dillingham,
and Bethel.
Project Information194
Environmental Assessment:
Directly or indirectly, any river or tidal turbine
installation has the possibility of impacting fish,
marine mammals, seabirds, and benthic fauna;
however, these impacts are largely unknown.
Direct impacts to aquatic organisms are primarily
the result of contact with structures (such as
turbines) placed in the immediate habitat. Such
impacts may result in injury or mortality. Indirect
impacts can include species displacement due
to modified environmental factors that change
migratory patterns such as a modified tidal stream
that is relied upon for migration in and out of a bay
or estuary.
One significant concern is potential impacts to
Alaska’s fish, particularly salmon. It is generally
thought that hydrokinetic devices will have limited
impact on adult species migrating upriver to spawn.
They tend to favor slow water along banks rather
than fast currents where hydrokinetic devices would
be sited, and they would be better able to maneuver
around an upstream diversion, which they could
sense from turbulence and pressure changes. There
is potential to affect outmigrating smolts. They
tend to prefer the faster flowing waters where
devices would be placed, and they would have less
time to react to turbulence or pressure changes.
In any case, environmental impacts will be site
specific. Until more information is gathered,
a site specific environmental survey should be
conducted at any location considering hydrokinetic
power generation. The Alaska Department of Fish
and Game conducts fish monitoring programs
throughout the State, and there are several private
companies that conduct surveys.
At this time there is minimal if any third party
testing and verification of devices. Cost information
is based largely on claims from manufacturers, who
typically underestimate project expenses in the early
stages of development. In fact, the turbine deployed
by the Yukon River Inter-Tribal Watershed Council
at Ruby in 2008 was the first hydrokinetic device to
be connected to a grid anywhere in the United States
in a river location. The first tidal current devices,
six 34kW turbines, were installed in the East River
of New York City in late 2006. There is more cost
data available for tidal hydrokinetic applications
installed in the northeastern United States, but to
date these have all been demonstration projects and
not permanent installations.
In order to assess performance and economics of
hydrokinetic devices in river locations, the Electric
Power Research Institute (EPRI) has established a
baseline design for a hydrokinetic device consisting
of a horizontal axis turbine mounted on a
pontoon platform. Based on that design, a
performance, cost, and economic model using
a simple payback period (SPP) was developed.
This model can be extrapolated to various
sites of interest around the state. As is true
with many technologies, the commercial scale
economics are limited for rural Alaska, and small
projects will yield higher costs per installed
kilowatt. Nonetheless, EPRI calculated a simple
payback period of 3 to 5 years for the isolated
grid communities of Iguigig and Eagle. This
is based on a system-level preliminary design
of a plant anchored to the river floor (see Case
Study #1), with two sets of two counter-rotating,
4.5 ft diameter rotors and a generator mounted
on the rotor axis. The installed cost per kW of
generation capacity is estimated at $7,500 for
the 40 kW-rated plant at Iguigig and $5,800 for
the 60 kW-rated plant at Eagle. The single 5
kW Encurrent project at Ruby was installed for
$16,000 per installed kW.
While installation costs are high even in
comparison to other renewable energy systems,
they are not unexpected given the current
level of development. In addition to capital
costs, the economics of a project are also tied
to other project costs including operation
and maintenance (O&M), insurance costs,
and permitting, design, and environmental
monitoring costs. These could be substantial,
especially for early generation installations.
EPRI also states that initial project costs used in
their analysis contain a margin of error of up to
30%, and operating and maintenance costs have
a margin of error as high as 80%. This could
dramatically impact the simple payback period
and likely will vary from site to site.
Nonetheless, the results are compelling and
indicate that, if barriers to development of the
technology are overcome, hydrokinetic devices
could result in a real reduction in electrical
generation costs in remote Alaskan communities
with an appropriate resource.
Potential Reduction in Cost of Energy
196 197196197
The following list includes developers who have, at a minimum, built an in-stream prototype hydrokinetic
device:
Manufacturer Location Device Name Website
BioPower Australia bioStreamTM www.biopowersystems.com
Blue Energy Canada Davis Turbine www.bluenergy.com
Bourne Energy Malibu, CA Riverstar www.bourneenergy.com
Clean Current Canada Clean Current Turbine www.cleancurrent.com
Current to Current Burlington MA Submersible Power
Generator www.currenttocurrent.com
Free Flow Power Manchester, MA
Hammerfest Strom Norway Hammerfest Strom Turbine www.tidevannsenergi.com
Hydro Green
Energy Houston, TX HydroGreen Turbine www.hgenergy.com
Lucid Energy Goshen IN Lucid Energy Turbine www.lucidenergy.com
Lunar Energy Ltd United Kingdom RTT www.lunarenergy.co.uk
Marine Current
Turbines Ltd,United Kingdom Seaflow SeaGen www.marine turbines.com
Natural Currents Highland NY Natural Current Vertical Axis
Turbine www.e3-inc.com
Neptune
Renewables United Kingdom www.neptunerenewableenergy.com
Oceana Washington DC
Ocean Flow
Energy United Kingdom EvapodTM http://oceanflowenergy.com
Open Hydro Ireland Open Center Turbine (OCT)www.flordahydro.com
Ocean Renewable
Power Fall River, MA OCGenTM www.oceanrenewablepower.com
Pulse Generation United Kingdom Pulse Generation www.pulsegeneration.co.uk/index.asp
Ponte di
Archimeda Italy Enemar www.pontediarchimeda.it
Seapower Int’l AB Sweden EXIM TM www.seapower.se
Sea Snail United Kingdom Sea Snail www.rgu.ac.uk
Scots Renewables United Kingdom SRTT www.scotrenewables.com
SMD Hydrovision United Kingdom TidEl www.smdhydrovision.com
Manufacturer Options
196 197196197
Manufacturer Location Device Name Website
Startkraft Norway Statkraqft www.statkraft.com
Swan Turbines United Kingdom Swan Turbine www.swanturbines.co.uk
Tidal Generation
Limited United Kingdom Tidal Generation Turbine www.tidalgeneration.co.uk/contact.html
Tidal Hydraulic United Kingdom Tidal Hydraulic Generator
(THG)www.dev.onlinemarketinguk.net/THG/ndex.html
Tidal Sails Norway Tidal Sail www.tidalsails.com
Tidal Stream United Kingdom Tidal Stream Device www.tidalstream.co.uk
UEK Annapolis,
Maryland Underwater Electric Kite www.uekus.com
Verdant Power Arlington, VA Kinetic Hydro Power System www.verdantpower.com
Vortex Hydro
Energy
Ypsilanti, MI
48197, USA Vivaci www.vortexhydroenergy.com
Woodshed
Technologies Australia Tidal DelayTM www.woodshedtechnologies.com.au
198 199
Tidal Energy
Cook Inlet
Cook Inlet has some of the highest tidal ranges in the world and has been the subject of
several studies. Ocean Renewable Power Company (ORPC) has received a preliminary
FERC permit for its proposed tidal energy project site at Knik Arm, adjacent to Anchorage.
ORPC plans to deploy a pilot project at Knik Arm in 2011.
Yakutat The community of Yakutat is considering tidal energy.
Homer
The City of Homer and the communities of Port Graham and Seldovia are investigating the
potential for tidal energy development in Kachemak Bay.
Dillingham The Bristol Bay campus is assessing resource potential in Nushagak Bay.
In-river
Nenana ORPC is planning the installation of a 50 kW turbine in 2009.
Whitestone
The community of Whitestone on the Tanana River near Delta Junction is interested in in-
river hydro and has been the subject of an EPRI study.
Igiugig
Igiugig is a small community in southwestern Alaska that may be ideally suited to
hydrokinetic power. It is the subject of one of the case studies in this chapter.
Ruby
The Yukon River at Ruby is the location of the first hydrokinetic installation in Alaska, the
5kW Encurrent turbine installed by the Yukon River Inter-Tribal Watershed Council. The
YRITWC is considering deploying a larger 25 kW unit in 2010.
Eagle
AP&T has been planning the installation of a 100` kW UEK turbine for several years.
Planned deployment is scheduled for 2009.
The Alaska Center for Energy and Power (ACEP) at the University of Alaska is seeking funding for the development of a
Hydrokinetic Test Center in partnership with the University of Maine and Maine Maritime Academy (both active in tidal energy
research). The proposed Center would work with communities and industry to develop protocols, standards, and best practices in
environmental and resource assessment of tidal and in-river sites through the permitting process. The center would also work on
modeling and performance testing of devices.
Current Activity in Alaska
198 199
Igiugig, located 48 miles southwest of Iliamna
and 56 miles northeast of King Salmon, is a small
village with a year-round population of 56. Igiugig
sits at the headwaters of the Kvichak River, which
drains out of Lake Iliamna. Because it is located
downriver from Lake Iliamna, Igiugig has much less
summer/winter variability in flow. This location
also results in a reduction in silt loads compared to
rivers that are directly glacier fed. The Kvichak is
ice free all winter at Igiugig, although ice does pose
a concern for two weeks in the spring, as breakup
occurs on Lake Iliamna. These factors make Igiugig
an excellent candidate for hydrokinetic power
generation.
EPRI has considered a hypothetical 40 kW project
mounted on a 30-ft pontoon boat anchored to the
riverbed. The pontoon was designed to serve as a
platform from which four turbine rotors, 4.5 ft in
diameter, could be suspended in the water column.
A protective ‘trash-rack’ was mounted in front of
the rotors and generator to minimize debris impacts.
Three of these pontoons, with a total of twelve
devices, were considered for this case study.
The 40 kW size of the project was based on village
energy consumption (low) and resource availability
(high) during summer months. The village
currently has three diesel generators ranging in size
from 60kW to 100 kW. Historic loads are 40 kW
(summer) to 95 kW (December-February). The
cost of power in the community is 98¢ per kWh and
includes fuel and non-fuel costs.
Grid interconnection would be accomplished using
a short (~225 ft) underwater cable from the units
to the shore and connecting to the local grid via an
existing distribution line. Other project components
include a dedicated transformer, revenue metering,
a disconnect device, a circuit interrupting device,
Case Study #1: Igiugig In-River
Hydrokinetic Site (from EPRI study)
a multifunction relay, and a real-time SCADA
monitoring system.
Project costs in 2007 dollars were assessed through
a model using historical quotes and existing projects
in related technology fields. The capital cost for
the 40 kW installation was estimated at $300,000,
with annual O&M at $12,000 per year. Total annual
energy production was estimated at 200,000 kWh
(24 kW average, or 60% capacity factor). This was
assuming the installation matched summer loads for
Igiugug. The simple payback period was estimated
to be three to four years under this scenario. A
second scenario was considered in which the project
provided baseload power to the village (325,000
kWhrs, 36 kW on average, or 90% capacity factor).
This increased the capital and O&M costs for the
project accordingly, but resulted in a similar payback
period. Both scenarios were based on an avoided
fuel cost of 65¢ per kW, which is the fuel portion of
the current power cost.
Additional information on this hypothetical
installation can be found in the EPRI report, ‘System
Level Design, Performance, Cost and Economic
Assessment – Alaska River In-Stream Power Plants.’
200 201
Cairn Point is potentially a good location for in-
stream tidal power generation, as strong tidal currents
occur four times a day, and it is adjacent to significant
electrical infrastructure at Elmendorf AFB and
Anchorage. Cairn Point is located about two miles
north of Anchorage in Knik Arm, in upper Cook Inlet.
At Cairn Point, water depths exceed 150 ft, and the
flow through Knik Arm is constricted. The constricted
flow, along with Cook Inlet’s large twice-daily tidal
range, combine to produce high water velocities.
Tidal currents average 2.0 knots with peaks of up to
7.5 knots. They are some of the strongest currents in
Cook Inlet.
Challenges to successful deployment of an in-stream
energy device at this site include seasonal ice, a high
level of sedimentation in the water, a shifting seabed
(scour), and also concern about impacts to marine
mammals, particularly to the local population of
Beluga whales. Due to the presence of seasonal pack
ice, including both submerged and surface frazil ice as
well as large blocks of beach ice (mixed sediment and
ice), the support structure for turbines and the turbine
profile must be completely submerged. Access to the
turbine site for maintenance will likely not be possible
from about November until breakup in March.
The EPRI system feasibility study considered two
types of in-stream energy generation devices, the
Lunar (RTT) and the Marine Current Turbine (MCT),
installed in arrays that would produced an average of
17 MW of power with little environmental impact.
17 MW is the equivalent power used by about 12,000
homes, each using 1.3 kW. The array layout is
determined by spacing rules designed to reduce cyclic
blade stresses from seabed boundary layer effects,
to prevent ice impacts, and to prevent lateral and
downstream interaction between rotors.
The size and depth of a monopile into the seabed
are determined by current and seabed properties.
Case Study #2: Cairn Point at Knik Arm
Tidal Energy Site (from EPRI study)
Site-specific surveys of water flow and geotechnical
conditions will be required. The proposed installations
could be accomplished from a derrick barge that
would also be used to install monopile foundations
and a remote-operated vehicle (ROV). The ROV
is used to monitor subsea operations, provide visual
inspections, and carry out tasks such as connecting
and disconnecting guide wires and electrical cables.
The ROV can reduce cost and increase safety by
eliminating the need to use divers in high current
conditions.
The 17 MW size of the project was based on
restricting power extraction to about 15% of the total
available power to minimize degradation of the marine
environment. If more of the resource can be extracted
without degradation to the environment, then energy
costs could decrease. Grid interconnection would be
through a subsea cable (approximately 3000 ft long)
to a shore-based substation, then to Elmendorf AFB’s
electric grid for transmission to Anchorage Municipal
Light and Power.
Cost estimates in 2005 dollars are $110 million
for the capital costs (not including a $3.25 million
transmission upgrade), with an annual O&M cost of
$4.1 million. This translates into nominal levelized
costs of electricity of about 10.8¢/kWh for utility
generation, and 8.4¢/kWh for municipal generation.
This assumes energy incentives equal to those that the
government provides for wind energy technology.
At this point, Ocean Renewable Power Corporation
has secured a FERC preliminary permit for the Cairn
Point area. ORPC plans to install its own Ocean
Current Generator (OCGen™) module consisting
of four Turbine Generator Units (TGUs), each with
4 Advanced Design Cross Flow (ADCF) turbines
mounted to a permanent magnet generator on a single
shaft.
The system will be moored to the bottom with anchors
and weights rather than pilings. It will be located at
200 201
least 40 feet beneath the surface of the water to avoid
conflicts with marine vessels, ice, and debris. ORPC
plans to install a 1 MW pilot project in 2011, to increase
to 5 MW after a year of testing and monitoring, and to
increase to a final project size commensurate with the
resource and energy market for the long term.
Additional information for the tidal in-stream power
generation concept installation for Cairn Point can
be found in the EPRI report, ‘System Level Design,
Performance, Cost and Economic Assessment – Knik
Arm Alaska Tidal In-Stream Power Plant’.
The hydrokinetic working group agreed that
commercial projects will likely be operating in the
state in the next three to five years. The group was
not ready to make specific recommendations for
hydrokinetic projects for specific villages in Alaska.
Recommendations from the working group are less
project specific. They are tipped toward finding
appropriate ways to move forward with this technology.
The members of the working group stressed that its
success is tied to not overestimating the maturity level
202 203202203
of the technology by skipping over beta testing and demonstration phases.
Hydrokinetic energy represents a real opportunity for power generation using local resources at select
locations in Alaska; however, there are still numerous environmental and technical challenges associated with
this technology. For example, there are concerns related to interactions between turbines and both adult and
juvenile fish, since most communities with hydrokinetic resources are heavily dependent on local subsistence
and commercial fisheries. Additional concerns include ice interaction with infrastructure, silt abrasion,
Hydrokinetic Working Group
Recommendations
Specific recommendations that came out of the working group include:
Develop guidelines and protocols on how to initiate projects. •
Develop methods to prioritize potential projects.•
Conduct additional site-specific resource assessment in Alaska, including screening •
of locations with a list of compatibility factors, to determine optimal sites. This
is necessary for project development and does not commit the state to failure by
deploying technology too soon.
Quantify and streamline permitting requirements, and draft a recommendation to have •
the state review FERC licenses. Encourage communities to protect their own interests
by applying for site permits near their locations.
Conduct more research as needed in terms of impacts on fish populations.•
Involve the University of Alaska as an independent source for device testing.•
Support demonstration and pilot scale projects to come up with defensible numbers •
(projections) for future project costs. Get data on how devices are working and how
manufacturers can improve and modify devices. Optimize technology for Alaskan
environments.
Support development of a coordinated national research program to avoid multiple •
small failures in disparate locations. Position Alaska (possibly through the University)
to take a leading role. Such a test center could also serve to promote cross-
fertilization and standardization of ancillary equipment, such as development of a
universal platform for installation of turbines, including a deployment strategy.
202 203202203
submerged debris which could damage turbines,
navigation hazards, and impacts on marine life.
The actual construction and operation of a pilot
device or devices will result in a more complete
understanding of technical, environmental, and cost
factors associated with hydrokinetic energy. This
would provide a solid starting point for additional
cost and economic analysis for specific sites around
the state.
References
Polagye, B. and M. Previsic (2006) System Level
Design, Performance, Cost and Economic Assessment
– Knik Arm Alaska Tidal In-Stream Power Plant. EPRI –
TP – 006 AK, 126 pp.
Previsic, M, Polayge, B and Bedard R, (2008) System
Level Design, Performance, Cost and Economic
Assessment – Alaska In-Stream River Power Plants EPRI
RP-006-AK 99 pages
EPRI Primer on Power from Ocean Waves and Tides
Technology White Paper on Ocean Current Energy
Potential on the U.S. Outer Continental Shelf, U.S.
Department of the Interior
Conclusion
204 205204205
TECHNOLOGY SNAPSHOT: WAVE POWER
Installed Capacity (Worldwide)
Over 3000 kW worldwide, most are demonstration
projects. A commercial multi-unit 2.25 MW capacity
commercial wave farm was commissioned offshore of
Aguçadoura, Portugal in the summer of 2008
Installed Capacity (Alaska)
0 kW installed. Estimated recoverable resource of about
150 TWh/yr in southern Alaska (assuming 15% recovery
at 80% generation efficiency)
Resource Distribution
Potentially available to communities in regions of Alaska
located near an ice-free ocean and exposed to long
fetches. The potential for wave energy development in
protected waterways, such as those found in SE Alaska,
or under winter ice is limited.
Number of communities impacted Not assessed yet
Technology Readiness
Pre-commercial to early commercial with an early
commercial site of over 2 MW installed with a follow-on
second stage of about 20 MW in development
Environmental Impact
Impacts on local hydrology and aquatic species must be
assessed on a case-by-case basis. EPRI anticipates that
these impacts can be minimized by appropriate siting,
design and operation.
Economic Status
A 2007 assessment of energy costs for conceptual wave
power projects in North America ranges from about 10—
39 ¢/kWh with the potential to decrease to about 4¢/kWh
with installed capacities of 40 MW or more (consistent
with price trends seen for wind energy) [Bedard et al.,
2007]
Ocean Wave Energy Technologies
AEA Program Manager: David Lockard (771-3062)
204 205204205
Introduction
The wind acting on the ocean’s surface generates
waves. They can travel for thousands of miles with
little loss of energy until they near a shore where
they begin to interact with the seafloor at depths of
about 600 ft. Ocean waves consist of water particles
that move in an orbiting pattern. Most (95%) of the
wave energy occurs between the surface and a depth
equal to one quarter of the wavelength.
Alaska has significant potential (estimated at about
60% of the total U.S. potential) for ocean wave
energy development in offshore ocean basins near
coastal communities.
There are obvious opportunities, but also significant
environmental and technical challenges related to
the deployment of ocean wave energy devices in
Alaska’s ocean basins. Some of these are common to
installations in any location, and other concerns are
more specific to Alaskan waters.
Worldwide as of 2007, ocean wave energy devices
are considered pre-commercial to early commercial.
Design, performance, and economic assessments
have been made by EPRI for sites in Hawaii,
Oregon, California, Massachusetts, and Maine. To
date there has been no examination of wave energy
project design for Alaska, although the City of
Yakutat contracted with EPRI in the fall of 2008
to perform a wave energy feasibility study. The
only deployed wave energy project in the United
States is a 40 kW buoy (PowerBuoyTM) for a Navy
– Ocean Power Technology project in Hawaii. An
initial, commercial wave energy wave farm with
2.25 MW capacity has been developed 5 km off the
coastline of northern Portugal near Aguçadoura with
plans to further expand the farm to 20 MW (www.
pelamiswave.com/).
Some challenegs to Alaskan waters include:
Environmental concerns – especially with regard to •
impacts on fish and marine mammals.
Survivability and performance – Alaskan ocean basins •
have many potential hazards for ocean wave energy
devices, including intense storms, high ocean current,
debris, and ice (atmospheric, pack, and frazil). These
issues also complicate the design of anchoring and
cabling systems.
Resource assessment – there is a shortage of site-specific •
wave energy information.
Effects on navigation – ship and barge delivery of bulk •
materials to both major and isolated coastal communities
is common in Alaskan waters, so a major consideration is
that these devices not impede marine traffic.
Lack of transmission infrastucture and large electrical •
loads adjacent to the wave resources.
Ocean waves contain energy both through
water motion (kinetic energy) and due to the
elevation of water as the waves crest (potential
energy). On average, the potential and kinetic
energies in a wave are equal, while the energy
fluctuation is a function of the square of the
wave height, the distance between waves, and
the wave period. Wave energy fluctuates daily
and seasonally, depending on when and where
storms occur to generate deepwater ocean waves.
Ocean Wave Energy Technology Overview
Monthly averages can be used to estimate seasonal
variations in wave energy, which are maximum in
winter. Wave forecast models can approximately
predict wave energy from one to three days in
advance. Both the kinetic and potential energy of
waves are utilized in the range of ocean wave energy
conversion devices being developed or deployed.
These devices either transfer water motion into
mechanical action or use the wave height to create a
potential energy head across a generator.
207 Project InformationTo put together an ocean wave energy project,
exact conditions of the site need to be determined.
This information includes daily and monthly wave
heights and periods, extreme wave events, ice
conditions, wind and ocean currents, depths, fish
data, and commercial and navigational uses. Some
of this data can be obtained from public sources.
Information about Alaska coastal ocean basin
conditions and characteristics can be obtained from
the Alaska Ocean Observing System (ak.aoos.
org), NOAA, and Coast Guard buoys among other
sources.
Installation and operation of a wave power facility
will affect the near-by environment, and it has the
possibility of impacting fish, marine mammals,
seabirds, and benthic fauna directly or indirectly.
Other environmental effects may include the
withdrawal of wave energy, atmospheric and
oceanic emissions, visual appearance, conflicts with
other uses, and installation and decommissioning
of facilities. There is no actual environmental
effects data available as of 2008 for Alaska or
anywhere in the United States. Some studies are
being conducted in Europe to examine potential
environmental impacts of wave energy.
208 209208209
Manufacturer Options
The following list includes developers who have, at a minimum, built a wave energy conversion prototype
device:
Manufacturer Location Device Name Website
Finavera Renewables Canada AquaBuOy www.finavera.com/
Oceanlinx Australia Offshore OWC www.oceanlinx.com
Float San Diego, CA Pneumatic Stabilized
Platform www.floatinc.com
Hydam Ireland McCabe Wave Pump www.wave-power.com
Independent Natural
Resources Minnesota SEADOG – water pump
Pelamis Wave Power United Kingdom Pelamis www.pelamiswave.com/
Ocean Power Technologies Pennignton, NJ PowerBuoy www.oceanpowertechnologies.com
Ocean Wave Energy
Company Bristol, Road Island Ocean Wave Energy
Converter www.owec.com
Ocenergy Norwalk, CT Wave Pump www.ocenergy.com/
OreCon Ltd United Kingdom MRC1000 www.orcon.com
SeaPower Group Sweden Floating Wave Power
Vessel www.seapower.com
Teamwork Tech Netherlands Archimedes Wave Swing www.waveswing.com
Wve Dragon ApS Denmark Wave Dragon www.wavedragon.net
WaveBob Ltd Ireland Wavebob www.wavebob.com
WaveGen United Kingdom Coastal and Offshore
OWC www.wavegen.co.uk
AW-Energy Oy Finland WaveRoller www.aw-energy.com/
208 209208209
EPRI estimates of the cost of energy (COE) for
the first commercial-scale wave power facilities in
the United States range from about 10¢/kWh to 39¢/
kWh, based primarily on the wave energy potential
and operating and maintenance costs at the various
locations that were considered. These costs do
not compare favorably with some other forms of
renewable energy such as hydropower, but they are
somewhat less than the costs for early commercial
wind energy devices. EPRI estimates indicate that
the COE for wave energy facilities will decrease
along a learning curve that depends on knowledge
gained with each cycle of device improvement and
operating experience. The learning curve for wave
energy devices is projected to fall below the wind
energy learning curve. Both curves are a function of
installed capacity.
Potential reduction in cost of energy Conclusion
Ocean wave energy could represent a real
opportunity for select coastal locations in Alaska;
however, there are numerous environmental
and technical challenges associated with this
technology. For example, there are concerns related
to interactions between ocean energy devices
and marine mammals and both adult and juvenile
fish. Most coastal communities with wave energy
resources are heavily dependent on local subsistence
and commercial fisheries. Additional concerns are
related to ice interaction with infrastructure, debris
that could damage devices, navigation hazards, and
impacts on marine life.
While construction and operation of ocean wave
energy devices is not considered near-term for
Alaska, it has the potential to meet small-scale
energy requirements for remote coastal communities.
Feasibility studies like those done for in-stream
hydrokinetic energy generation will be needed to
provide a better understanding of the potential for and
challenges of ocean wave energy generation.
210 211210211
References
Bedard, R., Oregon offshore wave power demonstration
project: Bridging the gap between the completed phase
1 project definition study and the next phase - phase 2
detailed design and permitting. 2005, EPRI.
Bedard, R., et al., Final summary report: Project
definition study offshore wave power feasibility
demonstration project. 2005, Electric Power Research
Institute Inc. pp.34.
Bedard, R., HydroKinetic energy “lay of the land”. in
Department of Energy HydroKinetic Workshop. 2005:
Dept. of Energy.
Bedard, R., et al. North American ocean energy status
- March 2007 in 7th European Wave and Tidal Energy
Conference. 2007. 11—14 Sept. 2007, Porto, Portugal:
DigitalPapers Org.
Bedard, R., Overview of U.S. ocean wave and current
energy: Resource, technology, environmental, and
business issues and barriers. 2007, Electric Power
Research Institute. pp.60.
Comission, E., Ocean energy conversion in Europe:
Recent advancements and prospects. 2006, Centre for
Renewable Energy Sources: Pikermi, Greece. pp.36.
EPRI, Primer: Power from ocean waves and tides. 2007,
Electric Power Research Institute: Palo Alto, CA. pp.6.
FERC, Licensing hydrokinetic pilot projects. 2008,
Federal Energy Regulatory Commission. pp.33.
MMS, Technology white paper on wave energy potential
on the U.S. outer continental shelf. 2006, Minerals
Management Service. pp.11.
NOAA. Ecological effects of wave energy development
in the Pacific Northwest in Ecological effects of wave
energy development in the Pacific Northwest: A scientific
workshop, Oct. 11 - 12, 2007.
Robinson, M.C., Renewable energy technologies for use
on the outer continental shelf. 2006, National Renewable
Energy Laboratory. pp.34.
210 211210211
Small-Scale Nuclear Technologies
AEA Program Manager: Mike Harper (771-3025)
212 213212213
Worldwide, more than 15% of electricity is
generated from nuclear power, with the United
States, France, and Japan being leaders in this
technology. According to the International Energy
Agency, as of 2007 there were 439 nuclear power
reactors operating in 31 countries. As nuclear
power generation has become established since the
1950s, the size of reactor units has grown from 60
MW to more than 1300 MW, with corresponding
economies of scale in operation. At the same time
many hundreds of smaller reactors have been built,
both for naval use (primarily in submarines) and as
neutron sources, yielding enormous expertise in the
engineering of small nuclear units.
Conventional nuclear technology is considered a
mature technology. Significant progress is also being
made in the development of small-scale, sealed, self-
contained nuclear reactors, which can essentially
operate as a ‘battery’ to supply energy in the form
of electricity and/or heat. These modern, small
reactors for power generation are expected to have
greater simplicity of design, the economy of mass
production, and reduced siting costs. They are also
designed for a high level of safety in the event of
malfunction and may be built independently or as
modules in a larger complex, with capacity added
incrementally as required. The International Atomic
Energy Agency (IAEA) defines ‘small’ as reactors
under 300 MW. To put this in perspective, ‘small’
is over 25% higher than the current peak power
demand in the greater Fairbanks area (on the GVEA
grid).
Small nuclear reactors are an intriguing emerging
technology option for Alaska. Unlike conventional
reactors, these nuclear ‘batteries’ are designed to
be delivered to the site, installed with the generator
system, and operated for the prescribed life
(typically 5-30 years). After this time period, the
fuel assemblies are removed and returned to the
manufacturer, and the reactor assembly is refueled or
shipped to disposal intact.
This type of fueling protocol allows plants to be
simpler and less expensive to design and build.
For designs that have no onsite spent nuclear fuel,
the security requirements are reduced. The safety
systems are passive and highly reliable without
maintenance. The plants emit no greenhouse
gases and can be small enough to be buried to
minimize security issues. The power plant could be
transported by barge in modules and installed in a
building, with an excavation for the reactor vessel
and containment system as deep as 100 ft deep.
There are a number of potential applications for
these nuclear ‘batteries’ in Alaska. One of the
most obvious would be to supply power for remote
mines where diesel power would otherwise need
be imported at high cost. Six of this type of reactor
have been proposed for the Alberta oil sands region
to provide heat to facilitate separation of oil from the
sands. Power generation for remote communities
is another potentially attractive application. The
community of Galena has been working with
Toshiba on obtaining a reactor for a number of
years, and several other Alaskan communities
have expressed interest in this technology. Galena
is interested in a 10 MW reactor system, the 4S;
designed by Toshiba to provide power and heat to
the community. The city has passed a resolution
supporting the installation of this reactor.
Introduction
212 213212213
The economics of the Toshiba 4S reactor appear
compelling, especially given the current cost of
electricity at 70¢ per kWhr (from the 2007 PCE
Report) and estimated heating fuel cost at $7.48
per gallon (based on ISER data) in Galena. The
expected cost of electricity from the 10 MW-size 4S
is between 10¢ and 20¢ per kWhr. The final cost of
delivered power is likely to vary based on a range of
issues yet to be addressed related to the building of
a nuclear plant in Alaska. Cost will also depend on
the degree to which district heating and other uses
can be found for the waste heat from the turbine
generator system. While the Toshiba reactor can
make 10 MW of electricity, it can simultaneously
make 17 MWth (58 MMbtu) of thermal energy in the
form of warm (~ 150º F ) water.
The 4S reactor is currently at the beginning of the
licensing process with the U.S. Nuclear Regulatory
Commission (NRC). This work is funded by
Toshiba. The company expects to submit the design
certification application for the 4S sometime in 2009,
which will initiate the process that will ultimately
result in a Design Certification from the NRC.
This process certifies that national experts have
reviewed every aspect of the facility’s design and
that the vigorous, legally binding review process has
been satisfied. In parallel, an environmental report
on applying the technology to the site facility is
prepared, reviewed, and approved. These factors are
resolved in a standard review process, codified in 10
CFR 52 and referred to as the combined licensing
application (COLA). Seventeen applications
for over 30 new nuclear reactors are currently
undergoing this review process.
The U.S. DOE has completed a ‘Situational
Analysis’ for the community of Galena, including
a preliminary environmental impact assessment.
Compared to alternative energy sources, small
nuclear plants are promoted as virtually disappearing
into the background with little effect on the
environment. Clearly, the permitting process under
the Nuclear Regulatory Commission is an extremely
rigorous one, which addresses potential safety and
environmental concerns. Nonetheless, the Galena
project would be the first installation of its kind
and so contains inherent risks. For this reason,
the Yukon River Intertribal Watershed Council, a
consortium of 66 First Nations (Canada) and Tribes
(Alaska) living along the Yukon River and dedicated
to the protection and preservation of the Yukon River
Watershed, has strongly opposed the Galena nuclear
project.
Potential Reduction in Energy Cost Environmental Considerations
214 215214215
While the Toshiba 4S is one example of
a small nuclear reactor and the one closest to
commercialization, there is a large variety of
technologies with many proposed systems of a size
appropriate for Alaskan applications.
Other Manufacturers and Technology Options
PBMR
The Pebble Bed Modular Reactor is a modular, high-temperature gas reactor that uses
helium as its coolant. Its total output from 8 modules is 1320 MW. The PBMR is a
reactor that has received significant attention. At a scale of interest for some of the
larger mine sites or communities, this product is further away from permitting (and thus
commercialization) than the Toshiba 4S technology.
Hyperion
Hyperion Power Generation also touts a small, portable nuclear reactor (‘the size of a hot
tub’) that would produce 27 MW worth of thermal energy. The system uses technology
originally developed at Los Alamos National Laboratories, and now licensed by Hyperion
for commercial development. The suggested $25 million price tag is considered too
low by many following the technology, and Hyperion is far from development of a
commercial product.
NuScale Power
NuScale is another company that has licensed a design developed by the University of
Oregon. This reactor is essentially a scaled-down version of a standard reactor, sized at
approximately 40-50 MW. It is also in the early stages of development.
S-Star
Lawrence Livermore National Lab has designed a small, contained nuclear reactor as part
of its S-Star program, with a 10 MW prototype and expected final product size of 50-100
MW. This reactor is nowhere near commercialization.
IRIS:
The ‘International Reactor Innovative and Secure’ is a medium power (335 MW) reactor
that has been under development for several years by Westinghouse in coordination with
an international consortium. The most recent information is that the planned submittal of
a design certification application for IRIS has been pushed back from 2008 to 2010. In
addition, Toshiba is now the majority owner of Westinghouse so the future of the IRIS
reactor is not clear.
Worldwide, over 40 small reactor concepts are being
pursued, but with the exception of the 4S, they are
all far from commercial. Below are some examples
of developers and manufacturers who have received
attention in recent years:
214 215214215
If all goes well, the Toshiba 4S could be providing
Galena with power, space heating, and excess
capacity for economic development opportunities
by about 2015. If certain hurdles are not overcome,
however, a large amount of money and time will be
spent without producing any new power capacity at
all. In any case, nuclear technology should not be
considered a near term solution for energy needs in
Alaska.
An additional consideration with nuclear reactors
is that at this time AEA/AIDEA regulations
specifically preclude involvement in nuclear energy.
These regulations could hamper deployment of the
technology if and when it becomes readily available.
Conclusion
Nuclear Regulatory Commission website section on new
nuclear plant designs at: http://www.nrc.gov/reading-rm/
doc-collections/fact-sheets/new-nuc-plant-des-bg.html
Galena white papers technical publications for the Galena
nuclear project: http://www.roe.com/about_techGalena.
htm
Galena Electric Power – a Situational Analysis. Paper
published in 2004 by the University of Alaska for NREL.
http://www.iser.uaa.alaska.edu/Publications/Galena_
power_draftfinal_15Dec2004.pdf
Status of Small Reactor Designs Without On-Site
Refueling, IAEA-TECDOC-1536, International Atomic
Energy Agency, January 2007
References
216 217216217
Alaskan coal resources are spread
across coal basins and fields in the
northern, interior, and southcentral
regions of the state.
216 217216217
TECHNOLOGY SNAPSHOT: COALBED METHANE
Current production (Worldwide)
Worldwide resources estimated between 3,000 to 9000 tcf.
USA production is about 1.6 bcf from about 20,000 wells in
2007.
Current production (Alaska)None
Resource Distribution
Coalbed gas is generally limited to sub-bituminous to
bituminous coal rank. Coalbed gas content is unknown in
most Alaska coal basins.
Number of communities impacted Unknown
Technology Readiness
Successful and established commercial CBM production in
Lower 48, however no production or infrastructure in Alaska
yet. Production through permafrost is unproven
Environmental Impact Water disposal must not adversely affect surface waters or
subsurface aquifers.
Economic Status Uncertain in Alaska
Coalbed Methane
AEA Program Manager: James Jensen (771-3043)
218 219218219
Coal is one of the most abundant non-renewable
energy sources in the world, and Alaska has
substantial coal resources. The majority of Alaska’s
coal is located in the North Slope, followed by
the Cook Inlet region, Interior Alaska (mainly
Healy), the Alaska Peninsula, Copper River Basin,
and numerous smaller basins and individual coal
localities throughout the state. Until 1981, gas
in coal seams, or coalbed methane (CBM), was
considered a dangerous hazard to underground
mining operations and was vented to the surface.
Beginning in 1981, this ‘waste’ methane was
successfully produced, initially from underground
mines, as a viable energy resource. Today the
production of coalbed methane from coal seams in
the Lower 48 accounts for about 1.6 billion cubic
feet of gas, or about 10% of the gas production in the
United States.
Coalbed methane is a clean-burning fuel, comparable
in heating value (~1,000 Btu/scf) to conventional
natural gas. Unlike conventional natural gas, with
CBM the coal serves as the source rock and as the
gas reservoir. Methane is formed along with water,
nitrogen, and carbon dioxide when buried plant
material is converted into coal by heat, pressure,
and chemical processes over millions of years. This
coalification process generates methane-rich gas,
which often is held in pores, fractures, and spaces
within the coal reservoir. As a reservoir, coal is a
microporous hydrocarbon mineral capable of holding
a large quantity of gas that is generated internally.
This gas cannot be extracted from the coal reservoir
unless these small micropores are connected through
a well-developed fracture system called coal ‘cleats.’
Permeability is the measurement of how well a
fluid or gas moves through a rock when the pores
are connected through a cleat or fracture system.
Even if there is sufficient coalbed gas, it cannot be
produced if there are few fractures resulting in low
permeability.
Coal must also reach critical threshold of thermal
maturity or ‘coal rank’ before large volumes of
thermogenic methane gas are generated. Lower
rank lignite to subbituminous coals contain mostly
biogenic gas. The gas results from bacterial action on
organic material, in the same manner that methane is
generated by bacteria in shallow garbage landfills.
It is important to note that there is no current
production of biogenic gas from lignite coals
because they lack a well-developed natural fracture
system. Production of biogenic gas from very thick
(50-200ft-thick) sub-bituminous coals is occurring in
the Powder River Basin. There, gas contents average
less than 35 cubic feet per ton. Most commercially
viable coalbed methane production is from coals
within the range of high volatile A bituminous to
low volatile bituminous. These coals provide both
optimum gas content (as high as 800 cubic feet of
gas per ton) and well-developed, natural fracture
cleat systems to provide a pathway to the well bore.
Finally, coal seams are usually saturated with water,
with the hydrostatic pressure keeping the methane
within the coal. Sufficient hydrostatic pressure
must be present throughout the geologic history of
the coal seam for gas to be retained. If pressure is
reduced enough by erosion, uplift, or other means,
the gas can escape from the coal leaving little or no
gas behind.
Introduction
218 219218219
The geology of the coal basin and coal seam
reservoirs needs to be studied in considerable
detail so that the coal rank, coal thickness and
lateral extent, and degree of fracturing are known.
Additionally, data on the quality of the coal seam
water are important for disposal of produced water.
Systematic coalbed methane field development is
essential in order to maximize total gas production,
field life, and profitability. Coalbed methane
resources in some basins have been successfully
exploited, while other basins with apparently similar
geologic and hydrologic attributes have proven to be
only poor to moderate coalbed methane producers.
Therefore, many pilot wells need to be drilled
before the productivity of the reservoir in terms of
recoverable reserves for the average well and for the
field as a whole can be predicted.
The usual method of producing methane from coal
Critical Factors for Coalbed Methane Production
is to pump water from a well, reducing the pressure
and causing the methane to ‘desorb’ and begin to
flow from the coal. A key factor in the production of
CBM is permeability of the coal seam. The coal must
be very permeable to allow the gas to flow in large
quantities through the coal to the producing well. At
first, coalbed methane wells produce mostly water, but
over time and under proper geologic conditions, the
amount of water declines and gas production increases
as the bed is ‘dewatered.’ Water removal may continue
for several years.
A developed coalbed methane well field consists
of production wells, gathering lines, separators,
compressors, and water disposal facilities. In each
development, water and gas from each well site
are transported to a single site for water disposal,
gas treatment and central compression, and then to
distribution pipelines.
Left: Natural fracture or cleat system
in coal. Without cleats, coal is porous
but NOT permeable, and gas cannot be
produced.
220 221220221
Understanding the detailed geology of coal
deposits is essential in evaluating prospective
coalbed methane fields in Alaska. These geologic
evaluations are important for determining the coal
rank, quality, thickness, continuity, and pertinent
characteristics of the surrounding rock layers, as
well as of the basin’s hydrology. The ability for
coal to produce methane as a resource is governed
by the following critical controls: tectonic/structural
setting, deposition environment, coal thickness and
distribution, coal rank, gas content, permeability,
and hydrogeology. Initial data collection activites
to evaluate a prospective coal basin are detailed
geologic mapping, collection of coal outcrop
samples for coal quality and rank measurements, and
measurement of fractures or cleats within the coals.
The next step is drilling test holes to collect gas
content data, measure permeability, and sample for
water quality.
Exploring for Coalbed Methane in Alaska
Few of the coal basins in Alaska have had this level
of detailed study to determine whether they are
viable candidates for coalbed methane production.
Nearly all lack data on coal seam thickness, fracture
spacing, and coalbed gas content. Coal quality data
are sparse. As previously mentioned, coal rank is
important because it directly influences the coal’s gas
storage capacity. With the exception of the North
Slope, Alaska Peninsula, northern Cook Inlet, and a
few other areas, many of the coal basins that underlie
or are adjacent to Alaska rural communities have not
yet reached a depth of burial and a level of maturity
to form thermogenic coalbed methane, nor have they
developed adequate fracture systems. These basins
with lignite coal are not viable candidates for CBM
with today’s production technology.
220 221220221
There is currently no coalbed methane production
or developed coalbed gas infrastructure in Alaska.
Attempts to explore and economically produce
coalbed gas in the northern Cook Inlet region met
with limited success. In 2004, a government-funded
coalbed methane exploratory hole was drilled at the
community of Fort Yukon. The exploratory hole
reentered a previously drilled hole in order to sample
two low-rank lignite seams and collect samples
to measure gas content. This followed a shallow
seismic study conducted in 2001. It had determined
that the lignite was laterally continuous beneath the
community.
The results of the gas content measurements were
disappointing, as the upper coal seam averaged 13%
cubic feet per ton of gas; the lower lignite 19% cubic
feet per ton. Testing indicated that the permeability
of the lignite was extremely low with few fractures
present within the lignitic coal seam. This project,
including a preliminary seismic study and a single
core test hole, cost in excess of $1.7 million. The
importance of this study was that it demonstrated
that low-rank lignite coals that are prevalent in
many of Alaska’s coal basins are not candidates for
economically viable coalbed methane production.
In 2007 the Department of the Interior (USGS and
BLM) conducted exploration for coalbed methane
at Wainwright, Alaska on the western North Slope.
Their initial results were promising, and in 2008
they drilled a delineation well to test the lateral
extent of the coal beds, as well as an array of wells
for a production test. Coals in the subsurface at
Wainwright are bituminous in rank and appear to
have generated sufficient methane to merit continued
testing in 2009. Based on the known characteristics
of the western North Slope coal (optimum rank,
thick and laterally continuous seams, and sufficient
gas content and burial depth), this region contains
the best potential for coalbed gas production in all of
Alaska.
Status of Coalbed Methane Exploration in Alaska
In addition to finding coal of sufficient rank and gas
content, there are other, unique challenges to coalbed
methane production in Alaska. Given that coal bed
methane production often involves significant water
production, there must be some way to dispose
of the fluid, especially if it does not meet strict
EPA quality standards. The biggest challenges
to production and disposal of this water are cold
temperatures and permafrost. Usually, produced
water is either surface disposed in large evaporation
ponds, surface discharged into existing bodies
of water, or re-injected into deep disposal wells.
Evaporation ponds are common in many Lower 48
production facilities, but they are not a plausible
option for Alaska because of the long freezing-cold
winters. Surface discharge of even high quality
water into rivers or lakes is unlikely to be viable
because these streams are frozen about 70 % of the
time, and such a practice is likely to be restricted
due to possible impacts on fish habitat. Downhole
re-injection of produced water is also problematic
because the effects of disposal in permafrost are
unknown. A well bore can freeze up during pump
failure and cause significant problems that include
gas field shutdown. Additionally, re-injection has a
danger of fluid communication between aquifers if
the subsurface geology is poorly understood and the
rock layers are connected, resulting in contamination
of a local source of drinking water. These hurdles
can be overcome, but in Alaska it is important for
developers to make special considerations which
may result in significant additional costs.
222 223222223
Alaska has a significant portion of the coal
resources in North America, and coal is by far the
most abundant domestic energy resource available
in the United States. Nevertheless, the occurrence
of coal in an Alaskan sedimentary basin does not
necessarily mean that subsurface coalbed gas can
be economically produced. Subsurface coals need
appropriate geologic and hydrologic characteristics
to be CBM prospects. Lack of data on the geology,
hydrology, subsurface water quality, coal quality,
coal permeability, and gas content in most coal
basins impedes assessing the coalbed methane
potential in much of rural Alaska. However, there
are areas that contain significant potential and could
be explored and developed if the right incentives
were available and plans developed. Detailed
geologic field work and surface outcrop sampling is
required in most areas before proceeding to the step
of drill testing for gas content. The cost of obtaining
coal gas content by drill coring is expensive, as
much as $1 million per shallow drill hole as noted
in the Fort Yukon experience. Additionally, the Fort
Yukon project confirmed that the low-rank lignite
coals present in a number of basins are not viable
options for producing methane gas.
It is crucial that a proper assessment of all requisite
geologic parameters be completed by qualified
personnel before development decisions are
made. A poorly conceived and executed CBM
exploration program in rural Alaska could raise
false expectations of the existence of a profitable
resource where it is not geologically reasonable.
Similarly, a poorly executed study could condemn a
resource not properly assessed or evaluated for test
sites. Like all energy resources, coalbed methane
can be an excellent source of heat and power, but
unique geologic conditions must be present, and
rigorous scientific and economic evaluations need be
performed before development can occur.
Conclusions
References
American Society of Testing Materials (ASTM), 1983,
Standard classification of coal by rank: ASTM designa-
tion D388-82 in gaseous fuels, coal and coke, Philadel-
phia, 1983 Book of Standards, v. 5.05.
Ayers, W.B. 2002, Coalbed gas systems, resources, and
production and a review of contrasting cases from the
San Juan and Powder River Basins. AAPG Bulletin, V.86,
No.11, PP.1853-1890.
Bustin, R.M., and Clarkson, C.R., 1998, Geological
controls on coalbed methane reservoir capacity and gas
content, International Journal of Coal Geology, Volume
38, Issues 1-2, Pages 3-26.
Merritt, R.D., and Hawley, C.C., 1986, Map of Alaska's
coal resources: Alaska Division of Geological & Geo-
physical Surveys Special Report 37, 1 sheet, scale
1:2,500,000
Rural Alaska Coal bed Methane: Application of New
Technologies to Explore and Produce Energy, Final
Report, 2006, Work Performed for grant DE-FC26-01-
NT41248 for the National Energy Technology Labora-
tory, Arctic Energy Office, US Department of Energy, 123
pages.
Saulsberry, J.L., Schafer, P.S. and Schraufnagel, R.A.,
eds., 1996, A Guide to Coalbed Methane Reservoir En-
gineering, Gas Research Institute Report GRI-94/0397,
Chicago, Illinois, 342 pages.
Schraufnagel, R.A. 1993, Coal bed methane production,
in B.E. Law and D.D. Rice, eds., Hydrocarbons from
coal: AAPG studies in Geology 38, 341-359.
Scott, A. R., 1995, Application of burial history and
coalification to coalbed methane producibility: in Geol-
ogy and Hydrology of Coalbed Methane Producibility in
the United States: Analogs for the World, (W.R. Kaiser,
A.R. Scott, and R. Tyler eds.), InterGas ’95, The Univer-
sity of Alabama Continuing Education Workshop, pages
127-136.
Stach, E. Mackowsky, M-Th., Teichmuller, M. Taylor,
G.H., Chandra, D., and Teischmuuler R., 1975, Stach’s
textbook for coal petrology (2nd Ed.): Gebruder Borntra-
eger, Berlin, Stuttgart, 428 pages.
222 223222223
Fuel cells are electrochemical devices that produce
electricity and heat without combustion by combining
a fuel with an oxidizer in separate half-cell reactions.
Fuel cells are simple in construction, consisting of
a “stack” of repeating components. They can be
very efficient: hydrogen-oxygen fuel cells have a
theoretical upper efficiency limit in excess of 70%.
They can be pollution free (when operating on pure
hydrogen) and have no moving parts in the stack
(although moving air and fuel does require mechanical
action, except on the smallest systems). Fuel cells
are widely considered to be leading candidates for
replacement of internal combustion engines in cars
and for distributed power systems.
These features would seem to make fuel cells an
ideal choice for efficient power generation, but
fuel cells are not yet practical. They must jump a
number of technical hurdles before being suitable for
wide-scale use. For example, fuel cells have strict
requirements for reactant purity and can be ruined if
these requirements are not met. One type of fuel cell
is intolerant of carbon monoxide and can be poisoned
simply by the 1-2 ppm of CO present in ambient air.
Other issues include cost and durability. The
University of Alaska Fairbanks has been involved in
the testing of approximately ten fuel cells in the last
decade. Despite ideal laboratory conditions, all have
failed. Causes of these failures included membrane
failure, catalyst poisoning, control system problems,
and design flaws. Also, despite their high cost, none
of these systems has shown efficiency greater than that
of a conventional diesel engine. Depending on design
and manufacturer, efficiencies have varied from the
low teens to the high 30s.
At this time, the only commercial fuel cell available is
a 400 kW unit developed by UTC Power. These units
are available at a $1,000,000 installed cost ($2,500/
kW); however, this product operates only on natural
gas, which is not a readily available fuel in most rural
Alaskan communities. Even where natural gas is
available, the capital cost for the fuel cell unit is higher
than the capital cost for a natural gas turbine, and the
efficiencies are approximately equal.
Fuel Cells
AEA Program Manager: Peter Crimp (771-3039)
Fuel Cell undergoing testing at the
University of Alaska Center for Energy
and Power
224 225224225
TECHNOLOGY SNAPSHOT: ALTERNATIVE FUELS
Fischer-Tropsch Fuels
Potential to produce liquid fuels at lower cost
than petroleum based fuels. Issues include CO2
sequestration, high capital cost, and technology
shortage
Propane Based on construction of gas pipeline, Tanana is
serving as pilot project
Fish Oil
Has been used economically by large fish processors,
fish oil from smaller processors could have potential
but has been slow to develop
Ethanol and Biodiesel Rapidly evolving technologies with limited
feedstock available at this time
Waste Oil Limited resource availability
Hydrogen Expensive to produce and store, pilot studies have
not been shown to be economical
Ammonia Requires very cheap electricity and diesel fuel costs
above $10/gallon for consideration
Electricity Possibility to use plug-in electric vehicles in areas of
the state where the cost of electricity is low
Alternative Fuels
Waste vegetable oil products are a great
source of energy for cars and trucks fit-
ted with the conversion system.
Program Manager: James Jensen (771-3043)
224 225224225
The idea of producing or otherwise using
alternative fuels is appealing. Liquid or gas-based
fuel can be stored and transported similarly to
existing petroleum-based fuels. Alternative fuels
such as hydrogen, ammonia, or electricity are
actually best thought of as tools to store energy until
a time when it is more valuable, or to move energy
to a place where it is more valuable. Alternative
fuels such as fish oil, Fischer-Tropsch fuels, and
biodiesel are simply fuels derived from underutilized
resources.
Fischer-Tropsch Fuels
Fischer-Tropsch (F-T) fuels are liquid-phase
synthetic fuels made from a feedstock known as
synthesis gas. Synthesis gas, or syn gas as it is
sometimes called, is a gas stream consisting of
primarily carbon monoxide and hydrogen. Syn gas
can easily be produced by gasifying coal or biomass,
or by reforming natural gas. The F-T process was
invented during the 1920s in Germany by Franz
Fischer and Hans Tropsch. It was used by Germany
during World War II to convert locally available
coal into a liquid fuel. Today the F-T process is
an established technology that has been utilized
commercially in South Africa for many years to
produce liquid fuels and feedstock for a wide variety
of petrochemical products. In the last several years,
as petroleum prices have risen and support for
energy independence has grown, the F-T process has
received renewed interest worldwide. Alaska, with
its massive coal, natural gas, and biomass resources
has taken part in this resurgence.
There are several, recently completed studies
analyzing the opportunities for coal-to-liquids (CTL)
or gas-to-liquids (GTL) projects in Alaska. The most
recent was a study commissioned by the Fairbanks
Economic Development Corporation (FEDC) after
CTL technology was identified as a technology of
interest by the Fairbanks Energy Task Force report
dated December 2007.
This study was completed by Hatch Engineering
and is available on the FEDC website. The report
considers three different potential plants sized at
either 20,000 or 40,000 bbl/d with a coal, or coal
and natural gas feedstock. The report assumes a
long-term supply of coal at $25/ton and a way to
sequester CO2 generated in the process. Given these
assumptions, projected capital costs range from 4.1
to 7.5 billion dollars (+/-40%). With an assumed
interest rate of return of 12%, the breakeven F-T
product price ranged from $108/bbl-$138/bbl
(Hatch Report, page 2). The United States Air Force
has expressed some interest in locating this plant
at Eielson Air Force Base. The plant would then
provide the air force with a substantial amount of
synthetic jet fuel. One of the largest unaddressed
hurdles for this project is finding a cost effective
method to sequester the massive amounts of carbon
dioxide produced from this project.
Another possible location considered for a CTL plant
is the Beluga coal fields on the west side of Cook
Inlet. The advantage here is that the coal is currently
a stranded resource, but close to a deep water port
with export potential to the west coast of the U.S.
and to overseas markets. CO2 sequestration would
still be a challenge, but there are depleted natural gas
wells that may prove viable for long-term storage.
ANGTL, LLC has been working to advance an
80,000 bbl/d plant in this area.
Introduction
226 227226227
Using natural gas as a feedstock for F-T fuels is
also a potential option for Alaska. Converting
natural gas to synthetic petroleum and transporting
it down the Trans Alaska Pipeline is one way to
access the natural gas on the North Slope. Another
option would be to use both coal and natural gas as
feedstock. The primary advantage here would be
that natural gas produces a syn gas that is high in
hydrogen, whereas coal produces a syn gas high in
carbon monoxide. By adjusting syn gas amounts
from each source, the CO to H2 ratio for the F-T
conversion could be optimized. The Hatch study
commissioned by FEDC considered a natural gas
and coal feedstock scenario as one of the options,
and they found it to be the economically preferable
option assuming that the natural gas is available.
A third possible feedstock for F-T fuels is biomass.
The primary advantage of using biomass is that
the process would be nearly carbon neutral over
the growth cycle of the biomass. For large scale
plants such as the two described above, finding
enough biomass and delivering it economically
to the plant would be challenging. Given this
problem, ANGTL and others have proposed smaller
plants that use woody biomass or municipal solid
waste as feedstock. At these smaller scales, the
economics have not been proven. Most successful
F-T technology licensors have shown little interest
in Alaska. Nonetheless, biomass as a feedstock
may have the most promise in rural Alaska, where
a small plant would produce fuel locally and
displace expensive diesel fuel. The operational and
technological risk of such a plant would be high.
Given Alaska’s ample supply of potential F-T
feedstocks, the technology could have a future in the
state; however, all potential projects face significant
challenges related to CO2 sequestration, high
capital costs, and ability to attract demonstrated F-T
technology licensors/vendors.
Propane
Propane is already used in rural Alaska, primarily
for cooking. The Alaska Natural Gas Development
Authority (ANGDA) is now assessing the feasibility
of using propane in river communities across the
state for electricity, as well as for space and water
heating. They are using Tanana as a demonstration
community to determine the feasibility of converting
existing appliances, testing small co-generation
systems, and converting heavy equipment and
vehicles to run on propane.
The Yukon-Kuskokwim Propane Demonstration
Project is designed to greatly expand use of propane
in rural Alaska. This pilot project subsidizes
propane costs to reflect the cost ANGDA anticipates,
assuming a natural gas pipeline is constructed and
a propalizing plant is installed at the Yukon River
crossing. The feasibility study includes assessing
the challenges associated with transporting propane
by existing barge companies and using propane
for electricity and space heating. Two 1000-gallon
propane tanks have been delivered to Tanana as part
of the project; however, there are some concerns
with Coast Guard regulations regarding propane
transport on navigable waterways.
While the cost of propane including delivery is not
a major expense for rural Alaskans in the small
volumes currently used, larger quantities do not
demonstrate an economic benefit when used for
space heating or power generation. Nonetheless,
there are some benefits to propane over diesel fuels,
primarily in terms of environmental concerns.
ANGDA’s preliminary estimates suggest that
communities could save money by using propane
instead of other fossil fuels if the natural gas pipeline
is built. The Tanana project is designed as a guinea
pig to get a better sense of conversion costs and
economic viability of the fuel.
226 227226227
Fish oil
Fish oil is a natural fuel that can be a co-product
of the fish processing industry. The oil is rendered
from fish waste using a multi-step process of heating,
pressing, centrifugal separation, and filtering. Fish
oil can be used either directly as a boiler fuel or
converted into a biodiesel and used for diesel engine
fuel and/or heating fuel. Raw fish oil is also being
used by a number of fish processors around the state
for onsite heating and power generation.
For the last couple of
years The University
of Alaska Arctic
Energy Technology
Development
Laboratory (AETDL)
has been testing
fish oil biodiesel
in a diesel gen-
set. The results
indicate that fish
oil biodiesel can be
used for diesel-based
generation but that
needs to be handled
differently from
standard diesel. Two of the biggest issues are its
comparatively high cloud point temperature (34ºF)
when solid waxy particles begin to form within
the diesel fuel and plug delivery systems, and its
tendency to oxidize more quickly than petroleum
based diesel. Using oxidized fish oil biodiesel in
a diesel generator can cause shellacking of fuel
injectors and damage the engine’s fuel handling
system. Despite these challenges, fish oil and fish
oil biodiesel can be a very economical alternative
in communities where large quantities of fish oil is
readily available. The recent rise in the cost of diesel
fuel has created greater incentive to render fish oil to
replace conventional diesel in rural Alaska. Alaska
currently produces roughly 8 million gallons of fish
oil each year. The majority of this oil is produced
by the largest fish processors in the Aleutian Islands.
Statewide, there is an estimated 13 million gallons of
unrecovered fish oil each year.
This unrecovered fish oil is primarily from the
fish waste of Alaska’s many small fish processors.
Individually, these
processors do not
have the throughput
to justify the capital
cost of fish oil
rendering equipment.
A portable fish oil
rendering facility
might provide a
solution to this
problem. For the
last coupleof years,
the Alaska Energy
Authority has tried
to encourage the
development of
such a module,
but unfortunately its efforts have met with little
success. Long distances between processing sites
and short, overlapping fishing seasons are significant
hurdles that hurt the economics of a portable fish oil
rendering module.
228 229228229
Ethanol and Biodiesel
In the U.S., most ethanol is made from terrestrial
food crops like corn and soy beans. These bio-
fuels are considered first generation bio-fuels
and are inappropriate for most of Alaska, due
to their long growth cycle and energy-intensive
production, to land usage, and to Alaska’s climate
and environmental conditions. There is a new push
across the United States for second generation bio-
fuels, which are more environmentally friendly and
made from feedstock that is otherwise wasted or
has little value. Options that have been considered
for Alaska include cellulosic ethanol and algae
biodiesel.
The raw materials needed to produce cellulosic
ethanol are plentiful in most parts of Alaska.
Cellulose is present in every plant, in the form
of straw, grass, and wood. It could be harvested
from local forests, or cellulose-producing crops
could be planted on land considered marginal for
agriculture, but biomass is not an energy dense
feedstock for making liquid fuels, so transportation
costs would be significant. In the Lower 48, the
Department of Energy announced funding for six
pilot cellulosic ethanol plants in 2007. These plants
will require considerable financial support through
grants and subsidies to operate, but the hope is that
the technology will advance to where the process
becomes economic and cost-competitive with other
alternatives.
Over the last few years, algae biodiesel has received
significant attention worldwide. This is due to
algae’s fast growth rate and high oil content. Much
research is going into this potential feedstock for
biodiesel; however, with Alaska’s limited amount of
sunshine the state has not been the focus of any of
this activity. Alaska’s current options for biodiesel
feedstock are fish oil, and waste vegetable oil.
Waste Vegetable Oil
Biodiesel from waste vegetable oil or straight waste
vegetable oil represents a limited opportunity in
Alaska.
Only the largest communities, Anchorage, Fairbanks,
and Juneau, have large enough quantities of waste
vegetable oil to commercially utilize the resource.
All of these communities have groups working
toward developing this resource for biodiesel
production; however, the volumes will always be
small when considered from a statewide perspective.
In areas where even smaller quantities of waste
vegetable oil are available, heating applications to
be best. There are commercially available waste-
oil burners that can burn waste vegetable oil and/or
used motor oil; the smallest units available are rated
around 100,000 Btu/hr and cost around $5,000.
Hydrogen
Hydrogen is not a source of energy, but a way to
store energy. You don’t mine hydrogen; you use
electricity to make it. The ability to store energy
is valuable in areas of the state with significant
renewable energy resources but limited energy loads
to make use of them. This scenario describes much
of Alaska, where there is a nearly limitless supply
of wind, wave, and tidal energy. Hydrogen could
one day play a role in capturing that energy and
transporting it to market. If this is ever to happen,
cost reductions and/or efficiency gains need to be
made in the areas of producing, compressing, and
storing hydrogen. As hydrogen-related costs drop,
markets can develop that utilize the hydrogen. For
more information on hydrogen as an energy storage
option, see the section on Energy Storage.
228 229228229
Ammonia (NH3)
Ammonia has been used as a fuel in certain
applications, to power buses in Belgium during
World War II and to power the X15 rocket airplane,
that set speed and altitude records in the early 1960s.
Now ammonia has been proposed as an alternative
to fossil fuels for internal combustion engines
for stationary generator and vehicle applications.
Ammonia is preferable to hydrogen in terms of
energy storage, but it has approximately half the
energy density of diesel. This means it requires
twice the storage volume to achieve the same
energy content. Nonetheless, ammonia is a viable
alternative and it can run in most existing engines
with only minor modifications to carburetors and
injectors. Ammonia as fuel has no serious problems
associated with it in terms of toxicity, flammability,
or emissions. It is widely produced and distributed,
although transporting ammonia over long distances
would not be economical due to its lower energy
content per pound. About 80% or more of the
ammonia produced is used for fertilizing agricultural
crops. The Agrium fertilizer plant on the Kenai
Peninsula produced 280,000 tons of ammonia
fertilizer annually from a natural gas feedstock and
shipped the product to many countries across the
globe. The plant shut down in 2007 due to shortage
of natural gas supply in Cook Inlet.
Manufacturing ammonia onsite in rural Alaska
is a possibility. It could be manufactured from
renewable energy sources using an air separation
plant to collect nitrogen (air is composed of 78%
nitrogen), and an electrolyzer to generate hydrogen
from water. In contrast to using the hydrogen
directly, converting the hydrogen to ammonia
eliminates the need for compression, as ammonia can
be stored and transported as a liquid at reasonable
pressures. This means that existing infrastructure
could be used for handling, storing, and transporting
without the need for exotic storage material. In
addition, industry standards and regulations exist for
the safe handling and storage of ammonia.
Based on the expected cost of the equipment,
ammonia would not become economic to use as a
fuel until the cost of diesel reached $10.45 per gallon
(see analysis above). This is an optimistic analysis
based on commercial production of 4.5 Mmbbl per
year and no electricity cost. A more realistic analysis
calculated a break-even equivalent value of diesel
fuel at $13.50.
Since diesel is not expected to reach this value, even
in rural Alaska in the near future, this option does
not appear economically viable unless the equipment
cost (electrolyzer and air separation plant) is reduced
significantly, or there is a pilot project where the
capital costs are offset by grants.
Optimistic Break-Even Point for Ammonia Fuel Production
$ 4.10 $/kg H2
58 % electricity cost
$ 1.72 $/kg assuming no cost of electricity
$ 336,713
cost per year for electrolyzer including capital
and O&M
$ 1,779,766 full plant cost per year, capital and O&M only
$ 1,779,766
Annual value needed for capital recovery and
operation
1,221 tons ammonia produced per year
$ 1,457.15 break even cost per ton of ammonia
$ 75.19 Price per MMBtu for ammonia
$ 10.45 Equivalent price per gallon diesel fuel
230 231230231
Electricity
Electricity has the ability and, under some scenarios
the economic justification to replace petroleum-
based transportation and heating fuel. Over the last
few years, as heating fuel prices have increased,
Alaska has seen communities with cheap hydro-
based power move towards greater use of electric
space heating. This trend will continue in areas
where plentiful supplies of renewable electricity cost
less on a delivered BTU basis than heating fuel. In
addition to heating, electric-power transportation is
an emerging option. There are already commercially
available electric vehicles, snow machines, and
four wheeler. As battery technology improves,
these vehicles will cost less and show improved
range and efficiency. Plug-in electric vehicles may
also provide great advantage to small grids that
have access to intermittent renewable power. With
continued technology development, the batteries
of these vehicles may be able to stabilize the grid
by drawing or dispatching power whenever there
is a supply/load imbalance. This capability would
allow small grids to use higher percentages of non-
dispatchable renewable power without reducing
power quality.
230 231230231
Snettisham Hydropower Plant near Juneau. Hydro power is some
of the lowest cost energy in the state and can be used to displace
high-cost heating and transportation fuels.
232 233232233
Explanation to Database Methodology
How to Read and Interpret this Report
This report is the result of a process begun in the
spring of 2008 when the Alaska Energy Authority
held a series of regional and community meetings
to address the issue of rising energy prices. At that
time, the climbing price of crude oil resulted in
large increases in the cost of energy for residents
throughout the state, especially for those remote
communities.
At these community meetings, AEA director Steve
Haagenson outlined a process that would involve
collecting information from local communities to
be synthesized into a single state energy plan. At
the meetings, maps were created that showed where
community residents were aware of possible local
energy resources.
In addition to the information collected in the
community meetings, several other sources of
information have been used. AEA organized
working groups based on technology: diesel
efficiency, heat recovery, wind, hydro, biomass,
geothermal, and hydrokinetic and wave energy.
Each of these groups held meetings at AEA, with
interested parties joining the discussion by phone.
At the end of this process, a list of communities
where each of these technologies might be applicable
was created, along with estimates of the cost of using
these technologies.
Another important source of information for
this report is the PCE (Power Cost Equalization)
program, designed to reduce the cost of electricity
for residences in remote communities. Information
collected in the administration of this program is
the most complete data available for the state of
Alaska. This data set contains information about
diesel prices, electric prices, and consumption of
electricity by a community. This information applies
only to fuel used for power generation and it gives
no indication of heating fuel prices or use, or fuels
used for transportation.
Energy information collected by the Institute for
Social and Economic Research (ISER) has been
used to estimate the heating fuel and transportation
fuel used in each community. However, because no
process is in place for collecting this information, the
data, based on extrapolations from values collected
for 20 sample communities, is incomplete. As
heating fuel costs are particularly burdensome for
households in rural communities, this lack of data
is a major weakness of this analysis. ISER has
requested funding to address this issue by creating
an energy information data network to collect energy
cost and consumption data from all communities. It
is hoped that future versions of this document will
contain more defensible data.
Another source of information is the Department of
Community and Regional Affairs. This department
supplied a complete copy of their database for use in
this database. The population data, location, culture,
and history sections are taken directly from it. The
United States Census data is taken from the same
database, but from the 2000 census. New data will
not be collected in the next census. This is a further
argument for support of the ISER energy information
data network.
Every attempt has been made to collect the most
reliable information available for use in this report,
so that it will be a useful tool for communities,
utilities, funding agencies, and others to make good
decisions about how best to provide energy to each
community. However, the readers of this report
must note that in many cases the reliability of the
underlying data is not as robust as they might wish.
This necessarily limits the utility of this tool. It is
hoped that better data can be collected and that this
database can be improved.
Layout of the Community Reports
This report is based on a community by community
analysis and is divided into five basic sections: the
cover page, the community description, analysis
232 233232233
Explanation to Database Methodology
of the current energy situation, possible upgrades
to the existing power plant, and locally available
alternative resources.
Page 1 (Cover Page):
The cover page contains five basic items: the name
of the community, a map of Alaska showing the
location of the community, a pie chart and a per-
capita table showing the estimated breakdown
of energy use in the community, and two meters
showing the current cost of energy as compared with
possible alternatives.
Energy Use Pie Chart and Per-Capita Data:
The data in this pie chart is based on the PCE data
collected and the ISER extrapolations for each
community. As noted above, the PCE data is
more complete and trustworthy than the other two
components, but even the PCE data is sometimes
incomplete. For example, Akutan PCE data reports
only fuel consumed in the community power plant,
but the community has a fish processer that operates
its own power plant. The community population
counts the people working at the fish plant. When
these facts are combined, it appears that the energy
consumption in this village is low on a per-capita
basis, but this simply reflects the lack of data on
the fuel consumption at the fish processer. Other
communities, like Cold Bay, have the opposite
problem: the census data indicates only 72 people
in the community, but an average electrical load of
304 kW and high fuel prices. This results in a high
calculated per capita energy cost.
The Electric and Heat Meters:
These meters are a graphical presentation of the
results of the analysis of the current energy costs
in each community normalized to $110/bbl crude
oil and the calculated costs of alternatives. The
most trustworthy numbers are the current costs for
diesel-generated power and for heating fuel. These
meters indicate when an alternative appears to be
lower in cost than existing technologies (projects
that might be favorable to pursue), as compared with
projects that result in higher energy costs (ones that
probably should be avoided). How these numbers
are calculated is covered in the section below. The
yellow background indicates the possible range of
costs as the price of diesel fuel, with the bottom
estimated at $50 per barrel, and the top at $150 per
barrel.
Page 2: Community Information
If a community is in the PCE program, this will be
indicated by a ‘PCE’ designation besidw this line.
Some communities have been included that are not
PCE communities, but the information that follows
will be incomplete.
Current Energy Status-Electric (PCE)
This section begins with the most important and
most difficult number in the plan: the Estimated
Local Fuel Cost at $110/bbl in each community.
The numbers included in this report have been
estimated by ISER and AEA, and are the same as
those used for evaluation in the Renewable Energy
Fund reviews.
Utilities are required to submit receipts for fuel
deliveries in order to get reimbursed from PCE, but
three things affect the price they pay: the cost of
crude oil at the time of purchase, the cost of shipping
that fuel to that community, and the rates that the
utility is able to negotiate with the fuel supplier.
Some utilities have formed fuel-buying co-ops to
increase their purchasing power in the market, and
they have been able to negotiate better prices than
others. AVEC managed to obtain a long-term fuel
purchase agreement with their fuel supplier that
locked in prices for several years and delayed the
onset of higher fuel prices. This arrangement was
good for AVEC and seemingly good for the state;
however, a simple averaging of these fuel prices with
other villages underestimates the cost of fuel in that
village.
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Explanation to Database Methodology
The transportation component is also a tricky
number. In discussions with both utilities and fuel
suppliers, the cost of delivering fuel to any given
community is based on the distance and difficulty
of delivery. These numbers are not published for
antitrust reasons so they are not known to the writers
of this report. Adding to the confusion is the way in
which these numbers are reported to the PCE. For
AVEC, fuel is purchased in five or six ‘drops’ at the
refinery, then delivered to multiple villages. The fuel
cost reported to PCE seems to be the price paid per
gallon for that entire drop of fuel, and so it averages
the cost of transportation over all the villages served
by that particular shipment, regardless of the actual
transportation cost calculated by the shipper. Add
to that the rapidly changing price of crude oil in
times of high volatility (like the past few years). The
net result is a data set that seems to belie statistical
interpretation.
One of the criteria of this planning process was to
evaluate the cost of diesel power at $110 per barrel
crude oil prices, so a model needed to be created
that would estimate this number by community.
However, when village fuel prices reported to
PCE are plotted against crude oil prices and linear
regressions are calculated, about 10% of villages
have fuel prices below the refinery cost. Since
this result cannot be real, fuel price values for
these communities were adjusted upward. If some
communities are statistically low, one suspects that
an equal number of communities are statistically
high, but no adjustments were made to these higher
priced communities. It is also worth noting that
many (though not all) of the communities that
needed to be adjusted upward were AVEC villages,
suggesting that the fuel purchase agreement has been
very good for that utility.
Average Efficiency is calculated as the number of
kilowatt hours sold (Average Sales) divided by the
Consumption in 2007. A value of 14 kW-hours per
gallon for small communities and of 14.75 kW-hours
per gallon for larger communities is considered to be
achievable. Values lower than this would indicate
that efficiency gains could be achieved.
Consumption in 2007 is the total gallons of fuel
used in the power plant and is taken directly from the
PCE data.
Average Load is calculated as the Average Sales
divided by the number of hours in a year from the
PCE data.
Average Peak Load is estimated as twice the average
load above.
Average Sales is the number of kilowatt hours sold
per year and it is taken directly from PCE numbers.
Fuel COE (Cost of Electricity) is calculated as
the Estimated fuel cost at $110/bbl divided by the
Average Efficiency.
Est O&M is the estimated Operations and
Maintenance costs for diesel generators, set at
$.02 per kW-hr for every community, based on the
experience od diesel operations in the state.
NF COE is the PCE reported Non-Fuel Cost divided
by the number of kilowatt hours sold minus the $.02
for O&M.
This number is particularly inconsistent between
villages, due to many factors, and has been the topic
of many discussions about the PCE program. For
example, if a utility borrows money to purchase
a new generator, the cost of that purchase will be
reflected in this number; but if the new generator was
paid for by a grant from the Denali Commission, that
purchase will not be included. Also, administrative
support for billing and customer service is handled
in a variety of ways in different communities. AVEC
does not report these non-fuel costs by individual
community, but rather provides an aggregate value to
the PCE program.
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Explanation to Database Methodology
Current Fuel Costs are based on the number of
gallons consumed times the Estimated Local Fuel
Cost at $110/bbl.
Estimated O&M is the number of kilowatt hours
sold times $.02.
Other Non-Fuel Costs are from the PCE report, but
adjusted by the O&M above.
Total Electric Cost is calculated as the sum of the
previous three numbers
Current Energy Status – Space Heating
(Estimated)
2000 Census Data is from the Community and
Regional Affairs database; and is most helpful in
indicating which communities use wood for heat.
Some communities which may have large hydro
plants nearby may use electric heat, but these
communities typically are not PCE communities,
as this program is specifically designed for those
depending on diesel power generation.
2008 Estimated Heating Fuel Use is a community-
wide estimate of the total gallons of fuel used
for heating calculated by ISER, based on several
variables including population, number of
households, square footage per household, and
heating degree days. The sample size for this
estimate is small, and the regression is less robust
than desired. Improving this estimate is a goal of
ISER’s energy information data network.
Estimate Heating Fuel Cost per Gallon is calculated
as the Estimated Local Fuel Cost at $110/bbl plus
$1.00 per gallon. Reports from many villages
(especially AVEC villages) indicate that heating
fuel prices are far higher than this measure would
indicate.
$/MMBtu Delivered to User is based on the
Estimated Heating Fuel Cost per gallon times 9.05.
This factor comes from taking 1 million Btus divided
by the lower heating value of a gallon of heating fuel
(130,000 Btu/Gallon) times an efficiency of 85%
for a heating oil appliance. The equivalent cost for
Anchorage natural gas users is currently about $9.56
per MMBtu delivered.
Total Heating Oil figure is the Estimated Heating
Fuel Cost per Gallon times the 2008 Estimated
Heating Fuel Use.
Current Cost of Energy – Transportation
Cost (Estimated)
Estimated Diesel is an extrapolated number from a
previous ISER model. This model, not considered
robust, should be used with caution. Also please
note that this number does not include gasoline used
for motor fuels. However, this represents the best
available estimate at the current time.
Estimated Cost is based on a retail markup of $1 per
gallon over the cost of fuel delivered to the utility for
power generation. This is identical to the estimate
for that of heating fuel, but it is well below the
current cost of transportation fuels in some villages.
Total Transportation cost is the product of the two
numbers above.
Energy Total is the sum of the electrical, heating,
and transportation costs for the entire village.
Possible Upgrades to Existing Diesel Plant
(estimate)
Many power plants are due for upgrades, some for
safety reasons, some for efficiency reasons. This
section estimates the cost of those upgrades, and the
impact on the cost of power if the expense is born by
the consumer.
Upgrade Needed is the level of improvement that
needs to be made to the power plant. This can
range from a complete power plant replacement
($3,000,000), powerhouse module upgrade
236 237236237
($1,350,000), powerhouse upgrade ($1,000,000),
switch gear upgrade ($600,000), or generator
upgrade ($150,000). Note that these estimates are
fixed, and do not depend on the size of the village or
the size of the power plant.
Status is the place this project is in the statewide list
for these projects.
Achievable Efficiency is an estimate of what a well-
managed power plant of this size: 14 kW-hours per
gallon of diesel fuel for plants under 400 kW, and
14.75 kW-hours per gallon for plants over this size.
Fuel Use is the new, calculated fuel consumption
with the more efficient power plant, assuming the
efficiency above is reached.
Estimated Cost is an estimate on how much the
upgrade will cost. This is based only on the upgrade
level, as listed above.
Annual Capital Cost is based on the estimated cost
amortized at 3% over 15 years.
New Fuel Cost is the Fuel Use times the estimated
local fuel cost at $110 per barrel.
New Electrical Cost is the cost of electricity after the
upgrade. This may or may not be cheaper than the
existing cost of power.
Savings is an estimate of how much money this
upgrade will save the community, although this
savings may be negative. However, many power
plant upgrades must be undertaken for environment,
safety, or other reasons. The savings might not be the
reason for the upgrade.
Diesel Engine Heat Recovery
Given the higher cost of fuel in recent years, one
way to save fuel at a community level is to recover
as much heat as possible from the diesel generator
plant. Many communities have already installed this
equipment, although some of these installations are
no longer operable. This section summarizes the
economics of this energy source.
Heat Recovery Installed indicates communities
where heat recovery systems are known to be
installed. A blank indicates that there is no record of
a heat recovery installation in this community.
Is It Working Now indicates the current state
of operation of the heat recovery system. ‘Yes’
indicates that the system is working; ‘No’ indicates
that the system is not currently working. If the heat
recovery system is working, the savings indicated
in the following fields have already been realized.
However, the reporting on these heat recovery
systems is sketchy, but this sectionis included to
emphasize the importance of keeping these systems
operational.
BLDGs Connected and Working indicates which
buildings are currently receiving heat from the heat
recovery system.
Water Jacket indicates the total amount of heat that
could be collected from the water jacket of the diesel
engines, given in gallons of fuel equivalent. This
number is 15% of the total gallons of fuel consumed
by the diesel generator.
Value is an estimate of the value of the heat if it
can be used to replace diesel fuel, at local prices for
heating fuel. Note that in almost all cases, not all
of the recovered heat can be used (like heat in the
summer), but given the general need for heat for
much of the year in most places in Alaska, recovery
of most of this heat is possible.
Stack Heat refers to energy that can be recovered
from the exhaust stack of the diesel generators. In
the past, attempts to recover heat from this source
proved problematic, due to soot accumulation and
corrosion. Newer engines produce less soot and
newer fuels have much less sulfur, so these systems
are now proving feasible, as long as enough heat is
left in the exhaust stream to prevent condensation in
the stack. These systems are currently recommended
only for generators larger than 400 kW and for
Explanation to Database Methodology
236 237236237
villages of more than 700 people. When these
criteria are met, an estimated 10% of the fuel value
used by the engine can be recovered.
Installed cost is estimated based on $2800 times
the average power output of the plant, based on
installation costs from the state.
Annual I&D costs are calculated at 3% interest and
15 years.
Savings are the estimated savings to the community
on heating costs. Please note that in communities
where heat recovery is already being done, these
savings have already been realized, but these savings
are not included in the community heating fuel
estimates, so they are listed here.
Alternative Technologies
This section lists the alternative technologies
available to local communities. Several fields are
included for each technology, and some are specific
to a given technology.
The first technologies that are listed are commercial
or near commercial technologies, where estimates
have been made of the approximate cost of
installing these technologies in a given village.
These technologies are conventional hydro, wind,
geothermal, and biomass.
The common fields include the top row:
Installed kW indicates the total installed capacity of
the alternative technology. Some alternative projects
are defined by the size of the resource (such as
geothermal or hydro) while others are defined by the
size of the generators selected to match the peak load
of the community (wind and biomass).
kW-hours Per Year is an estimate of the total power
production of the alternative on an annual basis.
Annual Electric is the kW-hours per year divided
by the Average kilowatt Hours Sold from PCE, and
is reported as a percentage. This number may be
less than 100%, indicating that the installed project
cannot meet all of the community power demand,
or it may be greater than 100%, indicating that
the available power is more than the community
currently uses on an annual basis. However,
intermittent resources such as wind do not
necessarily match the load profile of the community,
and modeling is necessary to determine the precise
amount of energy that can be used to displace the
current diesel load. In this case, this number is
simply included to provide a sense of how big the
project is compared to the local market. In both
wind and hydro, models estimated how much diesel
generated power could be displaced. That number is
given here. Excess power may be converted to heat,
but that energy is not included in calculations.
Other common fields are the economic numbers in
the middle column:
Capital Cost is an estimate of the installed cost
of the project in the community. These numbers
are based on statewide estimates, old engineering
studies, or engineering estimates, and are included to
provide a rough calculation of the cost of this project
in this community. No projects will be funded based
on this number; an engineering feasibility study is
required.
Annual Capital Cost is based on the capital cost
above, using a 3% interest rate and a 20-year
payback period, except for hydro, where a 50-year
payback is used. The cost per kilowatt hour is also
calculated.
Annual O&M is the estimated Operations and
Maintenance costs for the technology, usually based
on a percentage of the installed capital costs. The
cost per kilowatt hour is also calculated.
Fuel Costs are the anticipated annual fuel costs for
the alternative energy source. Biomass is the only
alternative that has a fuel cost in the current model.
The cost per kilowatt hour is also calculated.
Explanation to Database Methodology
238 239238239
Total Annual Cost is the sum of the Capital, O&M,
and Fuel costs above. The cost per kilowatt hour is
also calculated. This cost does not include the non-
fuel costs, or the balance of diesel power that might
still be needed to provide energy to the community.
New Community COE is the new cost of electricity
based on adding this resource to the mix. This
number includes the non-fuel costs (the costs of
operating the utility) and the cost of operating
the diesel plant for power when the alternative is
not available. There are two cases that must be
discussed: (1) when the total kW-hours/year is less
than the total electrical demand for the community,
and (2) when the total kW-hours per year is above
the total village electrical demand.
For Case (1), the assumption made in this calculation
is that all electrical power can be used to displace
diesel up to the annual power consumption of
the village, which is not likely to be true for
technologies like wind. The New Community COE
is calculated as the cost of the new alternative, times
the amount of power it provides, plus the cost of
generating diesel power for the balance, plus the
non-fuel costs.
For Case (2), the cost of electricity is calculated as
the total annual costs of the alternative source, plus
the non-fuel costs, divided by total kilo-Watt hours
sold in the community. For large-scale geothermal
or hydro projects, this may result in a high cost of
electricity even though the cost per kW-hr above
might be low, as the cost of developing the resource
must be paid from a small local base.
Savings is calculated as the difference between the
current cost of producing electricity, minus the cost
of producing electricity with the alternative. In some
case, this is a positive number (the new technology
is more cost effective), while in others it is negative
(the new technology is less cost effective than the
existing power plant).
Wood
Wood is an abundant fuel in some parts of the
state, but nearly absent in others. Today, almost
all wood used is for space heat, not for electrical
power generation. New power generators are being
developed that might allow for electrical power to
be generated from wood or other biomass, and the
cost of electricity from these systems was modeled
in a paper by Crimp, Strandberg, and Colt in 2007.
The cost estimates given in this report for electrical
power generation are from that report. For this
calculation, a cost of $225 per cord was assumed
for all communities, although some might have fuel
available for considerably less cost. These wood
generators will also produce significant amounts of
heat, but this value is not included in the calculation.
Wind-Diesel Hybrids
Unlike wind power in grid connected areas where
wind contributes only a small amount of the total
needed power, small Alaskan communities with wind
turbines would like to replace a significant amount
of their total village power needs with wind. This
means that all wind systems are high penetration,
and care must be taken with the integration of the
wind with the diesel plant.
The Wind Class and wind speed numbers indicate
the size of the resource in the community. Small
communities of class 5 and above and larger
communities of class 4 and above are included in
this study. The installed kW is based on the peak
load of the community. Modeling with HOMER
was done for most of the small communities, and is
the basis of the economic calculations, but it should
be stressed that the economic analysis here is very
simplistic, and should be used only for a screening
analysis.
Hydro
The projects described in this section are all
conventional hydro projects, not run-of-the-river
Explanation to Database Methodology
238 239238239
hydrokinetic projects (these are still too new for
accurate economic estimates to be calculated).
Many of these hydro sites have been identified
over the past decades, and some of them have been
studied quite extensively. The data in this section
is by far the most complete of any of the alternative
electrical systems.
The Installed kW and the kilowatt-hours per year
numbers are estimated based on flow data from
the streams, but the reliability of the information
depends on the level of study completed. The site
name is the location of the project. The plant factor
(how much of the year the stream can produce
power), penetration factor (how much of the existing
load could be replaced given the plant factor), and
% community energy (a simple comparison of kW-
hours generated per year to kW-hours sold under
PCE) are all attempts to estimate how much of the
existing energy base might be displaced by the
installed hydro project.
Some hydro projects are quite large, and might
indicate potential for power to be used for other
applications.
Geothermal
Alaska has many potential geothermal sites, but few
of these are located close enough to large power
markets to justify their development. Development
of a geothermal power system requires significant
investment during the exploration phase, so much
of the costs of the project are incurred before the
ultimate economic viability can be determined.
Most of the geothermal projects described here have
both a shallow resource estimate and a deep resource
estimate.
Biomass For Heat
Recent development of high efficiency wood stoves
using a gasification design allow for clean burning of
cordwood. These are most commonly refered to as
Garn stoves, but other manufactures are marketing
similar designs. Most communities have some
form of biomass that could be used to fuel these
stoves, but their size requires a fairly large heat
load (community buildings, schools, or multiple
residences) in close proximity to justify their
installation. If these criteria can be met and fuel can
be obtained, significant savings can be attained.
Other Resources
There are several other potential resources for
remote communities, including wave, tidal, coal,
coal bed methane, and natural gas. No economic
analysis has been done for any of these resources
due to lack of reliable cost information, but these
resources are listed as potential sources for future
development.
Renewable Energy Fund Applications
This section briefly lists the applications submitted
to the Alaska Rewable energy fund.
Explanation to Database Methodology
240 241240241
Absorption Chiller - A device that
uses heat energy rather than mechanical
energy to cool an interior space through the
evaporation of a volatile fluid.
Active Solar - A solar water or
spaceheating system that uses pumps or
fans to circulate the fluid (water or heat
transfer fluid like diluted antifreeze) from the
solar collectors to a storage tank subsystem.
Alternative Fuels - A term for
“nonconventional” transportation fuels
derived from natural gas (propane,
compressed natural gas, methanol, etc.) or
biomass materials (ethanol, methanol, or
biodiesel).
Anemometer - An instrument for
measuring the velocity of wind; a wind
gauge.
Availability - Describes the reliability of
power plants. It refers to the number of hours
that a power plant is available to produce
power divided by the total hours in a set time
period, usually a year.
Avoided Cost - The incremental cost to
an electric power producer to generate or
purchase a unit of electricity or capacity or
both.
Biodiesel - A domestic, renewable fuel
for diesel engines derived from natural
oils like fish and vegetable oil; produced
by a chemical process that removes the
glycerin from the oil and meets a national
specification (ASTM D 6751).
Biomass - Organic matter that is available
on a renewable basis, including agricultural
crops and agricultural wastes and residues,
wood and wood wastes and residues, animal
wastes, municipal wastes, and aquatic
plants.
Bioenergy - Electrical, mechanical,
or thermal energy or fuels derived from
biomass.
Capacity Factor - The ratio of the
average power output of a generating unit
to the capacity rating of the unit over a
specified period of time, usually a year.
Co-firing - Using more than one fuel
source to produce electricity in a power
plant. Common combinations include
biomass and coal, biomass and natural gas,
or natural gas and coal.
Cogeneration - The generation of
electricity and the concurrent use of rejected
thermal energy from the conversion system
as an auxiliary energy source.
Conduction - The transfer of heat
through a material by the transfer of kinetic
energy from particle to particle; the flow
of heat between two materials of different
temperatures that are in direct physical
contact.
Convection - The transfer of heat by
means of air currents.
Dam - A structure for impeding and
controlling the flow of water in a water
course, it increases the water elevation to
create hydraulic head. The reservoir creates,
in effect, stored energy.
District Heating System - Local
system that provides thermal energy through
steam or hot water piped to buildings
within a specific geographic area. Used for
space heating, water heating, cooling, and
industrial processes. A common application
of geothermal resources.
Distributed Generation - Localized
or on-site power generation, which can be
used to reduce the burden on a transmission
system by generating electricity close to
areas of customer need.
Distribution Line - One or more circuits
of an electrical distribution system on the
same line or poles or supporting structures,
usually operating at a lower voltage relative
to a transmission line.
Domestic Hot Water - Water heated for
residential washing, bathing, etc.
Electrical Energy - The amount of work
accomplished by electrical power, usually
measured in kilowatt-hours (kWh). One kWh
is 1,000 Watts generated for one hour and is
equal to 3,413Btu.
Energy - The capability of doing work;
different forms of energy can be converted to
other forms, but the total amount of energy
remains the same.
Energy Crop - A plant grown specifically
for use in biomass electricity or thermal
generation.
Energy Storage - The process of storing
or converting energy from one form to
another for later use. Storage devices and
systems include batteries, conventional and
pumped storage hydroelectric, flywheels,
compressed gas, hydrogen, and thermal
mass.
Ethanol - A colorless liquid that is the
product of fermentation used in alcoholic
beverages, in industrial processes, and as
a fuel.
Feedstock - A raw material that can be
converted to one or more products.
Fossil Fuels - Fuels including oil, natural
gas, and coal formed in the ground from the
remains of dead plants and animals. It takes
millions of years to form fossil fuels.
Fuel - Any material that can be burned to
make energy.
Fuel Oil - Any liquid petroleum product
burned for the generation of heat in a
furnace or firebox or for the generation of
power in an engine. Domestic (residential)
heating fuels are classed as Nos. 1, 2, 3;
Industrial fuels as Nos. 4, 5, and 6.
Generator - A device for converting
mechanical energy to electrical energy.
Geothermal Energy - Energy produced
by the internal heat of the earth; geothermal
heat sources include: hydrothermal
convective systems; pressurized water
reservoirs; hot dry rocks; manual gradients;
and magma. Geothermal energy can be
used directly for heating and cooling or to
produce electric power.
Head - A measure of fluid pressure,
commonly used in water pumping and hydro
power to express height that a pump must lift
water, or the distance water falls. Total head
accounts for friction and other head losses.
Glossary
240 241240241
Heat Pump - An electricity powered
device that extracts available heat from one
area (the heat source) and transfers it to
another (the heat sink) to either heat or cool
an interior space or to extract heat energy
from a fluid.
Hybrid System - An energy system that
includes two different types of technologies
that produce the same type of energy;
for example, a wind turbine and a solar
photovoltaic array combined to meet electric
power demand.
Hydroelectric Power Plant - A power
plant that produces electricity by the force
of water falling through a hydro turbine that
spins a generator.
Hydrogen - A chemical element (H2) that
can be used as a fuel since it has a very high
energy content.
Landfill Gas - Produced in landfills,
naturally occurring methane that can be
burned in a boiler to produce heat or in a
gas turbine or engine-generator to produce
electricity.
Large-scale or Utility-scale - A power
generating facility designed to output enough
electricity for purchase by a utility.
Load - Amount of electricity required to
meet customer demand at any given time.
Meteorological (Met) Tower - A
structure instrumented with anemometers,
wind vanes, and other sensors to measure
the wind resource at a site.
Ocean Energy Systems - Energy
conversion technologies that harness
the energy in tides, waves, and thermal
gradients in the oceans.
Ocean Thermal Energy
Conversion
(OTEC) - The process or technologies
for producing energy by harnessing the
temperature differences between ocean
surface waters and that of ocean depths.
Organic Rankine Cycle - A system
that uses a hydrocarbon instead of water
as a working fluid to spin a turbine, and
therefore can operate at lower temperatures
and pressures than a conventional steam
process.
Panel (Solar) - A term generally applied
to individual solar collectors, and typically to
solar photovoltaic collectors or modules.
Passive Solar Design - Construction
of a building to maximize solar heat gain in
the winter and minimize it in the summer,
thereby reducing the use of mechanical
heating and cooling systems.
Peak Load – The amount of electricity
required to meet customer demand at its
highest.
Penstock - A component of a hydropower
plant; a pipe that delivers water to the
turbine.
Photovoltaics (PV) - Devices that
convert sunlight directly into electricity
by using semiconductor materials. Most
commonly found on a fixed or movable
panel; also called solar panels.
Power - Energy that is capable of doing
work; the time rate at which work is
performed, measured in horsepower, Watts,
or Btu per hour.
Production Tax Credit (PTC) –
An incentive that allows the owner of a
qualifying energy project to reduce his taxes
by a specified amount. The federal PTC for
wind, geothermal, and closed-loop biomass
is 1.9 cents per kWh.
Radiation - The transfer of heat through
matter or space by means of electromagnetic
waves.
Railbelt - The portion of Alaska that is
near the Alaska Railroad, generally including
Fairbanks, Anchorage, and the Kenai
Peninsula.
Renewable Resource - Energy
sources that are continuously replenished
by natural processes, such as wind, solar,
biomass, hydroelectric, wave, tidal, and
geothermal.
Run-of-River Hydroelectric – A type
of hydroelectric facility that uses the river
flow with very little alteration and little or no
impoundment of the water.
Small-scale or Residential-scale - A
generating facility designed to output enough
electricity, generally 250 kW or smaller.
to offset the needs of a residence, farm, or
small group of farms.
Solar Energy - Electromagnetic energy
transmitted from the sun (solar radiation).
Solar Radiation - A general term for
the visible and near visible (ultraviolet and
near-infrared) electromagnetic radiation that
is emitted by the sun. It has a spectral, or
wavelength, distribution that corresponds
to different energy levels; short wavelength
radiation has a higher energy than long-
wavelength radiation.
Tidal Power - The power available from
either the rise and fall or flow associated with
ocean tides.
Transmission Grid - The network
of power lines and associated equipment
required to deliver electricity from generating
facilities to consumers.
Turbine - A device for converting the flow
of a fluid (air, steam, water, or hot gases) into
mechanical motion.
Wave Energy - Energy derived from the
motion of ocean waves.
Wind Energy - Energy derived from the
movement of the wind across a landscape.
Wind is caused by the sun heating the
atmosphere, earth, and oceans.
Wind Turbine - A device typically having
two or three blades, that converts energy in
the wind to electrical energy.
Windmill - A device that converts energy in
the wind to mechanical energy that is used to
grind grain or pump water.
Wind Power Class - A class based on
wind power density ranging from 1 (worst) to
7 (best).
Wind Power Density - The amount of
power per unit area of a free windstream.
Wind Resource Assessment - The
process of characterizing the wind resource
and its energy potential for a specific site or
geographical area.
Glossary
242 243
Volt (V) - A unit of electrical force equal to that amount of
electromotive force that will cause a steady current of one
ampere to flow through a resistance of one ohm.
Voltage - The amount of electromotive force, measured
in volts, that exists between two points.
Watt (W) - Instantaneous measure of power, equivalent
to one ampere under an electrical pressure of one
volt. One watt equals 1/746 horsepower, or one joule
per second. It is the product of Voltage and Current
(amperage).
Watt-Hour - A unit of electricity consumption of one
Watt over the period of one hour.
Watts per Square Meter (W/m2) – Unit used
to measure wind power density, measured in Watts per
square meter of blade swept area.
Units of Measure
Ampere - A unit of measure for an electrical current; the
amount of current that flows in a circuit at an electromotive
force of one Volt and at a resistance of one Ohm.
Abbreviated as amp.
Amp-Hour - A measure of the flow of current (in
amperes) over one hour.
Barrel (Petroleum) - Equivalent to 42 U.S. gallons
(306 pounds of oil, or 5.78 million Btu).
British Thermal Unit (Btu) - The amount of heat
required to raise the temperature of one pound of water
one degree Fahrenheit; equal to 252 calories.
Cord (of Wood) - A stack of wood 4 feet by 4 feet by
8 feet.
Gigawatt (GW) - A unit of power equal to 1 billion
Watts; 1 million kilowatts, or 1,000 megawatts.
Hertz - A measure of the number of cycles or
wavelengths of electrical energy per second; U.S.
electricity supply has a standard frequency of 60 hertz.
Horsepower (hp) - A measure of time rate of
mechanical energy output; usually applied to electric
motors as the maximum output; 1 electrical hp is equal to
0.746 kilowatts or 2,545 Btu per hour.
Kilowatt (kW) - A standard unit of electrical power
equal to one thousand watts, or to the energy consumption
at a rate of 1000 Joules per second.
Kilowatt-hour (kWh) - A common measurement of
electricity equivalent to one kilowatt of power generated
or consumed over the period of one hour; equivalent to
3,413 Btu.
Megawatt (MW) - One thousand kilowatts, or 1 million
watts; standard measure of electric power plant generating
capacity.
Megawatt-hour (MWh) - One thousand kilowatt-
hours or 1 million watt-hours.
Mill - A common monetary measure equal to one-
thousandth of a dollar or a tenth of a cent.
MMTCO2e - million metric tons carbon dioxide
equivalent
Quad - One quadrillion Btu
(1,000,000,000,000,000 Btu)
Therm - A unit of heat containing 100,000 British thermal
units (Btu).
Terawatt (TW) - A unit of electrical power equal to one
trillion watts or one million megawatts.
Tonne - A unit of mass equal to 1,000 kilograms or
2,204.6 pounds, also known as a metric ton.
242 243
ACEP Alaska Center for Energy and Power
AEA Alaska Energy Authority
AETDL Arctic Energy Technology Development Laboratory
AHFC Alaska Housing and Finance Corpora¬tion
AIDEA Alaska Industrial Development & Export Authority
ANGDA Alaska Natural Gas Development Authority
ANGTL Alaska Natural Gas to Liquids
APA Alaska Power Association
AP&T Alaska Power & Telephone Inc.
ASTM American Society of Testing Materials
AVEC Alaska Village Electric Cooperative
AWEDTG Alaska Wood Energy Development Task Group
BLM Bureau of Land Management
CCCF Cen¬ter for Climate Change and Forecasting
CCHRC Cold Climate Housing Research Center
CEA Chugach Electric Association
DCCED Department of Commerce, Community and Economic Development
DEC Department of Environmental Conservation
DHSS Department of Health and Social Services
DOE Department of Energy
DNR Department of Natural Resources
EIA Energy Information Administration
EPA Environmental Protection Agency
EPRI Electric Power Research Institute
FEDC Fairbanks Economic Development Corporation
FERC Federal Energy Regulatory Commission
GVEA Golden Valley Electric Association
HEA Homer Electric Association
IAEA International Atomic Energy Agency
IEC International Electro-Technical Commission
ISER Institute of Social and Economic Research
KEA Kodiak Electric Association
MEA Matanuska Electric Association
ML&P Anchorage Municipal Light & Power
NRC Nuclear Regulatory Commission
NREL National Renewable Energy Laboratory
OPEC Organization of Petroleum Exporting Countries
ORPC Ocean Renewable Power Company
RCA Regulatory Commission of Alaska
REAP Renewable Energy Alaska Project
REGA Railbelt Electrical Grid Authority
SES Seward Electric System
UAF University of Alaska, Fairbanks
UEK Underwater Electric Kite Corporation
USDOE US Department of Energy
UTC United Technology Corporation
Acronyms - List of Organizations
244 245
We would like to thank everyone who participated in the community meetings that formed the basis for this
project.
We extend special thanks to the individuals who contributed to the narrative for this document:
Gwen Holdmann (ACEP), Steve Haagenson (AEA), Amanda Byrd (ACEP), Ginny Fay (ISER), Nick
Symoniak (ISER), Steve Colt (ISER), Scott Goldsmith (ISER), Wyn Menefee (DNR), Jim Clough (DNR),
Ian Baring-Gould (NREL), Martina Dabo (AEA), Doug Ott (AEA), Thomas Deerfield (Dalson Energy), Tom
Miles (Dalson Energy), Dick Benoit, Thomas Johnson (ACEP), Dennis Witmer (ACEP), Henry Cole, Jack
Schmidt (ACEP), Chuen-Sen Lin (UAF), Markus Mager (ACEP), Jerry Johnson (UAF), James Jensen (AEA),
Alan Fetters (AEA), Larry Landis (AEA), Kris Noonan (AEA), David Lockard (AEA), Peter Crimp (AEA),
Mike Harper (AEA), Rebecca Garrett (AEA), Chuck Renfro, Dan Mielke, Darren Scott, Kris Noonan (AEA),
Ken Papp (AEA), Jim Strandberg (AEA).
Thanks to the following individuals for constructing the Community Energy Database:
Dennis Witmer (ACEP, coordinator), Peter Crimp (AEA), Mike Harper (AEA), Markus Mager (ACEP),
Martina Dabo (ACEP), Lenny Landis (ACEP), Doug Ott (ACEP), James Jensen (ACEP), Kris Noonan
(ACEP), Ken Papp (ACEP), Linda MacMillan (ACEP), Terence Cato (ACEP), Travis Havemeister, and
Martin Pezoldt (AK DOT)
We would also like to thank the following individuals for their input:
Mark Foster, Christa Caldwell, Bob Swenson, Meera Kohler, Marvin Yoder, Bruce Tidwell, Bernie Karl, Bear
Ketzler, Charles Hess, Chris Rose, and Sue Beck.
Acknowledgments
244 245
We also like to thank the members of the technology working groups for their valuable direction and
input to this process.
Hydro Working Group:
Earle Ausman, JC Barger, Todd Bethard, Bob Butera, Bryan Carey, Dave Carlson, Charlie Cobb, Bob Dryden,
Jim Ferguson, Alan Fetters, Steve Gilbert, Bob Grimm, Joel Groves, Gwen Holdmann, Jan Konigsburg,
Lenny Landis, David Lockard, John Magee, Nan Nalder, Doug Ott, Gary Prokosch, Chris Rose,
Jim Strandberg, Charlie Walls, Dennis Witmer, and Eric Yould
Wood Working Group:
Ron Brown, Dan Parrent, Brian Templin, Thom Sacco, Scott Newlin, Karen Peterson, Peter Crimp,
Roger Taylor, Dave Nichols, Alfred Demientieff, Ray Scandura, Willie Salmon, Heidi Veach, Dick Lafever,
Cal Kerr, Paul McIntosh, Bob Gorman, Kimberly Carlo, Bill Wall, Dave Fredrick, Ryan Colgan, Dave Misiuk,
Gary Mullen, Wil Putnam, Cassie Pinkel, Leonard Dubber, and Jeff Hermans
Ocean and River Energy Working Group:
Alan Fetters, Bob Grimm, Brian Hirsch, Dale Smith, David Lockard, David Oliver, Dennis Witmer,
Doug Johnson, Eric Munday, Gwen Holdmann, James Lima, Jan Konigsberg, JC Barger, Jim Ferguson,
Jim Norman, Lena Perkins, Lenny Landis, Monty Worthington, Phil Brna- FWS, Rebekah Luhrs,
Robert Thomas, Scott Newlun, Stan Lefton, Steve Gilbert, Steve Selvaggio, Tiel Smith, and Walter R. Dinkins
Geothermal Working Group:
Amanda Kolker, Andrea Eddy, Art Bloom, Bernie Karl, Beth Maclean, Bob Fisk, Bob Swenson, Brad Reeve,
Brent Petrie, Caty Zeitler, Chris Hladick, Chris Nye, Chris Rose, Constance Fredenburg, Curtis Framel,
David Folce, David Lockard, Dean Westlake, Dick Peck, Donna Vukich, Elizabeth Woods, Frank Gladics,
Gary Chythlook, Gene Wescott, Gerry Huttrer, Gershon Cohen, Gladys Dart, Gwen Holdmann,
Hannah Willard, Jack Wood, Jim Clough, Jim Wanamaker, Joe Bereskin-Akutan, John Handeland, John Hasz,
John Lund, Joseph T Smudin, Kermit Witherbee, Lena Perkins, Liz Battocletti, Lorie Dilley, Marilyn Leland,
Marilyn Nemzer, Markus Mager, Michelle Wilber, Nick Goodman, Norm Phillps, Peter Crimp,
Rebecca Garrett, Rebekah Luhrs, Roger Bowers, Starkey Wilson, Steve Gilbert, Steve Selvaggio,
Suzanne Lamson, and Tammy Stromberg
Fischer-Tropsch and Coal Working Group:
Jim Clough, Steve Denton, Rajive Ganguli, Mike Harper, Jim Hemsath, Dave Hoffman, James Jensen,
Paul Park, Dick Peterson, Karl Reiche, William Sackinger, Jim Strandberg, and Bob Gross.
Acknowledgements