HomeMy WebLinkAboutRegional Inventory and Reconnaissance Study for Small Hydropower Projects, Northeast Alaska 1982 Part 1REGIONAL INVENTORY AND RECONNAISSANCE STUDY
FOR SMALL HYDROPOWER PROJECTS
NORTHEAST ALASKA
DEPARTMENT OF THE ARMY
ALASKA DISTRICT, CORPS OF ENGINEERS
JUNE 1982
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REGIONAL INVENTORY AND RECONNAISSANCE STUDY
FOR SMALL HYDROPOWER PROJECTS
NORTHEAST ALASKA
DEPARTr-1ENT OF THE ARMY
ALASKA DISTRICT, CORPS OF ENGINEERS
EBASCO SERVICES INCORPORATED
JUNE 1982
A,RLIS
Alaska Resources. .
L'brary & Information ServiC6S
1 Anchorage, A!aska
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FOREWORD
This report consists of two parts. Part I is an overview of the study,
including study results in summary format. Part II contains
site-specific data for each of the communities studied. The Table of
Contents provides an itemized list of the tables, maps, and data
contained within each community section of Part II. This report also
contains appendices which provide reference data and detailed
explanations of study methodologies. '
i
. TABLE OF CONTENTS
PART I -OVERVIEW
1.0 SUMMARY ••.
2.0 INTRODUCTION
. .
. 2.1
2.2
2.3
2.4
2.5
STUDY OBJECTIVES • • • • • •
DESCRIPTION OF THE STUDY AREA
STUDY AUTHORITY • • • •
STUDY PROCESS
DATA SDURCES • • •
3.0 EXISTING CONDITIONS •• . . . ,. .
.. . .
· . .
. . . . . . .
Page
1-1
• • • 2-1
· . . 2-1
• • 2-1
· • . . • 2-1
• •• 2-3
• . • • . • 2~3
3-1
3.1 COMMUNITY CHARACTERISTICS o o· · . . . . • • o. ° 3-1
3.1.1 Historical Development
3.1.2 Existing Conditions ••
. . . . . . . • • .3-1
• 3-2
3.2 EXISTING ELECTRICAL GENERATING SYSTEMS • . . . . . . • 3-3
3.2.1 Longevity of Diesel Generators
3.2.2 Cost of Power ••••••••••••
3.2 CURRENT ELECTRICAL ENERGY REQUIREMENTS •
4.0 PROJECTED ELECTRICAL ENERGY REQUIREMENTS
3-4
• •• 3-4
3-8
• 4-1
4.1 FORECAST MODELS AND ASSUMPTIONS •••• · . . . . . • 4-1
4.1.1 Introduction ••••••••
4.1.2 Variables Used in Estimating Demand
4.1.3 Forecasting Methodology •••••• · . .
· . .
• 4-1
• • • 4-1
4-1
• • • • • 4-5 4.2 PROJECTED DEMANDS ••••••• . • • • •
5.0 SCREENING OF COMMUNITY HYDROELECTRIC POTENTIAL · . . . . . . • 5-1
5.1 SCREENING CONCEPT •••••••••••••
5.2 PRELIMINARY SCREEN ING • • • • • • • • • •
5.2.1
5.2.2
5.2.3
5.2.4
Drai nage Basi n Inventory and Engi neeri ng
Analysi s • • • • • •
Hydro 1 09i c Ana lysi s • • • .'. •
Economic Analysi s •
Screeni n9 Resul ts • • • • • • •
ii
· . . . • 5-1 5-1
· . .
• • 5-1
• .5-2
• • 5-2
5-3
TABLE OF CONTENTS (Continued)
6.0 DETAILED INVESTIGATIONS •
6.1 FIELD RECONNAISSANCE. • •••
6.2 HYDROLOGIC ANALYSIS •••••••••••
6.3 PLANT FACTORS AND INSTALLED CAPACITY.
6.4 CONCEPTUAL ENGINEERING •••• • . . ..
General ••••••••••••
Page
6-1
• 6-1
• • 6-2
• 6-14 6-19
• • 6-19 6.4.1
6.4.2
6.4.3
6.4.4
6.4.5
6.4.6
6.4.7
6.4.8
Diversion Dams •••••••••• • • • • • • 6-21
Soils and Foundations. . . . . . . . 6-24
Waterways • • • • • • • • • • • • • 6-24
Turbines and Generators ••• • •• 6-26
Site Access • • ~ • • • •• • • . . . . . • . 6-29
Transmi ssi on • • • • • • · . . Operation and Maintenance • • •••••
• 6-29
• • • • 6-31
6.5 PROJECT COSTS •• . . . . . .
Dams ••• · . . . 6.5.1
6.5.2
6.5.3
6.5.4
6.5.5
6.5.6
6.5.7
6.5.8
6.5.9
Penstocks • • • • • • •
Powerhouse and Equipment . . . .
Swi tchy.ard •• • •
Access ••• • • • • • • · . Transmission •••••••••••
Mobilization ••••••
Geographic Cost Adjustment
Operation and Maintenance.
6.6 ECONOMIC ANALYSIS •••••
6.7 ENVIRONMENTAL CONSTRAINTS •••
7.0 LIST OF REFERENCES ••• • •• . . . .
iii
· . .
. .
• • 6~31
• 6-33
• • 6-33
• 6-34
• 6-36
• • • • • 6-36
• 6-36
• 6-37
••• 6-37
• 6-38
• • 6-38
• 6-40
• 7-1
LIST OF TABLES -PART I
~ No. Title Page
1-1 SUMMARY TABLEs HYDROPOWER POTENTIAL 1-2
3-1 CLASSIFICATION OF COMMUNITIES BY EXISTING GENERATING
SYSTEMS s NORTHEAST ALASKA 3-5
3-2 EXISTING POWER SYSTEM DATA SUMMARY s NORTHEAST ALASKA
COMMUN I TIES 3-6
4-1 FORECAST PARAMETERS -LIGHTING AND APPLIANCES TYPE A
COMMUNITIES (NO CENTRAL GENERATION PLANT ) AND TYPE C
COMMUNITIES (NO ELECTRICITY TO RESID~NCES) 4~3
4-2 FORECAST PARAMETERS -LIGHTING AND APPLIANCES TYPE B
COMMUNITIES (CENTRAL GENERATION PLANT) 4-4
4-3 ELECTRIC SPACE HEATING REQUIREMENTS 4-6
4-4 SUMMARY OF PROJECTED ELECTRICAL ENERGY ANNUAL PEAK
DEMAND 4-7
5-1 SUMMARY OF COMMUN ITY HYDROPOWER POTENTIAL, NORTHEAST
REGION 5-5
6 .. 1 GAGED STREAMS USED FOR BASIN PAIRING 6-4
6-2 FLOW ADJUSTMENT FACTORS FOR GAGED STREAMS USED IN
BASIN PAIRING 6-5
6-3 BASIN PAIRINGS AND HYDROLOGIC CHARACTERISTICS OF
POTENTIAL HYDROPOWER SITES 6-6
6-4 TYPICAL PLANT FACTOR ANALYSIS FOR ISOLATED COMMUNITES
AND SMALL UTILITIES s DESIGN YEAR 1997 6-17
6-5 ALASKA SMALL HYDROPOWER PROJECTS -COST ESCALATION
FACTORS 6-32
6-6 ALASKA GEOGRAPHIC COST ADJUSTMENT FACTORS 6-39
iv
LIST OF FIGURES -PART I
No. Title Page t....,,;
2-1 STUDY COMMUNITIES LOCATION MAp· 2-2
6-1 MEAN ANNUAL PRECIPITATION AND MEAN MINIMUM JANUARY
TEMPERATURES IN TANANA AREA 6-7
6-2 MEAN ANNUAL PRECIPITATION AND MEAN MINIMUM JANUARY
TEMPERATURES IN UPPER YUKON AREA 6-8
6-3 FLOW DURATION CURVE FOR BOULDER CREEK NEAR CENTRAL,
ALASKA 6-10
6-4 FLOW DURATION CURVE FOR BERRY CREEK NEAR DOT LAKE, ALASKA 6-11
6-5 FLOW DURATION,.CURVE FOR WISEMAN CREEK AT WISEMAN, ALASKA 6-12
6-6 FLOW DURATION .cURVE FOR JIM RI VER N EAR BETTLES, ALASKA 6-13
6-7 FLOW DURATION CURVE PLANT FACTOR ANALYSIS FOR UTILHY-
SERVED COMMUNITIES 6;..15
6-8 LOAD DURATION CURVE FOR PLANT FACTOR ANALYSIS -ISOLATED
COMMUNITIES AND SMALL UTILITIES 6-18
6-9 LARGE CONCRETE DAM AND INTAKE STRUCTURE TYPICAL LAYOUT 6-23
6-10 POWERHOUSE TYPICAL LAYOUT 6-28
6-11 TRANSMISSION LINE LOAD VS. DISTANCE FOR 5 PERCENT LOSS 6-30
6-12 TURBINE GENERATOR COSTS 6-35
v
u
TABLE OF CONTENTS (Continued)
PART II -COMMUNITY AND SITE DATA
Note: For each communi ty 1 i sted below, data sheets and other materi a 1 s
are provided in the following order:
Hydropower Sites Identified in Preliminary Screening
Summary Data Sheet
Load Forecast
Significant Data (Detailed Investigation)
Conceptual Layout (Detailed Investigation)
Plant Factor Program Output (Detailed Investigation)
Hydropower Cost Data (Detailed Investigation) .
Benefit-Cost Ratio (Detailed Investigation)
Photographs
Community Descriptions and Site Selection discussions are also provided
for communities which were visited in the field.
Part II communities are provided in the following order:
ARCTIC VILLAGE
VENETIE
DOT LAKE, TANACROSS, TOK, AND MANSFIELD VILLAGE
EAGLE -EAGLE VILLAGE
BIG DELTA -DELTA JUNCTION -CHENA
KAKTOVIK/BARTER ISLAND
BEAVER
BIRCH CREEK
CENTRAL -CIRCLE HOT SPRINGS
CHALKYITSIK
CHATANIKA
CHICKEN
CIRCLE
FORT YUKON
LIVENGOOD
RAMPART
STEVENS VILLAGE
WISEMAN
APPENDICES
APPENDIX A: UTILITY RATE SCHEDULES
APPENDIX B: METHODOLOGY FOR DRAINAGE BASIN INVENTORY AND
PRELIMINARY SCREENING
APPENDIX C: ECONOMIC ANALYSIS METHODOLOGY
vi
PART I -OVERVIEW
1.0 SUt4MARY
Currently, most Alaskan communities use electricity that is generated
by burning non-renewable fossil fuels. The costs of this fonn of power
generation have been increasing rapidly and it is expected that the
costs of fossil fuels will continue to rise. An. important alternative
to burning fossil fuels for electricity is the hydroelectric potential
of Alaska's surface water resources.
In 1976, the Corps of Engi neers was authori zed by Congress to assess
possible small hydropower developments (5 megawatts or less) that could
serve communities throughout Alaska. This study of Northeast Alaska is
focused on one of six of the subregions identified by the Corps for
futher study of hydroelectric potential.
The purpose of this reconnaissance-level study is to identify, at each
of 25 Northeast Alaska communities, nearby hydroelectric resources
worthy of further evaluation. This study was accomplished through a
three-stage process: 1) preliminary inventory and screening of
drainage basins; 2) limited field reconnaissance; and 3)
reconnaissance-level engineering and economic evaluation of the more
promising sites. As a result of the investigations undertaken in the
third stage, however, no sites in Northeast Alaska appear to be worthy
of feasibility-level evaluation, on the basis of benefit-cost ratios.
These results can be attributed to several factors:
1) Field observations and detailed map studies for most sites resulted
in significant dam costs. This may be attributed to generally wide
floodplains and other site-specific conditions.
2) Mobilization costs are a significant cost element in the more
detailed investigations due to the difficulty of construction in
remote Alaskan locations.
3} The projected electric energy demands for most Northeast region
communities are relatively low.
4} Plant factors for several sites are relatively low due to reduced
winter streamflows.
Table 1-1 summarizes significant infonnation pertaining to each site
included in the third and final stage of this reconnaissance study.
The results are stated in tenns of benefit-cost ratios. In this study,
this ratio is defined as the costs of the most likely alternative
method of power generation (diesel, combustion turbine) divided by the
costs of hydroelectric generation. Thus, the more expensive the
alternative in comparison to hydropower, the higher the benefit-cost
ratio derived for the hYdropm'ler site. The preliminary screening was
intended to highlight the most promising hydroelectriC sites. The
field visits and more detailed studies of the sites that "survived" the
preliminary screening resulted in the calculation of benefit-cost
ratios. The last column in Table 1-1 indicates that none of the sites
studied in the final phase of this reconnaissance survey would produce
a benefit-cost ratio greater than 1.0 and, therefore, none of these
sites merit further feasibility-level investigation.
1-1
TABLE 1-1
NORTHEAST ALASKA
HYDROPOwER SUMMARY TABLE
RESULTS OF DETAILED RECONNAISSANCE INVESTIGATIONS
Drainage Transmission Net Design Minimum Installed Plant Energy Benefit
Site Stream Area Distance Head Flow Flow Capacity Factor Cost Cost
Colllllunity No. Name (mi 2) (mil (ft) (cfs) (cfs) (kW) (Percent) J/kwh!! Ratio
,.
Arctic Village 3 Rock Head 9.9 6.7 260.0 8.7 0.87 141 21 2.57 0.27
West Creek
Venetie 2 Kocacho 342.0 10.0 31.5 92 9.2 196 33 3.45 0.18
Creek
Dot Lake 2 Bear 58.0 9.9 151.0 74.2 7.42 699 30 0.48 0.91
Creek
..... Tanacross 1 Yerrfck 29.0 1.5 237.0 18.6 1.86 299 31 0.69 0.63 I
N Creek
Tok 7 Clearwater 27.0 12.2 353 17.2 1.72 412 31 0.88 0.50
Creek
Eagle-Eagle 1 American 49.2 5.5 269 3.2 0.64 59 40 2.41 0.22
Village Creek
Big Delta-2 Granite 23.5 20.2 240 3.76 3.76 612 44 0.49 0.66
Delta Junction Creek
1/ 1981 J.
Y Conditions: 5 percent fuel costs escalation; capital costs of alternative power generation excluded.
c· c
2.0 INTRODUCTION
2.1 STUDY OBJECTIVES
Electric. power provided to Northeast Alaska villages is presently
generated, for the most part, by diesel generators. The costs of fuel,
lncluding transportation and handling costs, have been increasing
rapidly and present a financial burden to electricity consumers.
Diesel generators break down frequently and are expensive to operate
and maintain. Among the wide range of power generation alternatives,
the potential hYdroelectric resources of Northeast Alaska merit
consideration due to the availability of potentially suitable surface
water resources in the regi on. Deve 1 opment of small 1 oca 1 hydropower
facilities would relieve village consumers of paying for the rising
cost of fuel and ensure a source of power not subject to inflation.
The purpose of this study is to evaluate potential small hYdropower
developments to serve local needs at each of 25 Northeast Alaska
communities. As a reconnaissance study, the objective was to identify
and evaluate potential projects for which further, more detailed study
might be warranted. The report provides, for each community, a summary
of the existing power system, future power needs, an identification of
potential sites, and an economic review that indicates benefits of
hYdropower relative to existing methods of power generation. For those
sites with economic hYdropower potential, infonmation is provided on
the hYdrologic characteristics, suitable equipment, prelimina~ size of
project components, conceptual cost estimates, and identification of
potential environmental constraints.
2.2 DESCRIPTION OF THE STUDY AREA
The twenty-five communities that comprise the Northeast study region
(Figure 2-1) are located within a vast area of 130,000 square miles.
The topographY ranges from almost no relief characterized by the Yukon
Flats to the extensive relief of the Alaska Range. Despite'the size of
the study region, the communities support similar lifestyles and share
many common social and economic problems and needs. All communities
face harsh winters with temperatures that reach as low as _70 0 F. With
the exception of a few communities, the study area includes villages
with populations of less than 200 persons. The villages are inhabited
primarily by natives but a few support a non-native population.
Several villages are accessible only by air which makes transportation
outside the village difficult and expensive. The economies are a
mixture of subsistence/cash with few employment opportunities.
2.3 STUDY AUTHORITY
The Alaskan Small Hydropower Study authorized the Corps of Engineers to
assess the potential for installing small hYdropower prepackaged units
5 megawatts or less to serve isolated communities throughout Alaska.
This study of the hYdroelectric potential of Northeast Alaska is
2-1
PACIFIC OCEAN
KEY MAP
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SCALE IN MILES
REGIONAL INVENTORY & RECONNAISSANCE snJOY
SMAll HYDROPOWER PROJECTS
NORTHEAST ALASKA
STUDY COMMUNITIES LOCATION MAP
FIGURE 2-1
DEPARTMENT OF THE. ARMY
ALASKA DISTRICT
CORPS OF ENGINEERS
focused on one of six identified subregions. To date studies of the
Southeast, Southwest, Northwest, and Kodiak Island/Alaska
Peninsula/Aleutian Islands have been completed. This study was
conducted simultaneously with the hYdropower study of Southcentral
Al aska.
2.4 STUDY PROCESS
The study was accomplished in three stages during the period April to
December 1981. The first stage involved a literature and information
review, a projection of community electrical energy requirements, and
review of USGS 1:250,000-scale topographic maps to inventory drainage
basins and identify potential hydroelectric sites. Stream flows were
estimated by applying the concept of "basin pairing," in which drainage
basin characteristics for ungauged streams are matched to the most
appropriate gauged stream basin within the region. For those streams
that were estimated to have sufficient hydroelectric development
potential to meet a substantial part of community needs, preliminar-y
cost estimates were prepared. The cost of hYdropower was then compared
to the cost of alternative power. Six sets of benefit/cost ratios were
calculated based on scenarios of 0, 2, and 5 percent fuel escalation,
both with and without the cost of capital investment in generating
equipment for alternative power sources.
The second stage involved a field reconnaissance of sites that
indicated development potential. Eight communities were selected by
the Alaska District for field reconnaissance. During the site visits,
community leaders were contacted in order to obtain information
regarding local interest in hYdropower, power needs, future plans for
the community, and potential environmental constraints to development.
Cross-sectional profiles of streams and streamflow observations were
made.
The most promising sites identified in the pre'liminar-y screening were
included in the third stage of analysis. A list of sites to be studied
in greater detail was developed on the basis of field observations and
review of USGS 1:63,360-scale maps. During the third stage, data
obtained in the field were evaluated, and load projections were revised
based on community survey results. More detailed development concepts
and cost estimates were prepared for the most promising sites.
Benefit/cost ratios were recomputed by comparing hYdropower costs to
the value of electricity produced by the least costly alternative,
which in all cases was assumed to be existing generating plants.
2.5 DATA SOURCES
A list of reports that were used as background to this reconnaissance
study can be found in the reference section. Several reports were
available on the energy requirements of remote villages and were used
to support the load projections. Current population figures were
obtained from the U.S. Bureau of the Census.
In addition to recent Alaska literature, persons in various state
agencies and utilities were contacted regarding electrical energy
demand. Fuel, equipment, and transportation companies were contacted
to obtain the most current prices and costs.
2-3
u
3.0 EXISTING CONDITIONS
This section includes a description of community characteristics which
provides a context for understanding both the present and future
electric energy requirements of the study area communities. This
description of social and economic conditions provides a rationale for
the specific assumptions used in forecasting electric energy demand.
3.1 COMMUNITY CHARACTERISTICS
The communities of Northeast Alaska that comprise the study area can be
classified as either small regional centers or rural villages. Small
regional centers are communities ranging in size from approximately
200-1000 persons, provide sources of employment, but do not present the
economic opportunities of the larger cities. Communities that fall
withi n thi s category are Fort Yukon, Delta Junction, and Tok. These
small economic centers provide for the delive~ of goods and social
services to the surrounding area. Small businesses and government
agencies locate in these centers and provide local jobs. These
communities are characterized by the presence of commercial air
service, air charter services, and accomodations for tourists.
The majority of communities in the study area can be classified as
rural villages with populations of less than 200 persons. More than
one-half of the communities are Alaska native villages. A small
percentage of non-native population may reside in the native villages.
The unemployment rate is chronically high and jobs usually must be
sought outsi de of the vill age on a tempora~ basi s. Jobs a re often
found primarily in construction, firefighting, and with the native
cOl1>orati ons.
3.1.1 Historical Development·
The economy of the typical rural village is small, unstable, and
rapidly changing. Since 1940 population has declined in many of these
villages. In other villages, population levels have fluctuated
greatly, raising the question of future growth or decline (Alonso and
Rust 1976). Some remote villages have been abandoned in the past and
new communities have evolved in response to the changing economic
structure. In general, a net movement towards the larger cities has
been occurring, particularly among the native popul ation.Thi s trend
has been reversed in some areas due, in part, to the provisions of the
Alaska Native Claims Settlement Act and more recently to the Alaska
lands Si 11.
The subsistence economy in rural Alaska, which historically meant
trapping, fishing, gathering, and bartering, has been changed by the
introduction of capital (e.g., snowmachines used for trapping). This
necessitates stable sources of income of which there are few.
3-1
3.1.2 Existing Conditions
The socioeconomic characteristics and physical setting of a community
tell a great deal about existing and future electrical energy
requirements and the feasibility of continuing to produce power from
diesel generators. For the very remote communities, the expense of
transporting fuel and repairing the generators is a substantial
economic burden. The following discussion provides an overview of
village demographics, economic climate, and infrastructure.
Demographics
long term population growth in Alaska has ranged from less than
1 percent to 3 percent per year (Retherford 1981). Popul ation growth
in small rural villages has been lower on the average than in the
larger communities. Each community is unique with respect to
population trends, however; some villages have for years experienced
little or no change in population while other communities are growing
rapidly.
In native villages the availability of housing and jobs, and proximity
to family relatives are three major factors that influence a person to
relocate to a village. Privately financed housing construction is
uncommon and most new homes are obtained through the HUD housing
program. Communities that suddenly receive a large number of new homes
may experience a spurt in population growth. The availability of jobs,
such as for an airport construction project, may be an additional
inducement for an outsider to relocate.
The reasons why people move to non-native villages are not so
apparent. Some persons relocate to a remote community to escape the
city without conSidering fully job or housing opportunities.
Average household size in Alaska was 3.26 in 1976 (Goldsmith and Huskey
1980) but historically has been larger in non-urbanized communities.
The 44 villages served by the Alaska Village Electric Cooperative
(AVEC) have a reported household size of 5.5 persons (Galliet 1980).
Following the national trend toward fewer persons per household,
household size in Alaska will probably decrease over time. The
household size used in the load forecasting model was 4.5 persons for
isolated communities and 3.5 persons for intertied communities.
Employment and Income
In a mixed subsistence/cash economy, income is derived from either
wages or transfer payments. Subsistence activities reduce the need for
ca.sh and typically consist of mining (e.g. gold panning), trapping,
fishing, and gathering wood for fuel. Most jobs in rural villages are
seasonal, cyclical, and tempora~. Traditionally, seasonal employment
has been provided by jobs in construction and firefighting. Temporary
employment may be found outside the village with resource exploration
companies. A few local jobs have been created by the CETA program,
3-2
v
u
which is a government subsidized employment program. The funding has
recently received drastic cuts, however, and the program may eventually
be phased out.
Transfer payments are another form of income and include food stamps,
welfare, social security, and unemployment benefits as well as other
government subsidized programs. These payments often do not respond to
inflation and may be subject to cutbacks in the near future.
Infrastructure
Infrastructure in a small rural village typically includes housing,
community center, elementary school, laundry, and possibly a water and
sewer system. The introduction of infrastructure into a community can
change radically the electricity requirements. For example, Tanacross
pays very expensive electricity bills on their water treatment
plant. Since this is a community expense, the monies for payment
come from the village council contingency funds. Similarly, Dot lake
has a central hot water heating system that uses a large amount of
electricity for its circulating pump. During 1980, the utility
building which houses the heating system and the community hall used
16,000 kWh and cost approximately $3,000. '.
While many of the rural villages have limited infrastructure, water and
sewer systems, schools, airports, and HUD housing may be introduced
over the next ten years and would, consequently, increase the demand
for electricity. Under federal law, every village has a right to an
adequate" water and sewer system, and housing for low income people.
Every village with eight or more secondary students has a right to have
a high school under state law. Airport development projects are
occurring throughout the study area, and may increase in the future.
3.2 EXISTING ELECTRICAL GENERATING SYSTEMS
Communities in the study area range from having no electricity to
purchasing electricity from a utility. With the exception of those
communities served by Golden Valley Electric Association (GVEA), all
communities with electricity rely on diesel .generator systems ranging
in size from 200 kW to 2275 kW. In some communities, generators of 2-5
kW in size provide individual residential electricity but their use is
restricted by the high operating and maintenance costs. Many
communities have small diesel generators owned, operated, and
maintained by the BIA that are limited to school and council use. Ten
communities fall within the categeory of having no residential
electricity. A classification of the communities by existing
1/ $450/month during summer months; $650/month during winter months.
3-3
generati ng systems is presented in Table 3-1. A summary of the
existing power systems for each community include population system
size, utility, cost of diesel fuel, and cost of residential power is
presented in Table 3-2.
Several utilities were contacted to determine the expected useful life
of their existing diesel generators. Because each utility system
consists of a mix of generators of varying sizes and ages, and because
the utilties generally plan to extend the useful life of their
equipment through periodic overhauls, no specific data on expected
useful life of the generators can be provided in Table 3-2. However,
for the purposes of the present study, certain assuinptions were
developed. These are discussed in the following section.
3.2.1 Longevity of Diesel Generators
The life expectancy of a diesel generator is influenced by a number of
factors including size', number of total operating hours, daily and
seasonal operating patterns, and frequency and quality of maintenance.
Generators in size of up to 500 KW usually have a limit of 20,000 hours
of continuous operation before a major overhaul is requ'ired. The
1 arger di esel generators (500-850 KW) have a longer operating peri od of
3),000 -40,000 hours before an overhaul is required. A generator can
be overhauled three to four times. Given these values, a small diesel
generator has a life expectancy of approximately 9 years, if operated
continuously. Under these same maximum operating conditions, the
larger generators that would be used in a utility power system have an
expected 1 He of about 18 yea rs. Operati ng the generators only duri ng
the day and keepi ng one small generator on-l i ne for summer use
increases the expected 1 He of the system. For the prel imi na ry
screening, an investment cycle of 20 years was used to calculate the
cost of diesel power. While the life expectancy of a diesel generator
in isolated communities can be considerably less, a 20 year life
expectancy represents a conservative estimate of diesel power costs.
In Northeast Alaska, diesel generators are not always maintained on a
regular basis and conditions for maximizing the life of the machine are
not optimal. The requirements of a diesel system are complicated
further by the absence of local people to maintain the generators. In
several cases, where sending for a person from Fairbanks to repair a
generator is required, the time and expense involved may be a
disincentive to properly maintaining a generator.
3.2.2 Cost of Power
The cost of power varies greatly among the 25 communities in the study
a·rea. The disparity in electricity prices can be attributed to the size
of the generating system, price of fuel, and size of fuel storage
facilities. In general, communities that buy electricity from
utilities have lower power rates than isolated communities. The small
utilities that serve only one community charge higher rates than large
utilities that serve multiple com-munitites since they are not able to
achieve the economies of scale found in large power generating systems.
3-4
u
TABLE 3-1
CLASSIFICATION OF COMMUNITIES BY EXISTING GENERATING SYSTEMS
NORTHEAST ALASKA
Type A
Individual or Small
Village Generators
J
Arctic Vi 11 age
Central
Ci rcle
Eagle
Li vengood
Venetie
Type B
Central
Generation Plant
B1g Delta
Chatanika
Chena
Delta Junction
Dot Lake (early 1982)
Fort Yukon
Kaktovik/Barter Island
Tanacross
Tok
3-5
No Genera ion System
System or Limited
to School Use
Beaver
Bi rch Creek
Chal k,yits; k
Chicken
Ci rc 1 e Hot Spri ngs
Eagle Village
Mansfield Village
Rampa rt
Stevens Village
. Wi seman
TABLE 3-2
EXISTING POWER SYSTEM DATA SUMMARY
NDRTHEAST ALASKA COMMUNITIES
1/ 1/ 1981 Energy COst of
Page 1 of 2
1/ Cost of
Conmunity Longitude 1981 Method of-Utflfty-Insta11 ed-Use 2/ Dfesel Fuel Resfdentfal 4/
Name and latitude Po(!ulation Generation Name Ownershf(! Ca(!acftl (kll) (kllh/,lear)-(1/9all on) Power (I/kllh)-
Arctic Yi 11 age 145 0 32 '11 68' 08 'N 132 Dfesel None BIA 160 (BlA) 5SO,082 3.500 1.00
200 (Yi11 age)
Beaver 147· 23'11 66' 22 'N 66 Diesel None BIA 95 275,041 1.627
Big Delta 145 0 49'11 64' 09 'N II Coal, Golden Yalley REA 225,000 133,091 0.920 .12
Diesel, Electric on Associ atf on
Birch Creek 145 0 49 '11 66' 16'N 32 Dfesel None BIA 20 14,855 1.785
Central 144' 46 '1/ 65' 34 'N 20 Dfesel None Prhate Indhfdual generators 83,346 1.376
Chal kyftsi k 143' 44'1/ 66' 39 'N 95 Diesel None BIA 79 44,101 1.785
w 147 0 28 '1/ 65· 07 'N I Chatanfka 30 Coal, Golden Yalley REA 225,000 133,091 0;920 .12
'" Dfesel, Electrfc on Association
Chena 147 0 56'1/ 64' 48 'N 35 Coal, Golden Ya11ey REA 225,000 155,273 0.920 .12
Dfesel, Electric on Assocf ati on
Chicken 141' 56'11 64 0 04 'N 30 None 13,927 1.48LY
Circle 144· 04'1/ 65 0 SO'N 80 Ofesel Cf rcle Private III 333,383 1.376 .32
Utflftfes
Circle Hot 144 0 37 '1/ 65 0 29'N 25 Dfesel None Prhate 15 (Hotel use only) 11,605 1.376
Springs
Delta Junction 145 0 44'1/ 64' 02 'N 945 Coal, Golden Ya11ey REA 225,000 4,192,364 0.920 .12
Dfesel, Electric on Association
Dot Lake 1440 04'11 63 0 4Q'N 66 Diesel Al aska Power Prhate 20D (temporary until 292,80D 1.241 .25
and Telephone transmission lines are
in operation)
2,275 (early 1982)
1/ Alaska Department of Commerce and Economfc Development. 2./ Approximate cost of dfesel fuel ff generators were used. 1/ Derived from the load forecasts. !t Based on consumptfon of 438 kl/h/month.
c (
c c
TABLE 3-2
EXISTING POWER SYSTEM DATA SUMMARY
NORTHEAST AlASKA COMMUNITIES
1/ 11 17 1981 Energy
Page 2 of 2
Cost of Cost of
Conmunity Longftude 1981 Method of-Utflity -lnstalled-Use 2/ Diesel Fuel Residential 41
Name and latitude POl!ulatfon Generation Name Ownershie Caeaci!il (kW) (kWh/learl-(S/aallon) Power fS/kWh)-
Eagle 141" 12'W 64" 47'N 164 Diesel None Private 225 683.436 1.349 .38
50 (planned addition)
Eagle Village 141" 05'W 64" 47'N 54 D1esel None BIA 180 25.068 1.349
Fort Yukon 145 0 15'W 66' 34'N 619 Diesel Fort Yukon Private 1035 2.746.109 1.667 .30
Util1tfes
Kaktovikl 143" 37'W 70' 08'N 165 D1esel North Slope Municipal 230 732.000 1. 740 .35
Barter Island Borough
livengood 148' 33'W 65 0 31'N SO Diesel None Private Individual generators 208.365 1.376
Mansfield 143" 25'W 63' 27'N 0 None 1.34~1
Village
Rampart lSO° 10'W 65' 3O'N 53 Diesel None BIA 32.5 24,604 1.540
Stevens Vi 11 age 149" 06'W 66· OO'N 88 Diesel None BIA 10 40.851 1.592
w Tanacross 143" 21'W 62" 23'N ll7 Diesel Alaska Power Private 1.975 519,055 1.241 .25
I and Telephone ......
Tok 142' 59'W 63" 19'N 750 Diesel Alaska Power Private 2.275 3,260,728 1.241 .25
and Telephone
Venetfe 146" 25'W 67° Ol'N 160 Diesel None BIA 250 666,766 2.25 1.00
Wiseman 1SO° 07'W 67" 25'N 12 None 5.571 1.406Y
In communities served by utilities, the price of electricity is not always
simply the charge per kilowatt-hour. Utilities have up to three components
in the price of electricity. The residential electricity rate schedule I I
typically consi sts of a service charge (fl at rate per month), an energy ......,
charge for the amount of el ectricity consumed (fixed rate per
kilowatt-hour), and a fuel surcharge (fixed rate per kilowatt-hour) which is
usually a fraction of the energy charge. .
In isolated communities where diesel generators are owned and operated by
private individuals, the price of electricity usually has just an energy
charge, which covers the capital, operating, and maintenance costs and very
little profit, if any. In native villages, the BIA owns, operates, and
maintains the diesel generators that provide electricity to the schools and
village council buildings. In some native villages, the BIA provides elec-
tricity to residences as well. In this case, the residential electricity
price does not reflect the real cost of generating power since the govern-
ment is subsidizing the power system.
3.3 CURRENT ELECTRICAL ENERGY REQUIREMENTS
In the study area communities, electricity is used for lighting, small
household appliances, and large appliances such as refrigerators, freezers,
televisions, and car heaters. The number and type of large appliances are
key variables affecting energy demand. Some households have washers, dryers
and, in a few cases, electric hot water heaters, which are large electricity
consumers. In addition to residences, buildings in rural villages that use
electricity include the washeteria, school, and community building. In the
larger communities, buildings that are electricity consumers include stores,
motels, and restaurants.
3-8
u
4.0 PROJECTED ELECTRICAL ENERGY REQUIREMENTS
4.1 FORECAST MODELS AND ASSUMPTIONS
4.1.1 Introduction
Electric energy forecasting is a planning tool useful in evaluating the
needs of a community in relation to the generating capability of a
proposed nYdroelectric project. In a centralized system without
interties, electric energy demand is an important economic factor in
assessing the appropriate size of project.
The approach taken in this study toward foreca'sting demand is to use
different scenarios of electric energy growth based on the current
electric generating system and projected end use consumption. Villages
that presently are supplied electricity from a central generation plant
consume on the average more electricity per capita than do villages
that have individual diesel generators. The villages not served by a
utility are generally characterized by smaller populations and fewer
job opportunities. The models represent two load growth scenarios, in
which consumption patterns of villages with decentralized or no
electric generation lag behind those villages served by utilities.
4.1.2 Variables Used in Estimating Demand
Va ri ables that i nfl uence current and future el ectric energy demand are
population, income, and infrastructure. These variables affect end
uses of electricity, such as the number and type of household
appliances, as well as consumption patterns over time.
The historical fluctuations in population and economic activity of many
of the remote villages in Northeast Alaska make forecasting demand
highly speculative. ElectriCity requirements can change radically
through the introduction of new school or housing construction, which
result from state and federal programs. In villages with unreliable or
no diesel generators, electrification may affect locational preferences
of residents (Alonso and Rust 1976). It is difficult to predict to
what extent electrification will cause population growth, however,
since source of income rather than the availability of electricity is
probably the most critical variable affecting location decisions. A
change in employment opportunities will affect the size of disposable
income and, therefore, consumption patterns, as well as locational
preferences of resi dents.
4.1.3 Forecasting Methodology
Low and high electric energy projections have been calculated to
reflect different levels of use of electricity. The low projection is
based on the assumpti on that electri city woul d be used only for
lighting and household appliances. The high projection represents the
application of electricity to space heating in 3/4 of all residences as
well as to lighting and appliances and domestic hot water. The low and
4-1
high projections delineate the bounds of electric energy consumption
throughout the 1980-2030 period. In addition, a composite projection
that averages the high and low projections has been calculated. The
low growth projection is considered to be most representative of
electric energy consumption patterns in the future. The present
pattern of energy consumption is low, and is not expected to undergo
substantial change in the future.
The medium and high growth prOjections indicate possible futures in the
event growth is induced by development. The availability of revenues
from a project, local jobs with relatively high incomes, and the
introduction of lifestyles at variance with the existing culture may
lead to higher energy consumption.
All three load forecasts are included for each community in Part II of
thi s repo rt.
Application of Electricity to Lighting' and Appliances
Most rural Alaskan villages have low per capita electric energy usage
stemming from low incomes. Typically, the largest individual consumer
is the school. Consumption in the residential sector accounts for
approximately 10 percent of the total in rural villages and
approximately 35 percent of the total in sub-regional centers. With
the introduction of lower priced electricity a potential exists for
increased residential consumption. Current end uses of electric energy
include lighting, small appliances, and large appliances such as
refrigerators, washers, and televisions. If the price of electricity
decreases substantially, more appliances such as dryers, freezers, and
electric water heaters would be acquired. Acquisition of space heaters
is unlikely as explained in the following section. Assumptions used to
forecast demand for lighting and appliances are presented in Tables 4-1
and 4-2. The assumptions were derived from a review of recent energy
studies conducted for Alaskan communities and personal communication
with Alaskan utilities. Documents of particular use were Alaska Power
Administration 1979; Goldsmith 1980; Retherford 1981; Holden and
Associates 1981; ISER 1976; CH2M Hill 1980; and Galliet 1980.
The growth of electric energy consumption in the residential sector
will vary accord; ng to the current generati ng system. Residences
served currently by a utility consume approximately 5,250 kWh/year.
This value represents an average rate for consumers served by Alaska
Village Electric Cooperative (AVEC) and Copper Valley Electric
Cooperative (CVEA) for the year 1980. In comparison, residences served
by individual small diesel generators consume approximately one-third
of that amount, or I,BOO kWh/year.
Rates of growth in the residential sector as welJ as the institutional
and commercial sectors are presented in Tables 4-1.and 4-2. Using this
methodology residential consumption in rural villages in the year 2000
approaches present consumption of residences served by utilities.
4-2
u
TABLE 4-1
FORECAST PARAMETERS -LIGHTING AND APPLIANCES
TYPE A COMMUNITIES (NO CENTRAL GENERATION PLANT)
AND TYPE C COMMUNITIES (NO ELECTRICITY TO RESIDENCES)
Population Parameters (Common to Types A and C)
Annual Increase in Population
Persons per Household
1.5 percent
4.5
Growth in Electricity Consumption (Common to Types A and C)
Annual Increase in Energy in Residential Sector
Growth Sce na ri 0 :
1900 -1990
1990 -2000
2000 -2020
2020 -2030
Growth in El ectr1 c1 ty Consumption per Househol d:
Year Type A
l kWh7,lear)
1980 1800
1990 3541
2000 5768
2010 6371
2020 7038
2030 7038
7 percent
5 percent
1 percent
o percent
~ k ,lear)
0
1000
3541
5768
6371
7038
Annual Increase in Energy Use in Institutional Sector (School s)
Growth Scenario:
1900 -1990
1990 -2000
2000 -2030
Electric Energ,l Consumption-b,l Sector
Present
Sector Type A
type C
Percentage
1980
19'9i'f
Expected Change
1990-2030
2000-2030
2 percent
1 percent
0.5 percent
Residential
Institutional
Commercial
10 percent
79 percent
6 percent
5 percent
Increase 84 percent
Public Facilities
4-3
Decrease
6 percent
10 percent
TABLE 4-2
FORECAST PARAMETERS -LIGHTING AND APPLIANCES
TYPE B COMMUNITIES (CENTRAL GENERATION PLANT)
Popul ati on Parameters
Annual Increase in Population
Persons per Household
Growth in Electricity Consumption
Annual Increase in Energy in Residential Sector
Growth Scenario:
1900 -1990
1990 -2000
2000 -2020
2020 -2030
Growth in Electricity Consumption per Household:
Year
1980
1990
2000
2010
2020
2030
Annual Consum)tion
(kWh/year
5,250
7,056
8,601
9~982
11~584
11,584
1.5 percent
3.5
3 percent
2 percent
1. 5 percent o percent
Annual Increase in Energy Use in Institutional Sector (School s)
Growth Scenari 0:
1900 -1990
1990 -2000
2000 -2030
Electric Energy Consumption by Sector
Sector
Residential
Institutional/
Public Facilities
Commercial
1980
35 percent
55 percent
10 percent
4-4
1990-2030
Increase
Decrease
10 percent
2 percent
1 percent
.5 percent
90 percent
u
Communities that currently have no electricity will require several
years to match the consumption patterns of communities that have
el ectricity.
Application of Electricity to Space Heating
The use of electricity for residential space heating 1n Alaska is
unlikely due to the significant heating requirements and the higher
cost of electricity than alternate sources such as fuel oil, wood,
coal, and peat. Wood, peat, and coal are available in varying
quantities throughout Northeast Alaska and their use will depend on
long term supply. Currently, peati s not collected and burned for
space heating. The substitutability of electricity for other sources
of heat has therefore been assessed separate from other applications of
electricity. The use of electric space heating in the study area is
very unlikely but will depend on the price of electricity, income of
household, and the price of substitutes. The electric ener9Y
requirements for space heating in Alaska are substantial, particularly
in the Greater Fairbanks area and north of the Arctic Circle. In
comparison to Seattle, electric energy requirements for space heating
are 3 to 4 times greater in Al aska. Annual electric ener9Y
requirements for single family residences are presented in Table 4-3.
These values may exceed space heating requirements of residences in the
study area since houses in the remote communities have on the average
less area to heat than houses in Fairbanks, from which these values
were derived. The end use of electricity for space heating in the high
scenari 0 has been assumed to remai n constant throughout the study
period.
4.2 PROJECTED DEMANDS
The low energy demand was used as a basis for sizing the ~dropower
projects and compari ng the costs of hydropower to diesel generation,
for the reasons given in Section 4.1.3. The projected energy demands
for each community were calcul ated on the basi s of the assumpti ons
presented above and 1900 census data, and are presented in Table 4-4.
For the purpose of sizing projects to serve intertied communities, the
aggregate demand of study area communities was used as a basis. In
such situations, since the transmission lines are already in place, one
project could serve the entire system. For isolated cor.tnunities with
village or individual generators, projects were sized according to the
community demand.
4-5
TABLE 4-3
ELECTRIC SPACE HEATING REQUIREMENTSl/
Location
Greater Fairbanks
Arctic Circle
kWh/single family residence/year
45,900
59,OOoY
11 Goldsmith and Huskey 1980.
2/ Determined by ratio method, where
kWh SH (Arctic)
kWh SH (Fairbanks)
and kWh SH (Arctic)
49, 900
=
Heati ng degree days (Arctic)
Heating degree days (Fairbanks)
18,433 58,984 kWh SH (Arctic)
= = 14,344
4-6
TABLE 4-4
SUMMARY OF PROJECTED ELECTRICAL ENERGY ANNUAL PEAK DEMANol/
(kW)
Communitl 1990 1997 2000 2010 2020 2030
Arctic Village 256-256 302-512 322-621 356-1055 406-1212 443-1379
Beaver 128-128 151-233 161-277 180-450 203-517 222-586
Big Delta 60-60 70-117 74-142 89-247 109-292 122-334
Bi rch Creek 51-51 66-105 72-129 91-222 101-253 114-291
Central 39-39 46-70 49-84 55-136 61-157 67-177
Chalkyitsik 151-151 195-346 214-430 269-769 301-881 339-1012
Chatanika 60-60 70-117 74-142 89-247 109-292 122-334
Chena 69-69 81-137 86-166 104-288 127-341 142-390
Chicken 48-48 62-99 68-121 85-208 95-237 107-272
Ci rcle 155-155 183-282 195-336 218-546 246-626 269-710
Circle Hot Springs 40-40 51-82 56-100 71-173 79-198 89-227
Delta Junction 1875-1875 2194-3695 2331-4475 2803-7778 3420-9194 3831-10532
Dot LakeY 131-131 153-258 163-313 196-543 239-642 268-736
Eagle 319-319 376-578 400-689 447-1119 504-1283 551-1455
Eagl e Vi 11 age 86-86 111-178 122-217 153-374 171-427 193-490
Fort Yukon 1228-1228 1437-2701 1527-3332 1836-6025 2240-7102 2509-8152
Kaktovik/
Barter Isl and 327-327 383-720 407-888 489-1606 597-1893 669-2173
Livengood 97-97 114-176 122-210 136-341 154-391 168-444
)
Rampart 84-84 109-174 119-213 150-367 168-420 189-481
Stevens Vi 11 age 140-140 181-290 198-354 249-609 278-697 314-799
Tanacross .. Y 232-232 272-457 289-554 347-963 423-1138 474-1304
Tok 1458-1458 1707-2874 1813-3481 2180-6050 2660-7151 2980-8192
Venetie 311-311 366-620 390-753 436-1278 492-1469 537-1671
Wiseman 19-19 25-44 27-54 34-97 38-111 43-128
Y The range of peak demands given for each community correspond to low and high growth scenarios.
,!I Estimate does not include electricity for centralized hot water heating system.
'l! Estimate does not include electricity required by water treatment plant.
u
4-7
u
5.0 SCREENING OF COMMUNITY HYDROELECTRIC POTENTIAL
5.1 SCREENING CONCEPT
The objectives of applying a preliminary screening process were l)to
select from a large number of identified hYdroelectric sites those that
demonstrated potential, and 2)to identify communities with potential
sites that warranted a field visit. The procedure used to screen sites
was based on a set of engineering, hydrologic, and economic criteria.
The preliminary screening procedure resulted in narrowing the number of
Northeast communities with potential hydroelectric sites from 25 to
13. Each of these thirteen communities,could be served by at least one
hYdro site with a preliminary benefit/cost ratio greater than one,
which indicated the economic merit of hYdroelectric power compared to
the eXisting method of power generation over a SO-year period. Eight
of these thirteen communities were visited by the study team.
5.2 PRELIMINARY SCREENING
5.2.1 Drainage Basin Invento~ and Engineering Analysis
The initial selection of potential hYdroelectric sites involved an
inventory of drainage basins using U.S. Geological Survey topographic
maps at a scale of 1:250,000. A 15-mile radius around each community
generally defined the outer limits for identifying a site. This
distance was generally used to limit the study area for each community
principally because of the economics of transmission lines and access
requirements for small hYdro developments. However, potentially
attractive sites as far as 25 miles from a community were included in
the screening where no suitable sites were found within the 15-mile
radius. For each community, approximately six sites located within the
radius were selected for further investigation. The most promising
sites were selected in a logical manner, beginning with the principal
river or stream and then examining the smaller tributaries~ Each site
was sized to meet the following criteria:
o 80 percent of the low demand scenario in year 2030,
approximately equal to average day peak demand;
o Sites which could serve intertied communities were sized based
on the aggregate demand of the communities;
For each site selected, the following features were identified on the
maps:
o Site identification number
o Drainage basin boundaries and area above damsite
o Dam and powerhouse location
5-1
o Penstock route
o Transmission line route
A detailed discussion of the methodology used to identify sites for the
preliminary screening is presented in Appendix B.
5.2.2 ijydrologic Analysis
Because most of the streams identified as potential hydropower sites
are ungaged, a method of estimating flows in these streams was
necessary. For initial power potential and site screening purposes,
estimates of streamflow were made by assuming that flow is proportional
to drainage basin area and by using values of average runoff per unit
area (given in cfs/mi2) derived by Balding (1976). Drainage basin
areas were estimated from 1:250,000 USGS topographic maps using
planimetric techniques, and these values were multiplied by the runoff
per unit area values obtained from Balding (1976), which are given in
the fonn of i soli ne maps, to obtai n mean annual streamflow. Only the
single value of mean annual streamflow was used in the initial
screening phase.
5.2.3 Economic Analysis
The economic analysis methodology used in this study is presented,
along with a site-specific example, in Appendix C. The following
paragraphs provide a more general summary of the economic analysis used
in the prel imi nary screen; og phase.
Benefit/cost ratios were calculated for each potential site identified
in the drainage basin inventory and preliminary screening. The
objective of the analysis was to compare the economic viability of
hYdroelectric sites based on conceptual costs to the cost of
alternative power. Plant sizes were based on low electric energy
growth projections. Fuel costs of alternative power were escalated at
rates of 0, 2, and 5 percent. A discount rate of 7-5/8 percent was
applied to the costs of both hydroelectric and alternative power.
Cost of ijydroelectric Power
For each of the sites identified in the map reconnaissance, costs were
estimated for the major components and then summed to provide a total
estimated capital cost. The project components for which separate cost
estimates were developed include generation equipment (including the
powerhouse structure), penstocks, dams and mobilization, and
transmission facilities. Annual costs for each site were developed
using an interest rate of 7-5/8 percent for project financing over a
50-year period, including an allowance for operation and maintenance
costs. The average annual cost of energy for each site was then based
on the annual cost of the project and the estimated annual energy
output.
5-2
u
Diesel Alternative
A stream of diesel costs in ~/kWh were calculated for all isolated and
potentially intertied communities based on annualized capital,
operating and maintenance costs and, in the case of potential
interties, annualized transmission costs.
Two investment streams were calculated employing an average cost
methodology and based on an interest rate of 7-5/8 percent. The
capital costs were multiplied by a capital recovery factor of .0991 for
the 20-year investment cycle. Replacement of the diesel generator
after each 20 year increment was assumed. The assumption of a 20-year
investment cycle and a 5 percent fuel escalation rate were used to
calculate diesel costs for the first screening. For the potential
i nterti ed communities, transmi s5i on costs were annual ized based on a
capi tal recovery factor of .07823 for a 50-year investment cycle.
Other assumptions were used in calculating diesel generation costs.
Diesel generators were sized for peak hour of the final year of their
useful life (20th year), assuming the demand at that time would be 1.5
times greater than average demand. The factor of 1.5 was derived from
load curves supplied by Alaska Village Electric Cooperative (AVEC). A
diesel heat rate of 12.4 kWh/ gallon was used to calculate fuel
requirements.l/ Operating time was assumed to be 4380 hours per
year, or half time on the average. Capital costs varied with s1ze
, (~225/kW-~525/kW) and maintenance costs were assumed to be 6 percent of
installed capital costs.
Combustion Turbine Alternative
The alternative to hydropower was assumed to be combustion turbines for
those communities served by Golden Valley Electric Association, Chugach
Electric Association, Matanuska Electric Association, and Homer
Electric Association. The assumptions used in the economic analysis of
combustion turbine power generation were the following:
25 year investment cycle
heat rate of 10,800 Btu/kWh
capital cost of ~720/kW for turbines 5-50 MW in size
o and rv1 cost of ~O.005/kWh
5.2.4 Screening Results
Benefit/cost ratios which use average cost values were developed for
screening purposes. The benefit-cost ratio is defined as the costs of
the most likely alternative method of power generation (diesel,
combustion turbine) divided by the costs of hYdroelectric generation.
1/ A heat rate of 12.7 kWh/gallon was derived from data provided by
Caterpillar Products and Sales Services. A value of 12.4 kWh/
gallon was used as a conservative estimate of the diesel heat rate.
5-3
combustion turbine) divided by the costs of hYdroelectric generation.
The average ratio was taken for the cost of power generated during the
1981-2030 period. A B/C ratio gre~ter than 1.0 indicates that the
I'lYdro site is worthY of further cor'isideration. .
Six sets of benefit/cost ratios were examined, including 0, 2, and
5 percent fuel escalation, with and without the capital costs of
alternative power included. Benefit/cost ratios based on fuel
escalation but excluding the capital costs of the diesel generators
were included as part of the analysis since it can be assumed that
I'\Ydropower can supplement the existing generating system but not
replace it. Since hYdropower wou'ld be unlikely to meet 100 percent of
the demand throughout the year, diesel generators would be used as . \
standby power. Based on a 5 percent fuel escalation, the results of
the preliminary screening indicate that 12 communities have no
attractive hydroelectric sites while 13 communities survived the
screening. The results were the same for both the inclusion and
exclusion of capital costs of alternative power. Two of the thirteen
communities were subsequently eliminated from further consideration.
Chatanika Site No.2, the only site for this community with a B/C ratio
greater than 1.0, was eliminated from further study because it was
discovered, upon examining the 15-minute series maps, that the drainage
area previously estimated on the 1:250,000 scale-map was considerably
too large. Sites at Mansfield Village were eliminated from further
consideration since it was discovered during the field reconnaissance
that the community is a temporary fishing camp for residents of
Tanacross. Eight of the 13 communities that had sites with B/C ratios
greater than 1.0 were investigated during the field reconnaissance. A
summary list of study area communities grouped into categories
resulting from the preliminary screening is presented in Table 5-1.
As explained in the following chapter, communities which had at least
one site with a benefit-cost ratio greater than 1.0 were included in
the detailed study phase, the results of which are presented in
Table 1-1.
5-4
TABLE 5-1
SUI\1MARY OF COMMUN ITY HYDROPOWER POTENTIAL
NORTHEAST REGION
Sites With
No Potential
Beaver
Bi rch Creek
Central
Chalkyitsik
Chicken
Ci rcl e
Circle Hot Springs
Fort Yukon
Livengood
Rampart
Stevens Vi 11 age
Wi seman
Potential Sites/
Not Visited
Potential Sites/
Field Reconnaissance
Big Delta
Chena
Delta Junction
Kaktovik/B,rter Island
Chatanikal
Arct i c Vi 11 age
Dot Lake
Eagle
Eagle Village
Mansfield Village
Tanacross
Tok
Venetie
11 Subsequently eliminated due to limited drainage area.
5-5
u
6.0 DETAILED INVESTIGATIONS
Conmunities which had at leas,t one site with a benefit-cost ratio
greater than 1.0 were included in the detailed study phase. Each site
to be studied was selected on the basis of field observations or study
of more detailed (1:63,560-scale) maps. In a·. few instances, detailed
map study indicated unfavorable conditions which could not be seen in
the preliminary screening, and such sites were not included in the
detailed investigations. This chapter provides information regarding
the procedures employed in conducti "g. the detail ed investigations.
6.1 FIELD RECONNAISSANCE
At each community visited, as many of the candidate sites were observed
as possible. Use of helicopters allowed inspections from the air and
on the ground. Initially, the intent had been to inspect only the
sites at each conmunity ranked highest during the preliminary
screening, with the dam sites inspected from the ground and stream and
valley section measurement made at one or both sites. However, the
field inspection revealed several anomalies, including occasionally
pronounced differences in the runoff observed on north versus
south-facing basins, the disappearance of stream flow into floodplain
gravels or complete absence of flow in some basins. In addition,
community leaders consistently expressed a desire for a supply of
hydropower during the winter season. This led to reconsideration of
and visits to larger streams with potential for more adequate winter
flow.
The field reconnaissance revealed significant differences in stream
cross-sections, bed material, and sediment type and movement. In the
Brooks Range the streams generally flow over exposed bedrock and have
relatively dense vegetated banks that contribute very little sediment
to the flow. None of the streams in the study area flow over loose
volcanic ash, suited to use in sheet pile dams.
In the foothills of the Alaska Range, alpine streams fed by glaciers
are common. These streams can be grouped into two sub-types, here
called "braided" and "torrential". Both types require special
considerations in the type of diversion dam and intake selected. The
"braided ll streams typically consist of several narrow active channels
within a broad channel, up to 300 foot wide, composed of 2 to 12 inch
sized gravel and small boulders. Typically a gravel terrace, two or
three feet higher than the channel, extends for 100 to 200 feet on one
or both sides. This gravel terrace floodplain in most cases is covered
with vegetation. A diversion structure for this type of stre~m would
have to extend the entire valley width. An important consideration is
the danger of potential undermining of a surface type dam versus the
probably greater expense of excavating and constructing the structure
down to bedrock. '
6-1
The "torrential" alpine streams mayor may not exhibit the slightly
raised floodplain terrace. The main stream channel might typically be
only 30 to 80 feet wide, with a bed of large gravel and up to 2 foot
size boulders. This material can be readily visualized as quickly
piling up against and overflowing any low. to medium height diversion.
Spring floods deposit this material in their runout plains, miles
further downstream, and in the process build up continuous windrows on
either side, thus confining their own course. It was decided that the
intake on a torrential stream should be located 50 to 100 feet upstream
of the dam, thus avoiding the deposited sediment wedge at the dam.
Scour pipes through the dam can be provided but it is doubtful that
much gravel would be flushed on either the "braided" or "torrential"
streams.
Although storage type hYdro projects were not considered to be
economically feasible for isolated communities or for small intertied
systems. note was made of site suitability for storage projects in
general. The same approach was followed for the handful of communities
already forming part of a larger system limiting the present study to
projects not exceedi ng in design capacity the 1997 community load
demand. Only one potential storage project was identified, on American
Creek near Eagle. This would be a very large project, as discussed in
the Eagle section of this report, and was not considered to be within
the scope of this study.
6.2 HYDROLOGIC ANALYSIS
The detailed analysis of the most promising potential hydropower sites
required more accurate estimation and more complete description of
streamflow than was done for the initial screening phase (Section
5.2.2). The basis of the procedure was the assumption that runoff per
unit area in an ungaged stream was equal to runoff per unit area in a
nearby representative gaged stream. scaled by the ratio of mean annual
precipitation for the ungaged and gaged basins. That is,
Q2/A2 = (Q1/A1)(P2/P1)
where the subscripts 1 and 2 refer to gaged and ungaged basins,
respectively, and
Q = overall mean monthly or annual streamflow
A = drainage basin area
P = mean annual precipitation for basin
The factor P2/P1 adjusts for differing water inputs to the gaged
and unyaged basins and includes any effects due to elevation
differences between the basins.
(1)
The complete records of mean daily flows for .all current and
discontinued gaged streams in Northeast Alaska were obtained from the
U.S. Geological Survey on magnetiC tape. From these, stations were
selected for pairing with ungaged basins, based on geographical
proximity and correspondence of characteristics such as basin area,
percent of area glaciated, and general topographY. These stations are
6-2
u
listed in Table 6-1. For each of these stations, mean flow for each
month and year of record, overall mean monthly and annual flows for the
entire period of record, and a flow duration curve were calculated from
the daily data. Only data for complete water years were used in the
computations.
Due to the relatively short period of record for many of the gaged
streams and the fact that many recorded years could not be considered
IInormal" but rather high or low flow years, the development of flow
adjustment factors was necessary to define Ql in Equation 1
p'roperly. The factors were developed using long-term preCipitation
aata. Each gaged stream was paired with a nearby representative
long-term preCipitation station, which was used as an index to average
basin precipitation. The long-term mean annual rainfall from this
station was divided by the mean annual rainfall that occurred during
the stream gaging period. This factor was multiplied by the overall
mean monthly and annual flows calculated from the streamflow data to
obtain "normal" mean flows. That is,
Q1 = (Qt)(AP/GP)
where
Ql = "normal" mean monthly or annual flow
Ql* = mean monthly or annual flow calculated from streamflow
records
AP = long-term mean annual precipitation at index station
GP = mean annual precipitation at index station during stream
gagi ng peri od
( 2)
The flow adjustment factors for the gaged streams used for basin
pairing are listed in Table 6-2, and the adjusted mean annual flows are
given in Table 6-1.
After each ungaged stream identified as a potential nydroelectric site
was paired with a gaging station, the precipitation scaling factor was
derived and applied to the streamflow data for the gaged stream to
obtain mean flows for the ungaged stream. The preCipitation factor
(P /Pl in Equation-I) required knowledge of basin-wide mean annual
precipitation for gaged and ungaged basins. This information is
available in Lamke (1979). In this regression study of regional flood
characteristics, mean annual preCipitation was determined for many
Alaskan gaged streams. Also included in this report are isonyetal maps
covering the entire state, which were used by Lamke in determining mean
annual precipitation. For the present study, these maps were used to
obtain mean annual precipitation for all ungaged basins as well as for
any gaged basins used for pairing that did not have a mean annual
preCipitation value already reported by Lamke. Mean annual
preCipitation for gaged streams used for basin pairing are given in
Table 1, and values for potential nydropower sites are given in Table
6-3 and on the significant data sheets accompanying each community's
detailed description. The isonyetal maps from Lamke (1979) used in
this study are given in Figures 6-1 and 6-2.
6-3
TABLE 6-1
GAGED STREAMS USED FOR BASIN PAIRING
Station Station Drainage Mean Mean Length of
Number Name Are~ Annual Annual Record..!!/
(mi ) Precipitati on Flow
(i nches) (cfs)E/
15439000 Boul der Creek. 31.3 15 12.9 13(67-79)
near Central
15476))0 Berry Creek 65.1 18 50.0 8(72-79)
nea r Dot Lak.e
15564877 Wi seman Creek 49.2 18 28.1 8(71-78)
at Wiseman
15564885 Jim Ri ver 465 15 489 7(71-77)
nea r Bettl es
a/ Mean annual flow during gaging period multiplied by factors in Table 6-2.
b/ Compl ete water years only. Number of years is gi yen with the years of
record in pa rentheses.
6-4
u
Stream
Boul der Creek
Berry Creek
Wi seman Creek
Jim River
TABLE 6-2
FLOW ADJUSTMENT FACTORS FOR GAGED STREAMS
USED IN BASIN PAIRING
Index Precipitation
Station~/
Fai rbanks,
Universi ty Experiment Stati 00£1
Big Delta,
Northway.£l
Bettles
Bettles
Factor.bl
1.12
1.12
1.15
1.12
al National Weather Service stations as given in U.S. Environmental
Data Service (NOAA) Climatoligical Data.
bl Factor = AP/GP in Equation 2 in text.
£1 Factors obtained from two representative stations were averaged.
6-5
Site
Arctic Vi1l age
Site 3
Venetie
Site 2
TABLE 6-3
BASIN PAIRINGS AND HYDROLOGIC CHARACTERISTICS OF
POTENTIAL HYDROPOWER SITES
Estimated
Drainage Mean Mean
Are~ Annual a/ Annual
(mi ) Precipitation Flow
(inches) (cfs)
9.9 18 5.7
342 9 216
Eagle/Eagle Village 49.2 18 24.3
Site 1
Big Delta/ 23.5 25 25.1
De 1 ta Ju nc t ion
Site 2
Dot Lake 58.0 20 49.5
Site 2
Tanacross 29.0 10 12.4
Site 1
Tok 27.0 10 11.5
Site 7
Pai red
Gaged
Stream
Wi seman Creek
Jim River
Boulder Creek
Berry Creek
Berry Creek
Berry Creek
Be'rry Creek
!I The mean annual precipitation values presented are for the cited
drainage basin, estimated from iso~etals in Lamke (1979).
6-6
62
c
152" 148" 146" 144·
TANANA AREA
o . 50 MILES c:: E?3 £ .. , .. '1.---1
Figure 6-1. Mean annual precipitation and mean minimum January temperatures in Tanana area.
(Source: Lamke 1979)
c
140'
(7).
I
Q)
66·
:Pi'\.'t:~· .. / .
. ;~-:'_.f ..... ~
!'t'6""1!1' >
/
150'
Figure 6-2.
c
1460 140'
;1', :J .. ~~::~~y
14 n° . --~~~-oil;r-
Mean annual precipitation and mean minimum January temperatures in upper Yukon area.
(Source: La!11ke 1979) c
u
The drainage areas of the ungaged streams (A2 in Equation 1) were
determined by locating the dam sites on 1:63,360 USGS topographic maps
(except for Venetie, for which the largest scale map available is
1:250,000), outlining the drainage basins contributing runoff to those
poi nts, and pl animeteri ng the resulting areas. Ora; nage areas for
gaged streams were given in the station descriptions accompaO¥ing the
USGS flow data. Drainage area data are given in Tables 6-1 and 6-3 and
the community significant data sheets.
The procedures described above were used to derive values for Q1'
AI, A2, PI, and P2 in Equation 1. The solution to Equation 1
was labeled Q2' tne mean flow for the ungaged stream. This was done
for all ungaged streams to obtain overall mean flows for each month of
the year and to obtain the overall mean annual flow of the stream.
Further description of streamflow in the ungaged streams was obtained
using dimensionless annual flow duration curves calculated from the
USGS daily streamflow data for the gaged streams. Since the curves
were dimensionless (the ordinate was flow divided by mean annual flow),
they could be applied to the paired ungaged streams. Once the mean
annual streamflow for an ungaged stream was determined as outlined in
the procedure given above, the ordinate of the flow duration curve was
multiplied by this value to obtain a flow duration curve for the
ungaged stream. Flow duration curves for the gaged streams used for
pairing are given Figures 6-3 through 6-6.
The flow duration curves were used to determine plant factors for
hYdropower projects for utility-served communities. For these
communities, it could be assumed that aO¥ energy in excess of community
demand could be routed into the utility grid and sold. Therefore, a
standard flow duration curve analysis to determine percent of total
flow that is usable was appropriate. This percent was only dependent
on powerplant machine limitations. On the other hand, a flow duration
curve analysis was i nappropri ate for projects servi ng isolated
communities not within a utility grid because the energy available for
which there was no demand could not be sold elsewhere. This reduced
the percent of total flow that is usable below the value due strictly
to powerplant machine limitations. For these communities, mean monthly
streamflows were used instead of the flow duration curve to estimate
flow availability. These flows were used in a computer program that
calculated a plant factor by comparing energy availability to demand.
The procedures for determining plant factors are described in more
detail in Section 6.3.
The methodology described above can be expected to give reaso.nable
estimates of mean annual flow and the flow duration curve but less
accurate estimates of mean monthly flows for ungaged streams. This is
because a number of variables have a significantly greater effect on
monthly flows than on annual flow. Factors such as orientation of
slopes (i.e., north or south-facing) and percent of drainage area
glaciatedha've a large effect on the monthly distribution of flow. For
example, streams draining primarily north-facing slopes or glaCiated
6-9
~
9
LL.
~
LaJ
:::&
......
~
...J
LL.
4.0
3.5
3.0
2.5
2.0
1.5
1.0
0.5
ADJUSTED MEAN ANNUAL FLOW = 12.9 cfs
DRAINAGE AREA =31.3 mi 2
o~--------------~~=---.-----~ o 20 40 60 80 100
PERCENT OF TIME FUJN IS EQUALED OR EXCEEDED
REGIONAL INVENTORY & RECONNAISSANCE STUDY
SMALL HYOAOPOWER PROJECTS
FIGURE 6-3
FLOW DURATION CURVE FOR BOULDER ~
CREEK NEAR CENTRAL,ALASKA
DEPARTMENT OF THE ARMY
ALASKA DISTRICT CORPS OF ENGINEERS
~
9
LI..
S
::I
........
~
-' LI..
u
4.0
3.5
3.0
2.5
2.
1.5
1.0
0.5
ADJUSTED MEAN ANNUAL FLOW = 50.0 cfs
DRAINAGE AREA =65.1 mi 2
o+-----~------~------~----~------~ o 20 40 60 80 100
PERCENT r:F TIME FLOW IS EQUALED OR EXCEEDED
.. I'
A£GiONAL IHVEHTQRY & RECONNAISSANCE STUDY
SMAU HYDROPOWER PflOJECTS
FIGURE 6-4
FLOW DURATION CURVE FOR BERRY
CREEK NEAR DOT LAKE, ALASKA
DEPARTMENT OF THE ARMV
ALASKA DISTRICT CORPS OF ENGINEERS
~
LI..
~
1&.1
::I
......
~
..J
LI..
4.0
3.5
3.0
2.5
2.0-
1.5
1.0
0.5
ADJUSTED MEAN ANNUAL FLOW: 28.1 cfs
DRAINAGE AREA: 49.2 ml2
O~----____ --~~--~----~----~ a 20 40 60 eo 100
PERCENT OF TIME FLOW IS EQUALED OR EXCEEDED
6-12
REGIONAL IHVamlRY & RECOIitWSSANCE STUDY
SMALl HYDROPOWER PROJECTS
FIGURE 6-5
FLOW DURATION CURVE FOR WISEMAN
CREEK AT WISEMAN I ALASKA
DEPARTMENT OF THE ARMY
ALASKA DISTRICT CORPS OF ENGINEERS
~.
9
I&.
i
LLI
::::&
......
~
...J
I&.
u
4.0
3.5
3.0
2.5
2.Q.
1.5
1.0
0.5
ADJUSTED MEAN ANNUAL FLOW: 489cfs
DRAINAGE MEA = 465 mi 2
0L---~--__ --~====~~~ o 20 40 60 80 100
PERCENT (;If TIME FLOW IS EQUALED OR EXCEEDED
.6-13
REGIONAL INVENTORY & RECONNAISSANCE STUDY
SMAll HYDROPOWER PROJECTS
FIGURE 6 -6
FLOW DURATION CURVE FOR JIM RIVER
NEAR BETTLES, ALASKA
DEPARTMENT OF THE ARMY
ALASKA DISTRICT CORPS OF ENGINEERS
basins have their peak runoff period a month or two later in the year
than do streams draining south-facing slopes or unglaciated basins.
These factors have a much small er effect on annual flow. Iii Q basi n V
pairing procedure~ it is often difficult to find nearby gaged streams
with all drainage basin characteristics similar to the ungaged streams~
especially in remote areas such as Northeast Alaska, where gaged
streams are very sparse. Good estimates of mean annual flow can still
be obtained under such conditions, but mean monthly flows can be in
error, especially during the spring and summer snowmelt periods. The
mean annual flows estimated by this methodology, therefore, can be
considered to be more accurate than the estimated mean monthly flows.
While the accuracy limitations of the mean monthly flow estimates are
recognized, monthly estimates were developed in order to derive plant
factors for sites serving isolated villages, as discussed in the
following section. This procedure was determined to be appropriate in
a reconnaissance-level study, but a more rigorous approach supported by
better data would be required at the feasibility level of study.
, 6.3 PLANT FACTORS AND INSTALLED CAPAC lTV
Two methods of plant factor analysi s were used in the more detailed
studies. The first method was used in systems where the installed
capacity of the nYdroelectric plant was substantially below the average
system utility demand (annual energy divided by 8,760 hours). It was
assumed that the utility can sell any power produced, and the only
limitation to the amount of energy produced ,,,ould be availability of
streamflow to operate the turbines. The installed capacity was sized
to capture up to 1.5 times the mean annual flow. Any flow occuring in
excess of that amount was assumed to be spilled without producing
power. In addition, turbines cannot operate below a certain minimum
flow, which is determined by machine limitations. When the flow drops
below that amount, the turbine cannot operate and must be shut down.
The flow duration curve in Figure 6-7 illustrates the principles
involved. The area beneath the curve represents the total flow in the
stream, and the shaded area beneath the curve represents the fraction
of the total flow that can be used to generate power. This fraction is
multiplied by the annual average flow and termed the usable annual
average flow qu (in cfs). The annual energy (E) resulting from this
flow is calculated by the following equation:
E = quHn e 8760
11.8
where: Hn is the net head in feet, e is the system efficiency, based
on a tyical turbine efficiency of 0.85, generator efficiency of 0.96
and transformer efficiency of 0.98, which results in e = 0.80, and 8760
;s the number of hours per year. The factor 11.8 is a conversion
factor used to make all units dimensionally consistent.
6-14
4.0
3.5
3.0
2.5
u
PLANT FACTOR = FRACTION OF TOTAL FLOW
THAT IS USABLE X
MEAN FLOW.;. DESIGN FLOW
PERCENT CE TIME FLOW IS EQUALED OR EXCEEDED
6-15
REGIONAL INVENTORY & R£CONNAISSANCE sruoy
SMAll HYDAOPOWeJI PROJECTS
FIGURE 6-7
FLOW DURATION CURVE PLANT FACTOR
ANALYSIS FOR UTILITY-SERVED
COMMUNITIES
DEPARTMENT OF THE ARM ...
ALASKA DISTRICT CORPS OF ENGINEERS
Dividing the above annual energy actually generated by the energy that
could be generated by the plant operating at the design flow for the
entire year. yields the plant factor. U
Isolated communities and smaller utilities required a different
approach to estimate the plant factor. since not all power that can be
produced during periods of low demand can be sold. This approach is
illustrated in Table 6-4~ a typical summary table for 1997, the design
year. The computati ons i nvol ved were perfonned on a computer for each
year in the 50 year period of analysis. although only the design year
results were output. This infonnation was included in the significant
data section for each site analyzed. .
In order to implement this second approach~ average monthly flows were
deri ved as detailed in Secti on 6. 2~ Hydrologic Analysi s. The potenti a1
hYdroelectric energy generation was calculated based on the net head,
average monthly flow~ and number of hours per given month. When
average monthly flows exceeded the design flow~ the design flow
replaced the average monthly flow in the computations. When average
monthly flow fell below the minimum operating flow for the turbine
unit, it was assumed that no hYdroelectric energy was generated.
The installed capacity was selected as the lesser of the capacity
required to meet the 1997 annual energy forecast in kilowatt-hours,
divided by 8,760 hours per year and multiplied by 1.6 (see discussion
below on load utilization curve) and by the capacity resulting from
utlization of 1.5 times the average streamflow.
The pen:ent of average annual energy used in each month wa~ based on
five villages in the Alaska Village Electric Cooperative.1! These
values were multiplied by the yearly annual energy forecast to obtain
monthly energy demand in kilowatt hours.
The usable hYdro energy was calculated from the potential hydroelectric
energy generation (PHEG) and the energy demand. The method is
illustrated graphically in Figure 6-8. The figure represents a load
durati on curve for a gi ven month and year (i n this case the month of
October and the design year~ 1997). The curve shape was developed from
several references (USDI 1980; Creagher and Justin 1950; and Linsley
and Franzin 1975) and actual field observations. The ordinate is the
non-dimensional ratio of hourly demand to average daily demand (by
definition 1.00 represents the average daily demand). The abscissa is
the time (hours) over which that ratio prevails. The factors defining
the curve are referred to as load shape and hour factors. The daily
peak was assumed to occur during lunch and/or dinner time. It was
estimated to be twice the average daily demand and have a duration of 3
hours. This corresponds to a load shape factor of 2.00 and an hour
factor of 3.00. The bulk of the demand was estimated to be greater
11 Small Hydroelectric Inventory of Villages served by Alaska Village
Electric Cooperative~ United States Department of Energy~ Alaska
Power Administration~ December 1979.
6-16
U
TABLE 6-4
TYPICAL PLANT FACTOR ANALYSIS FOR ISOLATED COMMUNITIES
AND SMALL UTILITIES, DESIGN YEAR 1997
NE/SC ALASKA SMALL HYDRO RECONNAISANCE STUDY
PLANT FACTOR PROGRAM
COMMUNITY: VENETIE
SITE NUMBER: 2
NET HEAD (fT): 32.
DESIGN CAPACITY (KW): 196.
MINIMUM OPERATING FLOW (1 UNIT) (CFS): 9.20
LOAD SHAPE FACTORS: 0.50 ·0.75 1.60 2.00
HOUR FACTORS: 16.00 15.00 13.00 3.00
MONTH (#DAYS/MO.) AVERAGE POTENTIAL PERCENT ENERGY
MONTHLY HYDROELECTRIC OF AVERAGE DEMAND
FLOW ENERGY ANNUAL ENERGY
(CFS) GENERATI ON (KWH) (KWH)
JANUARY 14.10 22443. 10.00 106982.
FEBRUARY 11.20 16102. 9.50 101633.
MARCH 11.00 17509. 9.00 962~4.
APRIL 14.50 22335. 9.00 96284.
MAY 820.00 145824. 8.00 85585.
JUNE 671.00 141120. 5.50 58840.
JULY 206.00 145824. 5.50 58840.
AUGUST 316.00 145824. 6.00 64189.
SEPTEMBER 371.00 141120. 8.00 85585.
OCTOBER 86.90 138318. 9.00 .96284.
NOVEMBER 34.40 52988. lU.OO 106982.
DECEMBER 20.50 32630. 10.50 112331.
TOTAL 1022037. 1069818.
PLANT FACTOR(1997): 0.31
PLANT FACTOR(LIFE CYCLE): 0.33
6-17
USABLE
HYDRO
ENERGY
14962.
10735.
11672.
14890.
82417 •
58840.
58840.
64189.
81829.
82946.
35325.
21753.
538399.
2.0! ........ ----.
EXAMPLE I VENETIE
MONTH OF OCTOBER
ESIGN HYDROELECTRIC ENERGY
(l45,824 kWh) (PLANT LIMITED)
o «
9
1.5
UJ ~ 1.0
a::
UJ
~
....... g
...J
6.
LEGEND
12
HOURS
V7l POTENTIAL HYDROELECTRIC ENERGY-LL-LJ (138,318 kWh) (FLOW LIMITED)
~ USABLE HYDROELECTRIC ENERGY
~ (82,946 kWh)
6-18
18 24
REGIONAl. INVBmJIV &. ~ANCE STUDY
SIIAU, HYIlAOPOWER fIfIOJECTS
NORTHEAST ALASKA
FIGURE 6-8
LOAD DURATION CURVE FOR PLANT
FACTOR ANALYSIS -ISOLATED
COMMUNITIES AND SMALL UTILITIES
DEPARTMENT OF THE ARMV
ALASKA DISTRICT CORPS OF ENGINEERS
than or equal to 1.6 times the average daily load and anticipated to
occur over 13 hours. Therefore, it was selected as an installed
capacity ~uide1ine. During the eight hour night-time period, demand
normally 1S minimal and was therefore assumed to be zero for this
analysis.
The resulting PHEG value was converted to a non-dimensional ratio by
dividing it by the monthly energy demand. Values of the ratio were
then plotted as a line on the load duration curve. The shaded area
beneath the line represents the usable ~droelectricenergy. It was
calculated by the computer from the defined load shape and hour factors.
The plant factor is equal to the sum of the usable ~dro energy,
divided by the energy that would have resulted from operating the plant
at its installed capacity for the period under consideration. The
plant factors output included the 1997 design year plant factor as well
as the pl ant factor resul ti ng over the 50 year peri od of analysi s.
6.4 CONCEPTUAL ENGINEERING
6.4.1 General
From previous experience on similar studies and from a brief economic
sensitivity analysis, the type of ~dro development adopted was limited
to run-of-the-river plants. Accordingly, at the few topographically
very favorable sites where a minor amount of storage was provided
behind forty foot high dams, no credit was given to this storage in
operational studies because increasing dam height proved simply the
most economic means for providing sufficient spillway capacity and
sediment storage, as well as providing additional head in confined
sites.
Reconnaissance level studies were conducted of the type of diversion
dams, waterways, mechanical and electrical equipment, powerhouses,
transmission lines, access, and mobilization and demobilization. The
studies included review and evaluation of:
1. Published climatologic, geotechnical and other relevant data
on the study area;
2. State of art of small ~dro engineering in cold regions,
i ncl udi ng previously completed reports;
3. Equipment manufacturers data;
4. Transmission line options;
5. Access techniques; and
6. Contractor mobilization/demobilization requirements including
need for construction camps.
6-19
For the optimum site for each community the selected damsite and
project layout are described on its Significant Data sheet included in
thi s report.
Except for some river valleys and south-facing slopes, the entire
Northeast study region is generally underlain by permafrost. The main
aspects in which the presence of permafrost often may potentially
affect engineering projects are evaluated in considerable detail in the
1980 USCOE report on Northwest Alaska. Several of the restrictive
conclusions reached in that report are, however, applicable to a much
larger degree, to storage type projects in the flatland and muskeg
country of Northwest and Southwest Alaska, where only a handful of
sites could develop more than a hundred foot of head. These
conclusions are not felt to be fully applicable to the foothill and
mountain country of this study area where practically all the sites
evaluated in this study would be located. There can be no doubt that
extensive geotechnical exploration would be required on any project in
order to establish, by drilling, electromagnetic surveys, jacking 'in
holes and by other methods, the extent, temperature, and other
characteristics of the permafrost areas and zones. It should, however,
be remembered -that permafrost is not continuous in the Northeast study
region, and that the types of areas were the extent of permafrost is at
a minimum and/or where its presence has the least effect on
construction are typically those in which any small run-of-the-rfver
type hYdro developments would be located. Such modifying factors, as
they might lessen the negative impact of permafrost on the main project
elements, are summarized below:
o Diversion Dams
In almost every case these would be located on thaw-stable
gravelly materials or on bedrock. In quite a few cases the
stream might also already have created a thaw-bulb strip all
along its course, thus having actually entirely removed any
pennafrost. low concrete dams are therefore not 1 ikely to
settle significantly, nor would their safety be likely to be
endangered by any nominal increase in leakage flow underneath
them. Nor would minor temperature cracking within the
concrete blocks endanger these small structures.
o Penstocks
In most cases penstock routes would ski rt a stream bank, and
be located either on gravel terraces or on shallow bedrock,
their gradient normally dipping quite steeply. This would
avoid the need for any deep excavation or use of arctic type
piles to reach the bedrock. Settlement upon melting of any
ice lenses in the bedrock could readily be absorbed by the
penstock by means of incorporation of slight bends in plan and
by use of expansion joints.
6-20
u
o
o
.}, I <'
Powerhouse
Most likely, powerhouses would be seated within a gravel
terrace or on a bedrock b1 uff and therefore not be affected
adversely by permafrost, if present. In the few cases where
it might be located on banks of finer material, drilled piles
would readily ensure its safety.
Transmission Lines
For most of thei r 1 ength the routes woul d probably run in
terrain similar to that followed by the penstock routes.
Crossing of any limited local adverse permafrost areas of
frozen wet silty ground, in the flat country at the foot of
the hills, would be readily achieved by use of double
po1yethe1ene film wrapped around the embedded part of the
poles.
o Access Roads
Because of th~ relatively favorable topographic and foundation
factors discussed above, need for limiting access to winter
only would not be an automatic conclusion. The heavy
construction materials and equipment, as well as the permanent
project equipment. might well. however, be moved during
wintertime, simply because of the greater ease of winter
transportat ion.
6.4.2 Diversion Dams
The type of dam selected depends upon soils and foundations conditions
found at the project site. Soils and foundations information was
obtained from soil classification data in "Exp10ratory Soils Survey of
Alaska" of the U.S. Department of Agriculture So11 Conservation Service
(1979). The classification data describe soil types, terra.in slope.
erodibility and stability for roads. and other types of foundations.
Three types of diversion dams. conSisting of concrete. sheet pile, and
embankment structures. were considered for the Northeast Region sites.
A sheetpi1e and rockfi11 diversion structure requires soils conditions
in which driving of sheetpi1es is feasible. This was ruled out because
of the common occurrence of permafrost and large boulders and gravel.
Embankment structures were also ruled out, because their spillway
requirements would be economically unattractive in comparison with
conc rete dams.
The concrete dam scheme, shown in Figure 6-9, incorporates an intake
structure with a central overflow spillway section, and riprap
protection to the creek channel immediately downstream of the diversion
dam. Diversion into the penstock pipe will occur from an intake box.
slightly recessed into one stream abutment and normally located just
upstream of the dam face. Flows enter this intake box through a
6-21
sloping heavy grating-type trashrack~ located on an incline along the
top of the box. Thi s arrangement all ows fo.r easy mai ntenance removal
of any accumulated trash and the closed vertical walls of the box
exclude bottom sediment·from the vicinity of the pipe intake. A scour
val ve has been incorporated on each side of the stream for peri odic
flushing of bottom sediment accumulated. An overflow weir would be
located centrally over the stream bed~ with its crest elevation several
feet above the top of the intake box. This will allow winter flow to
enter the penstock even after up to a four foot thick ice cover has
fonned.
As shown on Figure 6-9, this dam, up to 40 foot high, would have a
central standard ogee spillway section with a bucket energy
dissipator. No fish ladder has been indicated or costed out for this
concrete dam because the cost of this item could become quite
considerable for this higher dam and shoulq therefore only be studied
where feasibility studies showed an actual need for such provisions.
The ogee spillway was sized for a 50-year flood, in accordance with the
approach in USCOE "Feasibility Studies for Small Scale Hydropower
Additions" (1979) for low hazard dams, with storage not exceeding 1000
acre feet and heights less than 40 feet. These 50 year floods were
detennined using the method detailed in "Flood Characteristics of
Alaskan Streams" (1975), taking no allowance for lake and pond storage
or forests. Mean minimum January temperatures of -20°F for the
Northeast Region were assumed. Various combinations of spillway height
and width were utilized in order to confine this flood to the main
stream channel. No freeboard was provided to the top of the
non-overflow section which was assumed to be safely overtopped during
larger floods.
This dam type will also provide a considerable amount of sediment
storage, as well as ample room for an ice sheet to form. However,
because only the sand size fraction of sediment would probably be
subsequently removed through flushing, the large gravel, cobble, and
boulder size particles would continue to accumulate against the dam.
For most of the sites, the need for provision for a certain amount of
sediment storage, especially on the braided and/or torrential streams,
caused the intake structure for the penstock to be an independent
structure, located 50 to 100 feet further upstream. From field
observation and literature study it was assumed that all concrete dams
would reach relatively impervious alluvial materials -or bedrock -
after excavating down four feet. This assumption also infers that
foundation treatment requirements would not become excessive.
At some sites an earthfill type of dam was evaluated in wide stream
valleys on creeks requiring relatively large spillways. A standard,
"non-frozen" earth and rockfill dam section with 2.5 to 1 slopes -as
costed .out by USCOEand given as Figure 4-2 in Tudor (1981) Report -
was considered with a ·freeboard of ten feet provided for the 50 year
flood. The spillway was assumed to be an ungated concrete chute in an
abutment. Details of the core, filter, and rockfill zones would depend
on the local availabilty of materials. The intake would be as for the
6-22
u
TO POWERHOUSE
ING GRADE
MAX. 50 YEAR w.L.
NORMAL W.L.
SECTION A-A
SCALE: 1"= 10'
6-23
STRUCTURE
PLAN
: VARIES __ .. OL .... " ,.., ... L TO BE DESIGNED TO
STANDARDS (TYPICAL)
VARIES
06'-260'} : OGEE SPILLWAY
",
". ", SIDESLOPE
",'" (VARIES)
", -----------~.... /----_.....--.------1--------
DEPTH OF EXCAVATION -...,.----'
(VARIES) ELEVATION
SCALE: Iii = 2d
BACKFILL BETWEEN
CONCRETE WALLS
SECTION B-B
SCALE: I": 10'
HEAVY
GRATI NG
"""-~ TO
POWER
HOUSE
p.
I
~I
I
!-----
SECTION C-C
SCALE: 1"=10'
REGIONAL INVENTORY & RECONNAISSANCE STUDY
SMALL HYDROPOWER PROJECTS
NORTHEAST ALASKA
,LARGE CONCRETE DAM AND INTAKE , -. ..
STRUCTURE. TYPICAL LAYOUT
FIGURE 8-g.
DEPARTMENT OF THE ARMY
ALASKA DtSTRICT
CORPS OF
u
1 arger concrete dams but the penstock woul d be concrete-encased through
the dam and provided with a downstream control gate and an adjacent
smaller diameter pipe for stream releases. Largely because of the
great cost for the concrete chute spillway, this type of dam did not
prove to be economical and was not further considered for Northeast
Region sites. .
Normal construction practice requires the contractor to be responsible
for cofferdam construction and diversion of water around the dam site.
This item is highly variable in cost and, as such, is included in the
contingency amount.
6.4.3 Soils and Foundations
U.S. Department of Agriculture soils maps were utilized in
identificaton of rocky and steep mountainous areas where access,
penstock, and transmission line construction might prove to be
difficult and more costly.
The type of bedrock is of relatively minor significance for the very
small size hYdraulic structures that would be required at the sites
evaluated in this report. Both bedrock and permafrost profiles should,
however, be established at both the intake and the powerhouse sites.
Diversion dam and powerhouse structures do not necessarily have to be
seated on bedrock, but could be supported on dense, pervious gravel.
For both the dam and powerhouse structures, the need for a cutoff to
bedrock would have to be evaluated in order to avoid seepage and
subsequent potential piping failure at the intake weir and undermining
by eddying currents at the powerhouse.
It is possible that pile foundations for the powerhouse may be required
at those few sites where bedrock, clean gravel, or other foundation
material not subject to frost heave, does not exist at a shallow
depth. Pile found~tions, incorporating appropriate measures for
dealing with permafrost, such as use of non-frost-susceptible backfill
slurries, proper anchoring, etc., would then be utilized. Because of
the lack of subsurface information, both with regard to extent of
permafrost and espeCially on the type and thickness of foundation
material, the increase in cost due to the need for such foundations was
not included in the present study.
6.4.4 Waterways
The use of open canal s as waterways was eval uated and rejected for
these projects, partly because of the negative environmental aspects,
but mainly because of the likely thawing of the underlying permafrost
and resulting permanent erosion, unless extensive gravel surround was
to be provided. All water conveyance structures would be enclosed
pipelines.
6-24
The ~draulic head at each site was generally maximized in order to
maximize power operations. The unit cost of penstocks was kept to a
minimum, both by limiting the design pressure and by reducing roughness
of pipe which allowedCthe penstock diameter to be reduced. Diameters
were selected to limit head losses to 10 percent of gross head, using
the Hazen Williams equation with CHW = 140.
The alignment selected attempts to maximize the low pressure pipeline
sections of the penstocks. The use of a low-head penstock section is
possible along the upper reaches of many sites. However, for the
manufactured steel penstock pipe assumed in this study, minimal,
normally accepted handling thicknesses proved to govern the pipe
thickness and hence the cost up to a static head of 280. feet for large
diameter (54" and greater) pipes, and increasing up to 560 feet for
small 12" diameter pipes. An allowance of 35 percent of static head
for surge was included.
Except for a ve~ short section immediately downstream of each intake
weir, where burial and/or concrete encasement appear to be practically
a requirement in order to provide protection against undermining and
other damage from high flood flows, the penstock line can be left
exposed. (Burial of up to 2-mile long penstocks would, in most cases,
prove to be very expensive and the long-term environmental impact from
potentially extensive excavation and soil erosion could be Significant,
although not pOSing as high a likelihood as erosion from canals.)
A brief state-of-the-art survey was carried out for the smoothest type
of readily available, long-lasting, and economic internal lining for
both facto~ manufactured steel pipes and field-assembled small
diameter (5 feet and below) steel penstocks. The optimum lining proved
to be either polyurethane vinyl, hand coated in 3 to 5 mil thickness,
or mechanical extruded vinyl lining (30 mil). For the outside coating,
zinc rich exterior primer with 2 protective coats of polyurethane vinyl
would be suitable for the Alaska locations.
Tar, tar enamel, tar epoxy, or asphalt exterior coating is not
recommended as these proective coatings become brittle and spall at the
sub-zero Alaskan winter temperatures.
Plastic pipe!! has been installed both above ground and underground
for water supply and sewerage service in the Alaska environment, and
has performed satisfactorily. Because of the remoteness of the sites
in this study, use of plastic pipe was, however, not deemed advisable
without further detailed investigations.
_1/· Either FRP (glass fiber reinforced isopthalic resin) or high
density polyet~lene.
6-25
v
No insulation was specified for the penstocks because maintenance of
continued flow within. full pipes was assumed' to basically provide
sufficient prOtection against freezing. To further guard 'against any
freezing and to enable rapid restarts to be made if freezing still were
to happen, the penstocks were finally assumed to be of steel. Small
diameter drain pipes would be specified at frequent dips in the
penstock profile to ensure speedy drainage of the system during any
lengtny shutdowns. At certain sites, low flow or no flow conditions
wi 11 prevent nydroel ectric operation duri ng the wi nter months.
Detailed i nvestigati onsof the pipelf ne thermodynamics as well as
insulation, flow bypass systems, and pipe burial should be conducted
during feasibility studies. No line items for these components have
been provided for in this study other than the general contingency.
Also, as discussed in Section 6.4.1, no special support provisions were
designed or costed in this reconnaissance study for coping with
permafrost, since the extent of this foundation aspect would first have
to be determined by detailed field studies.
6.4.5 Turbines and Generators
The project sites evaluated have a potential output range of from 60 to
1,000 kilowatts, with heads from 50 up to 400 feet. Impulse turbines
are utilized for most sites in this ~tudy because their ability to
operate over a wide range of flows.l! Typically, theseturb1nes
operate safely at 20 percent of maximum output. Accordingly, with two
turbines per site, nydroelectric generation can thus be maintained with
stream flows as low as 15 percent of the average flow. At Eagle,
however, only a single unit is proposed, both because of the low plant
capacity (60 kW) and because of extremely low winter flows.
F9r the small size generating units involved in this' study, ready means
a're a-vail able to 1 imit-the potential pressure-changes upon sudden flow
changes in the penstock, without resorti ng to .relative1y exp'ensfve
nydraulic structures, such as construction of surge tanks. Moderation
orelimi,na'ti(:>n of potential pressure rise from sudden loss or decrease
in load in the case of impulse-type turbines is built into the machine
in that the jet deflector first deflects the jet from the turbine
without changing the rate of flow in the penstock. Thereafter, the
needle valv.e controlling the flow can be slowly mov~d to a pOSition
corresponding to the new output. The rate of closure of the valve can
be controlled to protect the penstock from unacceptable pressure rise.
1/ Di,scussions were hel d with the manufactur~rs of small-size, but
basically medium-to high-head turbines,. The two major U.S.
turbi ne manufacturers do not 1 ncl ude . small impul se turbi nes of the
size required for these installations i.n their proauc~ line. There
are, however, domestic small special ty turb.i ne manufacturers and
foreign suppliers who do supply this equipment. Price information
covering the full project range was obtained from a domestic
manufacturer for this class of equipment.
6-26
The nozzle needle can be designed to maintain some flow in the
penstocks to avoid freezing. If it is anticipated than any of the
plants might be shut down for long periods, the intake valves provided
at the head of the penstock can be closed to drain the penstock. The
intake valves will generally be manually operated.
On all the project sites the diverted flow through the penstock is
assumed to be divided at the powerhouse into two equally sized
impulse-type units. The typical arrangement, using two packaged units,
is shown on Figure 6-10. The penstock would bifurcate just upstream of
the powerhouse into two pipes, each supplying a skid-mounted unit
package, seated on a concrete base slab. Each unH would di scharge
into a tailrace slot cut into this concrete base slab. Because impulse
turbi nes have to di scharge into atmospheric pressure above the maximum
tailrace elevation, about 3 to 6 feet of hYdraulic head is lost. This
loss is negligible when considering the flexibility of the machine and
its ability to operate without expensive surge tanks.
The package unit enclosures are supplied by the manufacturer and are
included in the total cost of the unit. If these package enclosures
prove to be not sufficiently insulated, a prefabricated wooden building
could be readily placed over the two unit packages. The additional
costs would be negligible in comparison with eachcproject cost.
The preferred orientation of the powerhouse, directing the tailrace
flows to meet the stream at approximately 45 degrees, is shown in
Figure 6-10. It should also be noted that the location of impulse-type
turbines above the tailrace water surface effectively precludes any
fish from entering the generating units.
The small Pelton-type impulse turbines described above were considered
to be below their optimum range at two Venetie sites because of the low
(35 feet) head available. Crossflow or Ossberger turbines which have a
relatively broad flow range were therefore utilized.
While generators may be either synchronous or induction type, most
sHes wi 11 requi re that synchronous generators be provi ded. The only
application for an induction generator is for those instances where the
power from the project is fed into a much larger system that has the
capability at the pOint of connection of providing the reactive power
necessary for the operation of the inductive mach; nee
The speed of a synchronous generator must be controlled in order to
ensure proper operation of electric motors and timing devices. A
governor will therefore be provided to control the flow of water to the
turbine in accordance with the load on the generator to maintain a
constant speed. An induction generator would be controlled by the
electrical system to which it was connected. and would have required
control devices only to protect the machin~ in case of malfunction. As
stated above, however, this less expensive type of generator could only·
be considered for the few proposed plants where connection to a large
system such as the Golden Valley system is possible.
6-27
r"""B
A
PLAN
SCALE : 1" -10' -0"
SECTION B - B
SCALE :. 1" -6' -0"
6-28'
PACKAGE
I' ,
JL
GENERATOR
IMPULSE
TURBINE
RUNNER
ONCRETE FLo01
i~~~Ir--SUBSTRUCTURE
SECTION Aj-A
SCALE : 1" -.,' -0"
REGIONAL INVENTORY & RECONNAISSANCE STUDY
SMALL HYDROPOWER PROJECTS
NORTHEAST ALASKA ~;":":"'-----II
POWERHOUSE
TYPICAL LAYOUT
FIGURE 8-10
DEPARTMENT OF THE ARMY
ALASKA OtSTRICT
CORPS OF ENGINEERS
u
6.4.6 Site Access
The impulse turbines selected as the generating units are packaged in a
container which can be readily transported to the sites during
wi ntertime on a 'sled. Remote control projects have been assumed for
the majority of the sites. Therefore, no permanent roads have been
assumed to be needed to powerhouse locations or other project features.
Access tracks to powerhouse and intake areas would be required as well
as to parts of the transmission lines where the conditions appear to be
particularly difficult.
6.4.7 Transmission
Transmission line capabilities under relatively small loading and short
distances have been evaluated to assess transmission capabilities up to
several megawatts at voltages of 7.2 kV, 14.4 kV, and 38 KY. The
economies involved do not warrant consideration of higher voltages for
the range of loads and distances considered. The voltages are intended
as an estimate only and a more detailed study of selected corona
effects, long distance stability, and thermal conditions as well as
other engineering considerations should be performed at the next stage
of study.
The transmission line capabilities for voltages and distances
considered are dependent primarily upon size and number of conductors,
voltage, distance, power factor, and, to a lesser degree, phase
spacing. This study assumed a minimum power factor of 0.9 and typical
phase spacing for 3-phase lines. The transmission line system was
selected to limit linepower losses to approximately 5 percent and
voltage drops at 7.75 to 10 percent. As shown on the load versus
distance curves in Figure 6-11, for a given line power loss and voltage
drop, th~ maximum product of the installed capacity in kilowatts and
the transmission distance in miles remains a constant. Specific
limiting kilowatt-miles for various transmission alternatives are
summarized in the Transmission Costs section.
In permafrost areas, single wire ground return systems are often not
feasible because of too low ground conductivity values. An alternative
single phase transmission concept was utilized, therefore, with a
second wire provided for the return current. Such systems are in
common usage in the Alaska Village Electric Cooperative Service areas
and other interior and northern utilities. Embedded wood poles would
be used because no major cost increases result from incorporation of a
double folded polyethelene film sleeve around the embedded part of the
pole which serves to break the bond to the active zone of permafrost
and thus prevent heave from occurri ng. .
A 14.4 kVor 38 kV four-wire transmission line was selected for larger
and/or more remote powerhouses. Selection of the minimum voltage in
this four-wire line alternate was subject to the same 5 percent loss
6-29
20~------~~---------+----------~
15r---------~--------_T----------r_
(Maximum MW -MILES = 167) -~
::I -10~--------~--~~---.~--~~--r---
5~--~----~---------.----------r--
14.4 kV (Maximum MW-MILES = 24)
6 10 20 30
DISTANCE (MILES)
266.8-26/7
1.75 % VOLTAGE DROP
5% LOSS
3 PHASE
REGIONAL INVENTORY & RECONNAISSANCE STUDY
SMALL HYDROPOWER PROJECTS
NORTHEAST ALASKA·
FIGURE 6-11
TRANSMISSION LINE ~OAD VS. DISTANCE FOR 5
LOSS
6-30
DEPARTMENT OF THE ARMY
ALASKA DISTRICT
CORPS OF ENGINEERS
u
u
co'nsideration. Long spans were used at a few sites, where transmission
1 i nes traversed expanses of water, such as the ri ver crossing at Arctic
Vi 11 age.
6.4.8 Operations and Maintenance
Little data are available on operations and maintenance of small
hYdroelectric projects. Most information that is available has been
compiled for operation of such projects as part of a larger system,
within ready reach of skilled personnel and maintenance facilities. An
attempt was made to arrive at conservative minimum 0 and M costs for
single Alaskan communities, not in the immediate viCinity of a large
population center.
The plant was assumed to be equipped with sufficient redundant
components to facilitate remote control with a minimum of plant outage
and provide sufficient time for maintenance personnel to arrive when
needed.
Remote control and intelligence transmission would be by micro-wave
carriers and the remote operating center would include a computer
facility, as well as all functions required to start, operate, monitor,
and shut down the plant.
Local recording of basic data and important functions would take place
at 'the plant and all equipment would be designed for fail safe
operation. Monthly inspection of the plant would be required for:
Cleaning of debris (intakes, sumps, filters, racks, etc.);
Replacement of recorder paper, relays, and adjustments;
Checking of condition of electrical equipment, batteries,
transformers, microwave equipment, motors, etc;
Comparison of data collected at the remote control center with
that recorded locally, for precise calibration;
Replacement of printed circuit cards as necessary; i.e.,
excitation, microwave, etc.
Prescheduled maintenance outages would occur once a year.
6.5 PROJECT COSTS
The reconnaissance level cost estimates were derived from the
preliminary project layouts by first estimating the cost for similar
work in the Pacific Northwest. The cost level for each item was based
on the construction cost indices of the Bureau of Reclamation for July
1981. Table 6-5 gives specific escalation factors applied to the
various cost components. Construction costs were totaled and
multiplied by a geographic factor developed for each community
6-31
TABLE 6-5
ALASKA SMALL HYDROPOWER PROJECTS
COST ESCALATION FACTORS
OSBR
Date of Cost Indexes Escalation Ky
1/ Original Original July Over Ori gi na
Item Source-Estimate Estimate 1981 Estimate Comments
l. DAMS
Concrete
Small New
Large New
Earth and
Rockfi11 1 4/79 2.37 3.00 1.27 Fig. 4-2
Spillway 1 4/79 2.47 3.21 1.30 Fig. 4-3
Sheetpile 2 7/80 2.83 3.08 1.09
2. PEN STOCKS 1 4/79 2.61 3.27 1. 25 Fig. 4-5
3. POWERHOUSE
AND EQUIPMENT
Turbi nes and
Generators
Pelton 2 7/80 2.95 3.29 1.12
Crossflow 3 7/78 2.38 3.29 1.38 Fi g. 5-7
Misc. Power
Plant and
Auxil iary
Equipment 1 4/79 2.37 2.95 1.24 Fig. B-8
Powerhouse
Structure
Pel ton New
Crossflow 3 7/78 2.28 3.03 1.33 Fig. 5-20
Excavation 3 7/78 2.33 3.14 1.35 Fig. 5-21
Val ves and
Bifur-
cations 1 4/79 2.61 3.27 1.25 Fig. 4-6
4. Swi tc I1Y a rd
(E1 ectri ca 1
and Ci vi 1) 1 4/79 2.37 3.08 1.32 Fig. B-9
or
Fig. 4-17
5. Access 2 7/80 3.16 3.32 1.05
6. Trans-
mission New
7. Mobili-
zation New
1.1 Sources: 1. EPRI (1981). .
2. Ebasco (1980). (Note Alaska cost factors were taken out to be
consistent with geographic factor applied to totals.)
U
3. USBR (fonnerly WPRS) (1980). ----------------------------------------------~
6-32
u
reflecting the particular conditions in that part of Alaska, including
higher labor and transportation costs, mobilization and demobilization,
and other factors related to remoteness and adverse climate. These
factors are presented in Secti on 6.5.8.
Contingencies of 25 percent and engineering and owner administration of
15 percent were then added to give the Total Construction Cost.
Interest During Construction (IDC) was estimated by assuming a 2.5-year
construction schedule and using an interest rate of 7-5/8 percent, as
defined in the scope of work for this study. The IDC factor was
computed following the uniform annual cost ar.proach, as recommended by
the USCOE IIHydropower Cost Estimati ng Manual' (1979). The IDC factor
was then added to the Total Construction Cost to give the Total Project
Cost, which is provided on the Cost Summary sheet for each project.
Costs not estimated and hence covered by the contingency item are land,
diversion and care of water during construction, reservoir,
relocations, and environmental controls and mitigation.
6.5.1 Dams
As discussed in Section 6.4.2, concrete gravity dams, with a central
ungated ogee section, were used at all Northeast Region sites. Costs
were based on quantity takeoff from the typical drawing (see Fig. 6-9).
The co nc rete co st s uti 1 i zed a bas i c conc rete cost of $250 per cubi c
yard. The cost of constructing the spillway bucket was estimated at
$375 per cubic yard. The intake structure was estimated at $500 per
cubic yard since it includes considerable framework. Val ves and
grating added an additional $10,000. Excavation, foundation treatment,
and backfi 11 were estimated as 10 percent of the total concrete costs.
The concrete volumes were estimated separately for each of the primary
geometric solids apparent in Figure 6-9. The side slopes were
determined from Abney level readings taken in the field, and estimated
from the USGS maps for unvisited sites. The spillway volumes were
calculated by integrating the area under the ogee curve and additional
allowance was made for the spillway bucket and walls. Intake structure
costs were estimated based on penstock diameter and the height of the
concrete ogee section which directly governs the height of the intake.
6.5.2 Penstocks
Penstock costs were estimated based on the diameter and length, and
utilized Figure 4-5 from the 1981 EPRI study "Simplified Methodology
for Economic Screening of Potential Low-Head Capacity Hydroelectric
Sites". Included in the costs are the supply and erection of the
penstock with supports, concrete footings, minimal excavation, and
surface treatment. Special foundation treatments, thrust blocks, and
bifurcations are not included.
Since EPRI Figure 4-5 is based on low pressure penstocks, a high head
adjustment factor (Fn) was developed.
6-33
Fn equals 1 for net heads less than or equal to those calculated
based on the USBR formula and adjusted for surge. When net heads
exceed this, a cost adjustment was made to cover the extra thickness
required for the internal pressure design. Installed penstocks average
approximately S2.25 per pound of steel pipe based on the EPRI Figure
escalated to July 1981 costs. Ma·nufacturers quoted the cost of extra
steel at S.45 per pound. The extra shipping weight and increased
handling costs would raise this increase in cost to S.75 per pound or
to approximately 1/3 of the cost per unit given by EPRI Figure 4-5.
Since thickness varies linearly with head, the following formula was
adopted for the high pressure head adjustment:
Fn = 1 + (H n -Hmi~Hmin
where
Hn is the net head, and
~io is the equvalent internal pressure deSign head for the USBR
mlnlmum handling thickness.
TM s factor was multiplied by the cost per foot, times the length of
the high head penstock. .
An analysis of penstock parameters showed that freight, supports, and
installation accounted for approximately 50 percent of the total cost.
The product cost of the finished penstock plant was not escalated by
the geographic factor. Therefore, weighted value of only 75 percent of
the total penstock cost was entered on the cost data summary table for
each site.
6.5.3 Powerhouse and EqUipment
6.5.3.1 Turbines and Generators
Pelton type impulse turbines were selected for all projects except for
heads below 130 feet. Estimates of the cost of powerplant generating
equi pment (i ncl udi ng turbi ne, governor, generator, and control
equipment) were obtained from manufacturers.
Costs for a skid-mounted, fully weather proofed, steel panel enclosed
turbine generator package are given by the curve in Figure 6-12.
For heads below 130 feet crossflow units were assumed. The eqUipment
costs were escalated from the USBR 1978 reference curve specified in
Table 6-5.
6.5.3.2 Miscellaneous Power Plant and Auxiliary Equipment
For both Pelton and Crossflow units, the costs of miscellaneous
equipment were obtained from EPRI Figure B-8 which also details the
equipment included in this item.
6-34
c
700
600
500
I ..
;:: 400 • ~. ...
en 300 I
(J.I
(J'I
200
) , ~.
.r 100
o V
o
l
I v
I ~ f"
V I;'
lL v
I ~ V
..-V
) v I I
/ I
I
.. V~
.IV-
~
I I
500 1000 UNIT SIZE IQi lSOO
IMPULSE TURBO-GENERATORS
COST-fOI fACTORY-COMPLETE INTEGRATED UNITI
NOTE: COST BASE FOR CURVE IS JULY 1980.
ESCALATE BY A FACTOR OF 1.12 TO
JULY 1981.
c
v '/
-'
V I
I
2000 2500
REGIONAL INVENTORY & RECONNAISSMU STllJY
SMAll HYDROPOWER PROJECTS
NORTHEAST ALASKA
FIGURE 8-II!
TURS INE GEtlERATOR COSTS
Note: Includes Cost of Turbine Generator,
Valves, and Switchgear
, DEPARTMENT OF THE ARMY
ALASKA DISTRICT CORPS OF ENGINEERS
6.5.3.3 Powerhouse Structure
The Pelton unit skid-mounted packages would be placed on a concrete
based slab, assumed to be seated on bedrock. Cost of this concrete
substructure, including erection of skid, was estimated at $350 per
cubic yard for structural concrete and $250 for mass concrete, with
rock excavation at $15 and common at $3 per cubic yard.
For the crossflow units the cost of the powerhouse and the attendant
excavation was based on USBR 1978 cost curves. In both cases the cost
of excavation for the transition into the existing stream downstream of
the drafttube was included. No specific tailrace was required,
however, because the flow in the stream would never be increased above
the present flow.
6.5.3.4 Valves and Bifurcations
Costs of the penstoGk bifurcation, and the turbine intake valve were
obtained from EPRI Figure 4-9, except for the crossflow unit intake
valve which had alreaqy been included as part of the turbine cost.
6. 5. 4 Swi tc hY a rd
Swi tchYard costs with generator vol tage ci rcuit breakers were estimated
from EPRI Figure 4-17 or B-9. The figure yields both civil and
equipment costs which were totaled and entered as a single l'ine item on
the cost summary sheets.
6.5.5 Access
Access tracks were estimated to be $15,000 per mile. Typically, they
extend from the powerhouse to the intake, structure. It was assumed
that construction access to nearby communities would generally follow
transmission line routes. Nonnal access to transmission lines was
included in the transmission line cost and the extra cost of detouring
from the transmission route was not included.
6.5.6 Transmission
Transmission line costs were developed from several sources, including
previous Ebasco reconnaissance studies, discussions with Alaska utility
engineers, and cost manuals by the Corps of Engineers, EPRI and USBR.·
Conductors were sized to limit line losses to 5 percent. Losses are
related to the product of installed capacity (kw) and distance
transmitted (miles). Because cost variation between 7.2 kV and 14.4 kV
systems was not significant, all costs were based on 14.4 kV and 38 kV
systems. This also provides the added advantage of reduced line losses
and potential for expansion for the smaller systems. Listed below are
the ranges in kW-miles over which the various transmission systems are
applicable. These costs include wood poles, conductor line hardware
and insulators, surveying, and clearing. No allowance has been made
for land and right-of-way acquisition nor for special access roads.
6-36
u
Volta 1e High Low Cost Base
(kV Phase (MW mi les) (MW miles) " ~er mile) Cost Comments
38 3 167 24 50,000 0 Conventi ona 1
14.4 3 24 12 40,000 0 Conventi ona 1
14.4 1 12 0 25,000 0 Conventional
14.4 1 15 0 20,000 25,000 Single Wire
Ground Return
14.4 1 12 0 30,000 5,000 Conventional,
Long Span
14.4 3 24 12 60,000 10,000 Long Span
The above costs per mile were subsequently mul tipl iedby the terrai n
factors listed below.
Terrain Terrai n Factor
Flat 1.0
Roll ing 1.25
Mountainous 1.50
Swampy 1.50
As discussed in Section 6.4.6, because of the limitations of the SWGR
system in permafrost areas, a conventional, IItwo-wi re ll simple phase
line was assumed wherever either of these single phase systems would
have been technically and economically feasible.
6.5.7 Mobilization
Mobilization costs in Alaska are typically a sizable ,percentage of
direct costs. In recent bids on nydro projects in Southeast Alaska,
mobilization costs ranged from 4 to 20 percent of the direct cost, the
successful bidder having allocated the 20 percent figure. From
investigation of recent estimates and construction bids for Alaska, a
figure of 10 percent of the direct costs has been adopted ,for
mobilization and demobilization at readily access'ible sites, increasing
to 20 percent when an extensive construction camp is, required at a
remote site. Minimum costs of ~100,OOO for the former and ~200,OOO for
'the latter case have been assumed.
6.5.8 Geographic Cost Adjustment
The Northeast region of Alaska shows considerable variation in
construction costs. For preliminary screening studies, two generalized
Qeographic cost mul tipl iers were used. A basic factor of 1.1 was used
ln the lower Northeast, and 1.2 in the upper Northeast region. These
factors were applied to costs that had already been escalated to
southern Alaska costs from the lower 48 states' costs, generally by a
factor of 2.
6-37
A more rigorous approach was applied in the more detailed studies, in
which the geographic cost adjustment was calculated for each community
studied.' The Department of the AnmY recommends 1.7 as an empirical
factor for converti ng Washi ngton State costs to Anchorage costs. The l...,)
Alaska Department of Transportation and Public 'Facilities publishes
location indices across the State of Alaska with Anchorage as a base
equal to 1.0. These indices were combined to convert the lower 48
states' construction costs to those of the communities selected for
detailed Phase II studies. The geographic cost adjustment factors are·
shown in Table 6-6.
6.5.9 Operations and Maintenance
With the realization that the degree of sophistication affordable will
vary considerably from 0.05 MW to 3 MW, the following are estimated to
be reasonable expenditures of mandays required for maintenance as an
average in a reasonably accessible fair-size community such as Tok:
Monthly routine checks and minor repairs
Annual inspection and major overhaul
Peripheral facilities, communications,
contro 1 s, etc.
Contigency
Total
Man-days/Year
35
45
10
15
TO"5"
For more remote, isolated communities, the following minmum yearly
costs have been estimated:
-Electrical operator
-Monthly transportation
-Annual maintenance (additional imported
personnel)
-Outside repairs
Insurance and general costs
Total
$30,000
5,000
15,000
10,000
10,000 ,
$70,000
For larger plants the only collated data have been presented by EPRI
(1981). Although it seems reasonable to expect that 0 and M costs
would be proportional to installed plant capacity rather than to total
project costs, the latter is the only relationship published.
Accordingly, a value of 1.2 percent. of the total project costs has been
assumed for the intertied plants, and increased to 1.5 percent for the
isolated communities.
6.6 ECONOMIC ANALYSIS
The economic analysis procedures used for the more detailed
investigations were essentially identical to those used in the
preliminary screening, as discussed in Section 5.2.3 and Appendix C.
One refinement was built into the detailed studies, however. The
benefit-cost analysis was modified to reflect a 2-1/2 year lead time
6-38
u
TABLE 6-6
ALASKA GEOGRAPHIC COST ADJUSTMENT FACTORs!/
Dot Lake 2.3
Tanacross-Tok 2.3
Arctic Vi 11 age 2/ ·3.6
Eagl~/ 2.6
Veneti~ 3.2
Big Delta-Delta Junction 2.2
1/ Washington State costs escalated to Anchorage costs based on the
Department of the Amty I s IIEmpi r1cal cost Estimtes for Mi litary
Construction and Cost Adjustment Factors". The applicable factor
is 1.7. Cost adjustments between Anchorage and other Alaskan
communities were further escalated based on actual locations or a
reasonable proximity to actual locations as indicated on the State
of Alaska Department of Transportation and Public Facilities
"Location indices of 08/06/81".
2/ Estimates based on similar proximity to population centers and
transportatf on routes.
6-39
for constructi on of the t\Ydroelectric project. Construction is assumed
to begin July 1, 1981 and benefits from the project will begin to
accrue when power is produced on January 1, 1984. In order to maintain U·
consistency in comparing the economic benefits of t\Ydroelectric and
diesel generation, benefit-cost ratios were calculated for the period
1984 through 2030.
6.7 ENVIRONMENTAL CONSTRAINTS
Major potential environmental constraints to hydroelectric project
development were identified principally through discussions with
community leaders during the field reconnaissance. The major
en vi ronmenta 1 concerns were ei ther 1 and ownershi p status or the use of
streams by migrating or spawning salmon. These concerns were included
in the selection of sites for detailed study, and in several cases,
were pivotal in selection of one site over another. Environmental
factors, where important, are highlighted in the individual community/
site descriptions and data sheets provided in Part II.
Reference was also made to the National Register of Historic Places
(U.S. Department of the Interior, 1981); no historic or archaeological
sites listed appear to be located in proximity of the potential
t\Ydroelectric sites identified in this study.
6-40
u
7.0 LIST OF REFERENCES
Alaska Dept. of Transportation and Public Facilities. 1981. Location
indices of 8/06/81. Personal correspondence.
Alaska Energy Association. Undated. New Chenega alternative energy
plan. Prepared for the New Chenega I.R.A. Village Council,
Anchorage, Alaska.
Alaska Power Administration. 1979. Small hYdroelectric inventory of
villages served by Alaska Village Electric Cooperative. U.S.
Department of Energy. Anchorage.
Alaska Power Authority. 1980. Reconnaissance study of the Kisaralik
River hYdroelectric power potential and alternate electric energy
resources in the Bethel area.
Alonso, W. and E. Rust. 1976. The evolving pattern of village
Alaska. Joint Federal-State Land Use Planning Commission for
Alaska. Anchorage.
Balding, G.O. 1976. Water availability quality, and use in Alaska.
U.S. Geol. Survey Open File Rept. 76-513.
CH2M Hill. 1978. Review of southcentral Alaska hYdropower potential-
Fairbanks area. U.S. Anny Corps of Engineers~ Alaska District.
CH2M Hill. 1978. Review of southcentral Alaska hYdropower potential -
Anchorage area. U.S. Anny Corps of Engineers, Alaska District.
CH2M Hill. 1979. Regional invento~ and reconnaissance study for
small hYdropower sites in southeast Alaska. U.S. Army Corps of
Engineers, Alaska District.
CH2M Hill. 1980. Reconnaissance assessment of energy alternatives.
Chilkat River basin region. Prepared for the State of Alaska,
Alaska Power Authority. Anchorage.
Creagher, W.P. and J.D. Justin. 1950. Hydroelectric handbook. John
Wi 1 ey and Sons, Inc., New York.
Ebasco Services Incorporated. 1980. Regional inventory and
reconnaissance study for small hYdropower projects -Aleutian
Islands, Alaska Peninsula, Kodiak Island, Alaska. U.S. Army Corps
of Engineers, Alaska District.
Ebasco Services Incorporated. 1981. Terror Lake Hydro Project
independent feasibility-level cost estimate. Alaska Power
Authority, Ancho~age.
Federal Energy Regulato~ Commission. 1981. Alaska river basins
pl anni ng status report. FERC-0068.
Federal Power Commission. 1976. The 1976 Alaska power survey, vol. 1.
7-1
Galllet, Harold H., Joe A. Marks, and Dan Renshaw. 1980. Wood to
gas to power - a feasibility report on conversion of village power
generation and heati ng to f,uel s other than oil. Vol s. I, II, and V
III. Prepared for the Alaska Village Electric Cooperative.
Goldsmith, Scott, and Lee Huskey. 1980. Electric power consumption
for the Railbelt: a projection of requirements. Prepared jointly
for State of Alaska House Power Alternatives Study Committee and
Alaska Power Authority by the Institute of Social and Economic
Research. Anchorage, Alaska. (June), Technical Appendices (t~ay).
Golze, Alfred R. (ed.). 1977. Handbook of dam engineering. Van
Nostrand Reinhold Co., New York.
Gordon, J.L. and A.C. Penman. 1979. Quick estimating techniques for
small hYdro potential. Water Power and Dam Construction (Oct.)
Holden and Associates, Fryer Pressley Elliot Associates, and Jack West
Associates. 1981. Reconnaissance study of energy requirements and
alternatives for Kaltag, Savoonga, White Mountain and Elim. Draft
report, prepared for the Alaska Power Authority.
Institute of Social and Economic Research, University of Alaska. 1976.
Electric power in Alaska, 1976-1995. Prepared for the House
Finance Committee, Second Session, Ninth Legislature State of
Alaska. Prepared by ISER in cooperation with Kent Miller, Robert
Retherford Associates, Stefano-Mespl~ and Associates, and National
Economic Research Associates. Anchorage.
Kilday, G.D. 1974. Mean monthly and annual precipitation -Alaska.
NOAA Tech. Memo. NWS AR-10.
Lamke R.D. 1979. Flood characteristics of Alaskan streams. U.S.
Geol. Survey Water Res. Invest. 78-129.
Linsley, R.K. and J.B. Franzini. 1964. Water resources engineering.
McGraw-Hill Book Co., Inc.
linsley, R.K. et al. 1975. Hydrology for engineers. 2nd ed. McGraw-
Hill, Inc.
Ott Water Engi neers, Inc.
reconnaissance study.
01 strict.
1981. Northwest Alaska hYdropower
U.S. A~ Corps of Engineers, Alaska
R.W. Retherford Associates. 1980. Reconnaissance study of the Lake
Elva and o~her hYdroelectric power potentials in the Dillingham
area. Al aska Power Authori ty t Anchorage.
R.W. Retherford Associates. 1981. Draft report: reconaissance study
of energy resource alternatives for thirteen western Alaska
villages. Prepared for State of Alaska, Alaska Power Authori·ty.
Anchorage, Alaska.
7-2
u
Rutledge, G. et ale 1980. Alaska regional energy resources planning
project. Vol. II -~droelectric development. Alaska Div. of
Energy and Power Development.
Scott, Kevin M. 1978. Effects of permafrost on stream channel
behavior in arctic Alaska. U.S. Geol. Survey. Prof. Paper 1068.
U.S. Govt. Prtg. Off., Washington, D.C.
Tudor Engineering Company. 1981. Simplified methodology for economic
screening of potential low-head small-capacity hydroelectric
sites. Electric Power Research Inst. (EPRI) EM-1679.
Tudor Engineering Company. 1980. Reconnaissance evaluation of small,
low-head hYdroelectric installations. U.S. Dept. of the Interior,
Water and Power Resources Service.
U.S. Anmy Corps of Engineers. 1979. Feasibility studies for small
scale hYdropower additions. NTIS.
U.S. AnI\Y Corps of Engineers, Alaska District. Undated. Electrical
power for Valdez and the Copper River Basin. Interim Feasibility
Report and Fi nal Envi ronmental Impact Statement. "
U.S. Army Corps of Engineers, Alaska District. 1981. Small-scale
hYdropower reconnaissance stu~, Southwest Alaska.
U.S. Army Corps of Engineers, Portland District. 1979. ~dropower
cost estimating manual.
U.S. Department of Agriculture, Soil Conservation Service. 1979.
Exploratory soil survey of Alaska.
U.S. Department of the Army. 1978. Construction empirical cost
estimates for military construction and cost adjustment factors.
Army Regul ati on 415-17. ' .
U.S. Department of Energy, Alaska Power Adminstration. 1976. Inventory
of potential hYdroelectric sites in Alaska.
U.S. Department of Energy, Alaska Power Administration. 1979. Small
hYdroelectric inventory of villages served by Alaska Village
Electric Corporation.
U.S. Department of Energy, Alaska Power Administration. 1981.
Prel imi na ry eval uati on of hYdropower alternatives for Chiti na,
Al aska.
U.S. Department of Interior, Bureau of Reclamation. 1974. Design
of small dams. U.S. Govt. Prtg. Off., Washington, D.C.
7-3
u.s. Department of Interior, Heritage Conservation and Recreation
Service. 1981. National Register of Historic Places; Annual
Listing of Historic Properties. Federal Register 46(22):
10623-10624.
u.s. Environmental Data Service.
climatological data, Alaska.
Admi ni stration.
1949-1979 •. Annual sUl1IIIaries-
National Oceanic and Atmospheric
7-4
PART II -COMMUNITY AND SITE DATA
u
u
INTRODUCTION
Part II of this report provides information specific to each community
studied. The communities· are grouped as follows: .
1) The first four sections (numbered 1.0 through 4.0) contain
information for the Northeast Region communities which were visited
in the field. A brief text is included to provide insights gained
during the field visits. Summary data for the detailed studies are
i ncl uded.
2) The next section (Big Delta-Delta Junction) contains both
preliminary screening and detailed study data, but no summary text
because these communities were not visited in the field.
3) The remaining communities (Kaktovik/Barter Island through Wiseman)
were not studied beyond the preliminary screening, and therefore
those sections contai n only prelimi nary screeni ng results.
Listed below are explanations of the terms and abbreviations used
on the computer output contained in Part II. .
Term/Abbreviation
Nondi scounted/t~ondi sc
Di scounted/Di sc
Operati on and
Maintenance/O and M
Explanation
The nondiscounted cost of power at a given
point in time is equal to the cost of
delivery 1n 1981 dollars.
The di sc·ounted cost of power at a gi ven
point in time is equal to its present value
in 1981 doll ars calcul ated at a di scount
rate of 7-5/8 percent per year.
Operating costs were assumed to vary with
plant size while maintenance costs were
assumed to be fixed at 6 percent of the
installed cost of the plant.
u
1.0 ARCTIC VILLAGE
1.1 COMMUNITY DESCRIPTION
Arctic Village is a community 10cated'125 miles north of the Arctic
Circle on the East Fork of the Chandalar River. The village is
populated by 132 persons distributed among 28 households.
Electricity is supplied to the village school by 2 -35 kW and 1 -90
kW diesel generators and is operated and maintained by the BIA. The 90
kW machi ne is operated from October to Ma rc h when the power needs are
greatest. Last year 2 -100 kW diesel generators were purchased by the
BIA for the village and power lines were installed. In addition to the
28 residences, power is supplied to the village council hall, public
health service building, store, and the airport runway. Public
buildings as well as residences use wood for space heating.
The cost of diesel fuel ranges from ~3.00 -~4.00 per gallon, depending
on which air charter transports the fuel. Due to the inefficient
handling of the fuel such as waste from tank and line leakages, the
cost of fuel does not fully reflect the real cost of power.
Residences are not yet metered but plans are underway to install meters
by the spring of 1982. Every household pays a flat rate of $100/month,
or $1200/year. This rate is set arbitrarily, however, since the Native
Village of Venetie Tribal Government pays for the capital, operation,
and maintenance of the generators (approximately $1.00/kWh) and monies
from the residential power bills are used to defray the costs incurred
by the tribe. When the meters are installed and full costs of
providing power are passed on to the consumer, electricity bills are
expected to increase significantly, making the cost of power
prohibitive to most residents. The high power rates may necessitate
the tribal council to continue subsidizing the power system. The types
of household appliances used include primarily small applicances
although about one-half of the households have refrigerators, freezers,
and power tools. If the cost of power was to be reduced through a
f1ydropower project, some electrical appliances would be acquired but
total demand would not increase significantly.
The highest priority of Arctic Village is to create employment for the
residents. The goal is to seek projects that would create long term
benefits for individuals and the tribal council. Presently an airport
development project employs 7 people on a part-time basis. There are
no permanent stable sources of income available locally.
1.2 SITE SELECTION
•
Potential project dam sites on both Paddle Mountain and Rock Head West
Creeks were visited and measurements taken of the flows and of the
creek cross sections. Both of these sites are located due west of
Arctic Village, across the Chanda1ar River in very similar terrain on
1-1
..
south facing slopes of the Brooks Range. Shale bedrock slabs are
exposed at both dam sites, although limited stripping would still be
required. Permafrost is believed to be omnipresent. Both creeks were . ~
also starting to freeze over at the time of the field visit (August 19,
1981), but generally maintain winter flow.
There appeared to be little basic difference between these two adjacent
creek basins, and the unit energy costs were also closely similar. .
Rock Head West Creek is proposed for initial development because of the
potentially greater amount of ~dro energy which could be generated.
1-2
TOPOGRAPHY FROM U. S. G. S.-ARCTIC-,
ALASKA, 1:250pOO
LEGEND
• DAM SITE
• POWERHOUSE o SITE NO.
-----PENSTOCK
---TRANSMISSION LINE
-WATERSHED
b o 5
t-=I E3
SCALE I N MILES
REGIONAL INVENTORY a RECONNAISSANCE sruov
SMALL HYDROPOWER PROJECTS
NORTHEAST ALASKA
HYDROPOWER SITES IDENTIFIED
IN PRELIMINARY SCREENING
ARCTIC VILLAGE
DEPARTMENT OF THE ARMV
ALASKA DISTRICT CORPS OF ENGINEERS
~
NE/SC ALASKA SMALL HYDRO RECONNAI SANCE STUDY
PLANT FACTOR PROGRAM
COMMUNITY: ARCTIC VILLAGE
SI TE NUMBER: 3
NET HEAD (fT): 260.
DESIGN CAPACITY (KW): 141.
MINIMUM OPERATING fLOW (1 UNIT) (CfS): 0.87
LOAD SHAPE fACTORS: 0.50 0.75 1.60 2.00
HOUR FACTORS: 16.06 15.00 13.00 3.00
MONTH (HDAYS/MO.) AVERAGE POTENTIAL PERCENT ENERGY USABLE
MONTHLY HYDROELECTRIC OF AVERAGE DEMAND HYDRO
FLOW ENERGY ANNUAL ENERGY ENERGY
(CFS) GENERATION (KWH) (KWH)
JANUARY 0.00 o. 10.00 88260. o.
FEBRUARY 0.00 o. 9.50 83847. O.
MARCH 0.00 O. 9.00 79434. o.
APRIL 0.00 O. 9.00 79434. o.
MAY 20.90 104904. 8.00 70608. 62707.
JUNE 25.80 101520. 5.50 48543. 48543.
JULY 6.62 86972. 5.50 48543. 47279.
AUGUST 7.97 104708. 6.00 52956. 52806.
SEPTEMBER 5.71 72597. 8.00 70608. 45207.
OCTOBER 0.71 o. 9.00 79434. O.
NOVEMBER 0.06 O. 10.00 88260. O.
DECEMBER 0.00 O. 10.50 92673. O.
TOTAL 470701. 882600. 256542.
PLANT FACTOR(1997): 0.21
PLANT FACTOR(LIFE CYCLE): 0.21
U
HYDROPOWER COST DATA -DETAILED RECONNAISSANCE INVESTIGATIONS
Community:
Site:
Stream:
Arcti c Vi 11 age
3
Rock Head West Creek
ITEM
1. Dam (including intake and spillway)
2. Penstock
3. Powerhouse and Equipment
-Turbines and ,Generators
-Misc. Mechanical and Electrical
-Structure
-Valves and Bifurcations
4. Switchyard
5. Access
6. Transmission
TOTAL DIRECT CONSTRUCTION COSTS
7. Construction Facilities and Equipment.
Camp, Mobilization, and Demobilization
TOTAL INDIRECT CONSTRUCTION COSTS AT 20 PERCENT
SUBTOTAL
Geographic Factor =
SUBTOTAL
Conti ngency at 25 percent
SUBTOTAL
Engineering and Administration at 15 percent
TOTAL CONSTRUCTION COST
Interest During Construction at 9.5 percent
TOTAL PROJECT COST
Cost per kW Installed Capacity
ANNUAL COSTS
Annuity at 7-5/8 percent (AlP = 0.07823)
Operations and Maintenance Cost at 1.5 percent
TOTAL ANNUAL COSTS
Cost per kWh
Benefit-Cost Ratio:
COST
$ 137,000
$ 239,000
$ 112,000
$ 170.000
$ 30.000
$ 19.000
$ 167.000
$ 15.000
$ 168.000
$ 1,057,000
$ 211.000
$ 1.268.000
3.6
$ 4,566.000
$ 1,142,000
$ 5,708,000
$ 856,000
$ 6,564,000
$ 624,000
$ 7,188,000
$ 50,980
$ 562,300
$ 107,800
$ 670,100
$ 2.57
0.27
c..;
u
REGIONAL INVENTORY & RECONNAISANCE STUDY -SMALL HYDROPOWl:R PROJECTS
ALASKA DISTRICT -CORPS OF ENGINEERS
YE{~R
19:;::4
1·~J:31:.,
1'~:::7
11~/:~:::::
11~i:::';i
1.990
1991
11~J'"iJ:2
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1995
199{-
1997
1999
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::01>1
2002
200:3
2004
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2009
::Wl0
2011
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2014
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2020
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DETAILED RECONNAISSANCE INVESTIGATIONS
COST OF HYDROPOWER -BENEFIT COST RATIO
ARCTIC VILLAI3E
::::ITE NO. ~:
KWH/YEAR
1 ':"7515.
2 ():::: 1 :32 II
2()875::::.
:;~ 1 ::~: I~ 7 S"' II
2:341:::: 1.
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107800.
107800.
~07800.
107aOO.
107:::00.
107::::00.
1(17:300.
107::::00.
107800.
107::::00.
107::::00.
107::::00.
107::::00.
107800.
107::::00.
107:300.
107800.
107::::00.
107::::00.
1.07:::00.
107800.
107:300.
107:300.
107::::00.
107800.
107::::(10.
107:::00.
565983. 107800.
565983. 107800.
5659:33. 107800.
565983. 10780u.
565983. 107800.
565983. 107800.
TOTAL$
6 7::::"'~~:::': II
/::..7378:;: •
67:~:78::::.
67378:=:.
l:,'7::::'783 II
67:37:~::~: •
&'.7~17:3:3 II
(: ... , :~~: 7:3:3 II
67:3783.
/:.·737:;:::::: II
6737:33.
67::::-78:3.
l",,'7:~:7E::::: JI
(:.7 :::: 7 ::: :::: II
(:.7:37:::::::: II
67378~:.
6 7:37:=:~: II
67:37:=::3.
67:378:3.
67::::7:3:~:.
(:.7:3"1:::3 "
67:3"1::::::: •
1:.·7:~:7:3:~:1I
67::::78:3.
67:~:78:3.
67:378:3.
1:.,7::::7::::3.
/.:.7:37::::::: •
$n:::WH $/KWH
NONDISC
::::.411
3. 149
:3.074
:~: II t)t):2
2.G77
2.77:3
:~~ II 728
~'2. /.:. ''i' :3
::;:: .. 1:..5:~
:;~. ~")·2l ....
2. 5'~'~7
2. 5t.:, 7
2. ~541
2.511
2.497
2.471
;:.460
2.450
2.440
~~ II 4::::()
:2.420
~;:~. 4()::~
2. ::::~,t,
2. :3:::4
2.:377
2. :369
2 II :3,S2
211 :~:55
2 II :34':;
2.34(:.
2. :341
2 a :3:~:t.
2. :::::34
[11::::(:
~:. 077
1.70::::
f. !:i50
1.4(17
1.1.6'~i
:1..067
0.975
O. ::;::94
() .. :::::::'::()
o. 75:~:
() It /:. •• ~) :;2
o. !'.:i40
O. 49'~'
0.461
O.4:;'/:'
0.:394
o. :3(:.4
0.3::n
()II ::::12
t) II :2:?a:::
0.267
o. :;'::47
() II 2~':::
fl,,211
0.195
0.1::::1
() II 1 (:.::::
()a 155
o. 144
(I. 1 :~:4
0.124
C).115
0.107
0.099
0.092
678783. 2.332 0.085
673783. 2.330 0.079
6737::::3. 2.328 0.074
673783. 2.:326 0.068
67378:3. 2.324 0.063
673783. 2.322 0.059
AVERAGE COST :2.56:::: o. (-,]'4
BENEFIT-COST RATIO (5% FUEL COST ESCALATION): 0.27
Arctic Vi ll aqe, Alaska
Aeri a 1 Vi ew of Arct i c Vi 11 age
Damsite-Rock Head West Creek
(foreground)
u
2.0 VENETIE
2.1 COMMUNITY DESCRIPTION
Venetie is a sUbsistence community located 50 miles northwest of Fort
Yukon at the edge of the Yukon Fl atsOti the Chanda1ar Ri ver. Due to
ties between Arctic Village and Venetie. people move periodically from
one village to the other. Venetie is also experiencing' a return of
fonner res'idents from Fairbanks. Venetie has a population of 160 and
approximately 40 households. '
Venetie has 250 kW of installed capacity (2 -100 kW and 1 -50 kW) to
serve the community. TheBIA maintains a smaller generator to provide
electricity to the schools. The generators are not ver,y reliable and
are serviced from Fairbanks when they break down. All residences pay a
flat rate of $30/month. which is used to defray the real cost of power
estimated at $1.00/kWh. Similar to Arctic Village. the tribal council
pays for the capital. operation. and maintenance of the generators.
When meters are installed. the village plans to charge customers based
on the amount of electricity consumed.
The average household uses electricity for lights. toasters.
coffeepots. electric frying pans, washers, refrigerators, some
freezers, and televisions. Other buildings in the community that use
electricity include the community hall. two schools, store. church, and
post office. Even if the price of electricity was reduced, not many
more appliances are expected to be acquired. Wood is used to heat
homes and propane and blazo are used for cooking and hot water.
Venetie acquired 21 HUD houses 2 years ago and a few individuals are
planning to build new homes.
Venetie has few sources of employment; approximately 2 full-time and 3
part-time jobs exist. Temporar,y employment of 17 persons was provided
recently by an oil company in connection with seismic exploration. The
construction of a clinic and community hall are two projects that will
provide jobs temporarily. Venetie has a long term interest in
developing community based agriculture as a means to strengthen the
economic base. Such a project is contingent upon the availability of
inexpensive power to run the pumps for irrigation.
2.2 SITE SELECTION
All the final sites considered were located on Kocacho Creek. Field
measurements duri ng the vi sit gave much greater flows in the west
branch. as opposed to the observations made by USCOE on 10/8/79 when
only this ann had been dry. Local residents stated that wintertime
flow in Kocacho Creek was maintained under the ice. The optimum site
for a run-of-the-river hYdro development appeared to be located
approximately 1/8 of a mile downstream of the confl uence. where a low
spur on the right abutment approaches the creek. The eXisting 50 foot
2-1
wide creek channel is too low to contain a structuresufffciently high
to allow both for a three foot thick ice sheet and for bed material
deposition. Any intake structure will therefore have to extend for
several hundred feet onto the flood plain on both sides of the creek.
The very gentle slopes in all directions, combined with dense spruce
and shrub vegetation and the availability of only 200-foot contour maps
meant that a clearly preferable dam location could not be established
during the site visit, nor could the optimum-po.werhouse location along
the lightly meandering creek course be determined. Access to within a
couple of miles of the site would follow an existing sled trail, as
would the transmission line.
2-2 u
u
NOTE: TOPOGRAPHY FROM US. G. S. -CHRISTIAN
ALASKA, 1:250,000
LEGEND
• DAM SITE
• POWERHOUSE o SITE NO.
- -_. -PENSTOCK
- - -TRANSMISSION LINE
--WATERSHED
5 0 5
SCALE I N MILES
REGIONAL INVENTORY a RECCNNAISSANCE STUDt
SMALL HYDROPOWER PROJECTS
NORTHEAST ALASKA
HYDROPOWER SITES IDENTIFIED
IN PRELIMINARY SCREENING
VENETIE
DEPARTMENT OF THE ARMV
ALASKA DISTRICT CORPS OF ENGINEERS
u
~dro~ower Potential
Installed
Capacity
S1 te No. (kW)
2 196
Demogra~hic Characteristics
1981 Population: 160
SUMM,ARY DATA SHEET
DETAILED INVESTIGATIONS
VENETIE, ALASKA
Cost of
Installed Al ternati ve
Cost Power.!/
(SI000) (mill s/kWh)
20.380 613 •
1981 Number of Households: 45
Economic Base
Subsi stence
Government
.!/ 5 Percent Fuel Escalation, Capital Cost Excluded.
Cost of
IiY d ropowe r Benefit/Cost
(mi 11 s/kWh) Ratio
3,450 0.18
See Appendix C (Table C-8) for example of method of computation of
cost of alternative power.
REGIONAL INVl:NTORY & RECONNAISANCE STUDY -SHALL HYDROPOv-1E R PROJECTS
ALASKA DISTRIC'r -COUPS OF' ENGINEERS
LOAD FORECAST -VENETIE
KILmvATT-IiOURS PER YEAR ANNUAL PEAK DEr·1AND-KW U
YSl\H Lm~ Ml::DIm1 HIGH LOW HEDIUM HIGH
1980 640000. 640000. 640000. 2.19. 219. 219.
19B1 666766. 666766. 666766. 228. 228. 228.
1982 693533. 693533. 693533. 238. 238. 238.
1983 720299. 720299. 720299. 247. 247. 247.
1984 747066. 747066. 747066. 256. 256. 256.
19B5 773832. 773832. 773832. 265. 265. 265.
1986 800598. 800598. 800598. 274. 274. 274.
1987 827365. 827365. 827365. 283. 283. 283.
1918 854131. 854]31. 854131. 293 • 293. 293.
. 19U9 880897. 880897. 880897. 302. 302. 302.
1990 907664. 907664. 907664. 311. 311. 311.
1991 930829. 983805. 1036781. 319. 337. 355.
1992 953994. 1059946. 1165899. 327. 363. 399.
1993 977159. 1136088. 1295016. 335. 389. 443.
1994 1000324. 1212229. 1424134. 343. 415. 488.
1995 1023488. 1288370. 1553251. 351. 441. 532.
1996 1046653. 1364511. 1682368. 358. 467. 576.
1997 1069818. 1440653. 1811486. 366. 493. 620.
1998 1092983. 1516794. 1940603. 374. 519. 665.
1999 1116148. 1592935. 2069720. 382. 546. 709.
2000 1139313. 1669076. 2198838. 390. 572. 753.
2001 1152727. 1752475. 2352223. 395. 600. 806.
2002 1166140. 1835875. 2505609. 399. 629. 858.
2003 1179554. 1919274. 2658994. 404. 657. 911.
2004 1192967. 2002673. 2812379. 409. 686. 963.
2005 1206381. 2086072 • 2965764. 413. 714. 1016.
2006 1219794. 2169472. 3119150. 418. 743. 1068.
2007 1233208. 2252871. 3272535. 422. 772. 1121.
200B 1246621. 2336270. 3425920. 427. 800. 1173 •
2009 1260035. 2419669. 3579305. 432. 829. 1226.
2010 1273448. 2503069. 3732690. 436. 857. 1278.
2011 1289693. 2539055. 3788416. 442. 870. 1297.
2012 1305939. 2575041. 3844142. 447. 882. 1316.
2013 1322184. 2611026. 3899868. 453. 894. 1336.
2014 1338429. 2647012. 3955594. 458. 907. 1355.
2015 1354674. 2682998. 4011320. 464. 919. 1374.
2016 1370920. 2718984. 4067046. 469. 931-1393.
2017 1387165. 2754969. 4122772. 475. 943. 1412.
2018 1403410. 2790955. 4178498. 481. 956. 1431.
2019 1419655. 2826941. 4234224. 486. 968. 1450.
2020 11135901. 2862926. 4289951. 492. 980. 1469.
2021 1449156. 2B99091. 4349026. 496. 993. 1489~
2022 1462412. 2935256. 4408100. 501. 1005. 1510.
2023 1475667. 2971420. 4467175. 505. 1018. 1530.
2024 1488922. 3007585. 4526249. 510. 1030. 1550.
2025 1502177. 3043750. 4585324. 514. 1042. 1570.
2026 1515433. 3079915. 4644398. 519. 1055. 1591.
2027 1528688. 3116079. 4703473. 524. 1067. 161 1. ~ U 2028 1541943. 3152244. 4762547. 528. 1080. 1631.
2029 1555198. 3188409. 4821622. 533. 1092. 1651.
2030 1568454. 3224574. 48A0696. 537. 1104. 1671.
u
VENETIE -SITE 2
SIGNIFICANT DATA
DETAILED RECONNAISSANCE INVESTIGATIONS
1. LOCATION (diversion)
Stream: Kocacho Creek
Section!! 27, Township 27N, Range 7E, Fairbanks Meridian
Community Served: Venetie
Di stance: 10 mi Di rection (community to site): North-Northeast
Map: USGS Christian, Alaska, 1:250,000
2. HYDROLOGY
Drainage Area:
Estimated Mean Streamflow:
Estimated Mean Annual Precipitation:
3. DIVERSION DAM
Type:
Hei ght:
Crest El evati on:
Vol ume:
4. SPILLWAY
Type:
Openi ng Hei ght:
Width:
Crest Elevation:
5. WATERCONDUCTOR
Type:
Diameter:
Length:
6. POWER STATION
Number of Units:
Turbi ne Type:
Tailwater Elevation:
Rated Net Head:
Installed Capacity:
Maximum Flow (both units combined):
Minimum Flow (single unit):
7. ACCESS
Length:
8. TRANSMISSION LINE
Voltage/Phase: Terrain:~/ Flat (1.0)
Total Length:
9. ENERGY
Pl ant Factor:
Average Annual Energy Production:
Method of Energy Computat10n:
10. ENVIRONMENTAL CONSTRAINTS: None noted
1/ Section number is approximate.
342
216
9
sq mi
cfs
in
Large Concrete Gravity
10 ft
660 fmsl
1920 cu yd
Conc rete Ogee
5 ft .
260 ft
1920 fmsl
Steel Penstock
66 in
5810 ft
2
. Cross Flow
625 fmsl
31.5 ft
196 kW
92 cfs
9.2 cfs
1.1
14.4
10.0
10.0
mi
kV/l phase
m1
mi
33 percent
564 MWh
Plant Factor Program
2/ Terrain Cost Factors Shown in Parentheses.
. ,
.\l If -
·s
e
SCALE: 1·. 1 Mile
LEGEND:
DAM
PENSTOCK
u ......... .. TRANSMISSION LINE
•
(
POWERHOUSE
r DRAINAGE BASIN
REGIONAL INVENTORY & oflECONNAISSANCE STUDY
SMALL HYDROPOWER PROJECTS
NORTHEAST ALASKA
VENETIE SITE 02
CONCEPTUAL LAYOUT
KOCACHO CREEK
For:
DEPARTMENT OF THE ARMY
ALASKA DISTRICT
CORPS OF ENGINEERS
U
NE/SC ALASKA SMALL HYDRO RECONNAISANCE STUDY
PLANT fACTUR PROGRAM
COMf~UNITY: VENETIE
SITE NUr"lBE R: 2
NET HEAD (FT): 32.
DESIGN CAPACITY (KW): 196.
NINH"IUr-l OPERATING FLOW (1 UNIT) (CFS) : 9.20
LOAD SHAPE FACTORS: 0.50 0.75 1.60 2.00
HOUR FACTORS: 16.00 15.00 13.00 3.00
t10NTH (HDAYS/MO.) AVERAGE POTENTIAL PERCENT ENERGY USABLE
MONTHLY HYDROELECTRIC OF AVERAGE OEr~AND HYDRO
FLOW ENERGY ANNUAL ENERGY ENERGY
(CFS) GENERATION (KWH) (KWH)
JANUARY 14.10 22443. 10.00 106982. 14962.
FEBRUARY 11.20 16102. 9.50 101633. 10735.
MARCH 11.00 17509. 9.00 96284. 11672.
APRIL 14.50 22335. 9.00 96284. 14890.
MAY 820.00 145824. 8.0U 85585. 82417 •
JUNE 671.00 141120. 5.50 58840. 58840.
JULY 206.00 145824. 5.50 58840. 58840.
AUGUST 316.00 145824. 6.00 64189. 64lH9.
SEPTEMBER 371.00 141120. 8.UO 85585. 81829.
OCTOBER 86.90 138318. 9.00 96284. 82946.
NOVEfvll.3ER 34.40 52988. 10.00 106982. 35325.
DECEMBER 20.50 32630. . 10.50 112331. 21753.
TOTAL 1022037. 1069818. 538399.
PLANT FACTOR(1997): 0.31
PLANT FACTOR(LIFE CYCLE): 0.33
U
HYDROPOWER COST DATA -DETAILED RECONNAISSANCE INVESTIGATIONS
Community:
Site:
Stream:
Venetie
2
Koc ac ho Creek
ITEM
1. Dam (including intake and spillway)
2. Penstock
3. Powerhouse and Equipment
-Turbines and Generators
-Misc. Mechanical and Electrical
-Structure
-Val yes and Bifurcations
4. Switchyard
5. Access
6. Transmission
TOTAL DIRECT CONSTRUCTION COSTS
7. Construction Facilities and Equipment,
Camp, Mobilization, and Demobilization
TOTAL INDIRECT CONSTRUCTION COSTS AT 20 PERCENT
SUBTOTAL
Geographic Factor =
SUBTOTAL
Conti ngency at 25 percent
SUBTOTAL
Engineering and Administration at 15 percent
TOTAL CONSTRUCTION COST
Interest During Construction at 9.5 percent
TOTAL PROJECT COST
Cost per kW Installed Capacity
ANNUAL COSTS
Annuity at 7-5/8 percent (AlP = 0.07823)
Operations and Maintenance Cost at 1.5 percent
TOTAL ANNUAL COSTS
Cost per kWh
Benefit-Cost Ratio:
COST
i· 571,000
i 1,569,000
i 373,000
i 188,000
i 210,000
i 6,000
i 188,000
i 17,000
i 250,000
i 3,372,000
i 674,000
i 4,046,000
3.2
i12,947,OOO
i 3,237,000
i16,184,000
i 2,428,000
i18,612,000
i 1,768,000
i20,380,000
i 104,000
i 1,594,300
i 305,700·
u
i 1,900,000 ~
i 3.45
0.18
u
u
REGIONAL INVENTORY & RECONNAISANCE STUDY -SMALL HYDROPOWER PROJECTS
ALASKA DISTRICT -CORPS OF ENGINEERS
DETAILED RECONNAISSANCE INVESTIGATIONS
COST OF HYDROPOWER -BENEFIT COST RATIO
VENETIE
~::~nE NO. 2
1 '==':::4
11~;35
1 I~) ::':: I..~\
1990
1''991
1994
1 ~'9~i
1·~)9/:..
19~'7
1''999
2000
2001
2002
:20(>::::
2004
200!)
200/:..
2007
200:3
2009
2010
2011
:2012
;::01::::
2014
I<WH/YEAR
422454.
4::::::36::::0.
444::::2!:,i.
4~j5021.
46571 (:"
47'::;.411.
486594.
4'~~4'~I'~E: II
51 0(:,(:,1 •
~H 7600.
!.:i24540.
5:31480.
~'~:~339S) •
545290.
551454.
5!'57107.
55';i6':::.7.
562226.
5647::::(:..
567:;:46.
569906.
572396.
5747~55.
577113.
579472.
581831-
584594.
~i87227 •
~;:3ti':31:,() •
5'''2318.
20 15 ~,94727.
2016 ~i971-::':7.
:2017 599547.
::;::018 601956.
2019 604::::66.
:2020 606776.
2021 60:::742.
~20;~~::: (,') 12675.
2024 614641.
2025 1..:.16607.
2026 61857:;':.
:~:()~?,? f.:2:3€)24 It
::;:~():~~:() /:.12446C) D
AVERAGE (;OST
CAPITAL
1604721.
1604721.
1604721.
1604721.
1604721.
1604721.
1604721.
1 ':::,04721.
1.604721.
1604721.
1':::,04721.
1604721.
1604721.
1604721.
1604721.
1604721.
1604721.
1604721.
1604721.
1604721.
1604721-
1604721.
1604721.
1604721.
1604721.
1604721.
1604721.
1604'721.
1604721.
1604721.
1604721.
1604721.
1604721.
1604721.
1604721-
1604721.
1604721-
1604721.
1604721.
1604721.
1604721.
1604721.
1604721.
1604721.
1604721.
1604721.
1604721.
(I 8~ M
:305700.
:30~~700.
:305700.
:3(15700.
3057(10.
::::0!::~70(l.
:305700.
:305700.
305700.
305700.
305700.
:;:05700.
:305700.
305700.
:305700.
305700.
305700.
305700.
:305700.
305700.
:305700.
:305700.
305700.
305700.
305700.
::;:05700.
305700.
:305700.
305700.
305700.
305700.
305700.
305700.
305700.
305700.
305700.
305700.
~::05700.
305700.
305700.
:3(1!::i700.
::::05700.
~~:05'700.
3057()O.
::::O~i700.
::=:05700.
305700.
TOTAL$
1910421.
1'::>10421-
1910421.
1910421-
1910421.
1910421.
1910421.
1910421-
1910421.
1910421.
1910421.
1910421.
l';il10421-
1910421,.
1910421-
1910421-
1910421.
1910421.
1910421-
1910421.
1S"10421.
1910421-
1910421-
1910421-
1910421-
1910421.
l';il104~:1-
1';>10421.
1910421-
1910421-
1910421.
1910421.
1910421-
1910421-
1910421.
1910421.
1910421-
1910421.
1910421.
1910421-
1910421.
1910421.
19:1 0421.
1 ';i 1 0421 •
1910421-
1910421.
1,';"10421.
$/KWH $/I<WH
NOND I ::;;C DISC
4. ~522 :~:. :371
4.406 3.051
4.300 2.7':::,7
4.199 2.510
4.102 2.279
4.010 2.070
:3.926 1.88:3
:3.859 1.720
3.7'::>6 1.572
:;:.741 1.439
:3.6911.319
:3.(:,421.210
3. 595 1 • 10':;"1
3.5.481.017
3.503 ().933
3.464 0.858
3.429 0.789
3.413 0.729
:3. :398 0.675
3 .. :3E:3 (). c,24
3.367 0.577
3.352 0.534
3.338 0.494
:3.324 0.457
::;:.310 0.42::::
3 .. 28q (1.3c.2
3. :268 O. :335
3.253 0.310
:3.239 0.287
3.225 0.265
3.212
3.199
3.186
3.174
:3. 161
3.148
3.138
3.128
:3. 118
:;:. 1 ()8
:3. ()98
::3. O(~:8
::;:. ()::: 1
:3 II ()6~~;.
:::. ()5t;1
::::. 4~i2
0.245
0.227
0.210
0.194
0.180
0.167
0.154
0.143
0.132
0.123
0.114
0.105
0.0'-;'7
0.090
0.084
0.078
RFNFFTT-COST RATIO (5% FUEL COST ESCALATION): 0.18
Venetie, Alaska
Kocacho Creek-Damsite Vicinity
(i n foreground)
Community of Venetie
u
u
3.0 TOK, DOT LAKE, TANACROSS, AND MANSFIELD VILLAGE
3.1 COMMUNITY AND UTILITY DESCRIPTIONS
Tok, Tanacross, a,nd Dot Lake are located on the Alaska Highway 150 to
200 miles southeast of Fairbanks. Tok is a regional center with an
economic base of tourism while both Tanacross and Dot Lake are small
native villages. Tok has a large, dispersed and expanding population.
Dot Lake and Tancross have small stable populations concentrated at the
community centers.
The electric energy needs of Tok, Tanacross. and Dot Lake have been
assessed in combination since a small nydropower project could serve
potentially three communities. Alaska Power and Telephone (AP and T)
is the utility that owns and operates the existing diesel generators
based in Tok as well as the pair of 100 kW generators in Dot Lake. Tok
and Tanacross are intertied by a 3 phase transmission line and a
single-wire ground return (SWGR) line extends from Tanacross to Dot
Lake. A waiver of certain cOde restrictions from the Alaska Power
Authority is required before electricity can be transmitted through the
SWGR wi reo
3.1.1 Alaska Power and Telephone Compa~
AP and T generates electricity in this area by diesel generators. The
system, based in Tok, has 1 -975 kW, 3 -300 kW, and 2 -200 kW
generators, for a total of 2275 kW of installed capacity. The 300 kW
and 200 kW generators are used for standby in the summer and brought
on-line in the winter. Peak demand in the summer is 1000 kW and the
winter peak is 1200 to 1300 kW. A substantial number of Tok residents
are not served by AP and T and cost of installing distribution lines is
prohibitive to many potential consumers. The system is planned to
expand in the winter of 1982 when a 1250 kW generator will replace the
larger generator, adding 275 kW of capacity to the total system.
Transmission routes and capacities of the system are presented in
Table 1.
TABLE 1
AP AND T TRANSIIr1 ISS ION ROUTES AND CAPACITIES
TOK, ALASKA VICINITY
Direction from Tok Di stance Phase Volts
East
West
South
6 miles
12 mi 1 es (short
of Tanacross)
Continuing to Dot
Dot Lake approxi-
mate ly 40 mi 1 es
2 miles
3-1
3
3
1
3
7,200 12,000
7,200 12,000
Single Wire Ground
Return
2,400
AP and T charges consumers based on a decli n1 ng block rate structure in
which th~ highest price per kWh is paid by the smallest consumers. The
cost of power to small consumers is 18 cents/kWh plus a fuel surcharge
of 7 cents/kWh, making an effective rate of 25 cents/kWh. Large
consumers receive a financial break and pay 12 cents/kWh plus a fuel
surcharge. This rate affects residences that are attached to
commercial operations. A detailed rate schedule is presented in
Table 2.
TABLE 2
AP AND T RESIDENTIAL ELECTRICITY RATE SCHEDULE
Quantity Consumed per Month
( kWh)
Small Consumers
1st 100 kWh
2nd 100 kWh
next 800 kWh
Large Consumers
unlimited
Price
(' lkWh)
.1797
.1697
.1447
.1200
No immediate plans have been made for system expansion to serve more
customers. If the Alaska natural gas pipeline project materializes,
AP and T could expand north of Dot Lake where construction camps will
likely be located. When the SWGR wire is used to transmit electricity
from Tok to Dot Lake, the diesel generators at Dot Lake would be used
only for standby power. AP and T plans to decentralize the phone
system and put in an office in Dot Lake. Eventually the telephone line
between Tanacross and Dot Lake would be phased out and the poles may be
equipped to carry 3 phase electric lines. This additional capacity of
the lines would allow for the expansion northward.
3.1.2 Tok
TOk, located at the junction of the Alaska and Glenn Highways, is the
regional center for the Upper Tanana area. Tok originated as a
construction camp for the A1can and Glenn Highways between 1942 and
1946 and for the Haines-Fairbanks oil pipeline in 1954. In the late
1960s travel on the Alaska Highway had become popular which enabled Tok
to capital i ze on touri sm. Tok has presently a number of busi nesses and
government offices. These provide local employment, particularly
during the tourist season. During winter, however, the unemployment
rate is around 50 percent. Despite the lack of jobs, Tok is growing
rapidly and attracting people both from within and outside Alaska.
3-2 u
u
The population of Tok is 750 which increases during the summer, due
primarily to an influx of retired people. ~Residents are dispersed
across a large area rather than being concentrated in neighborhoods.
Numerous stores, gas stations, motels, and restaurants are located at
and near the junction of the two highways.
With respect to electricity usage, a large proportion of pmlfer is
consumed in the commercial and institutional sectors. Some of the
motels have been equipped with electric baseboard heating and domestic
hot water tanks. In contrast, numerous residences in Tok are without
power. The average household that is served by AP and T has the
standard electric appliances such as refrigerators, freezers, and small
appliances but does not have ma~ large appliances because of the high
price of electricity. Homes are heated by either wood or oil; but at
$1.21/gallon, the trend 1.s towards converting to wood heat. If power
was available at a more reasonable cost, a likely scenario would be
that more appliances would be acquired and more residences would pay
for the service.
3.1.3 Tanacross/Mansfield Village
Tanacross is an Athabascan village located 12 miles west of Tok on the
Tanana River. The old village, located on the east side of the Tanana
River burned in 1979, eight years after the village was relocated to
• its present site. The current population of 117 resides at the new
community. All of the homes are HUD or constructed privately and are
wi red for modern appli ances. Other structures in Tanacross are the
community hall, council office building, water treatment plant, church,
andelementar,y school.
Mansfield Village is located about 8 miles north of Tanacross and can
be reached only by a foot trail. The village serves as a fishing camp
for Tanacross residents in the summer and has approximately 8 houses.
Any power that is required is generated by a small horsepower engine.
Providing electricity on a~ larger scale would be impractical.
In Tanacross, use of electricity in the residental sector is fairly low
and is constrained by high electricity prices and lack of stable
sources of income. Appliances found in an average household include
televison, refrigerator, toaster, coffeepot, and radio. Ma~ of the
homes are heated by forced ai r oil heat which requires electricity to
operate the fan. Similar to Tok, ma~ houses are changing to wood heat
because it is more economical than oil. Load is heaviest· in the winter
when car heaters are used overnight and circulating fans in ,the furnace
are on frequently. Power bills average S150/month during the winter
and can be as low as $10/monthduring the summer.
The water treatment plant i.s the principal electricity consumer.
Monthly consump~ion ranges from 3700 kWh to 5500 kWh and monthly bills
average $450 in the summer and $650 in the winter. The money to pay
these electric bills comes from the village council contingency funds.
3-3
Tanacross operates on a sUbsistence econorqy of fishing and trapping. A
few full-time jobs exist but in general the unemployment rate is very
high. The village council employs people on a temporary basis through U
various community projects but most residents find seasonal employment
outside of Tanacross. Temporary jobs that are available include
firefighting for the BlM, highway construction, North Slope
construction, and government in Tok.
3.1.4 Dot lake
Dot lake is a native village with a population of 66 including both
Athabascans and non-nati ves. The majority of the popul ation
(45 persons) is located at the community center and the remaining
individuals live in the surrounding area. Structures in Dot lake that
IJse electricity include 10 residences, community hall, lodge,
restaurant/store, school s (grades 1 through 12), church, and microwave
tower.
Power is generated from 2 -100 kW diesel generators located in Dot
lake and owned, operated, and maintained by Alaska Power and Telephone
Company. One generator is used for backup power. The power is not
dependable and wears down the motors on appliances. Although Dot lake
is intertied to the AP and T transmission system, the community has
only once received power from its central generating station based in
Tok (see previous discussion of AP and T system). Meters are installed
on all houses as well as on all the other structures. At 18 cents/kWh
pl us fuel surcharge, an average monthly bi 11 ranges from $35 to $80
based on consumption of 150 kWh to 350 kWh. Electrical appliances
found in most homes are refrigerators, freezers, coffeepots, toasters,
and frying pans. Televisions are being acquired and a few homes have
microwave ovens. Propane is used for cooking and domestic hot water.
The residential load is fairly even throughout the year although the
total village load is heaviest in the winter. This variation in
village consumption is du.e primarily to the central hot water heating
system, which uses two oil furnaces and circulating pumps. In 1980,
the utility building used 16,000 kWh, at a cost of approximately S3,000.
Sources of income are sporadic. The lodge is a family operated
business and employs no outside help. Two full-time janitorial
positions are connected with the school. Part-time jobs can be found
in construction and locally with community projects.
Several proposed developments may stimulate growth in the Dot lake
area. The state is proposing to sell 300 - 5 acre lots west of Dot
lake along the Alaska Highway. Local residents have expressed
reservations regarding what newcomers would do for a living as well as
what they would be able to contribute to the community. In addition,
the proposed project is sited at a major moose crossing. Another land
sale that is associated with a mining project may occur south of Dot
3-4 u
u
u
Lake near Robertson River. The development of the proposed gas
pipeline and associated construction camps, would also stimulate growth
in the area.
3.2. SITE SELECTION
3.2.1 Dot .Lake
Four sites were investigated in field. Site No. 02 on the main branch
of Bear Creek was deemed clearly superior because the flow measured was
much larger than at .the other sites and because no major adverse
factors appeared to be associated with the site. As opposed to this,
Site 4 on the North Fork of Bear Creek was found to be located on a
vast glacial gravel outwash plain, offering no clear-cut dam sites and
requiring a very long intake structure, located on pervious foundations
and likely to b~ shortly buried by bedload sedimen~ deposition. Site
05 on Berry Creek was also inspected and the flow measured, but both
this site and Site 01 on the South Fork of Bear Creek, which was
overflown, were deemed to be less attractive than the selected site.
Site No.2 is located in an approximately fifty foot wid~, five foot
deep channel of the braided Bear Creek, apparently in alluvial terrace
material al though metamorphic or igneous bedrock outcrops occur higher
up on the gently sloping left abutment. Because of the amount and size
of the bedload gravel the intake itself was assumed to be located 50 to
100 feet upstream of the concrete ogee type dam. No major topographic
nor foundation problems appear to be present along the proposed
penstock or transmission routes.
3.2.2 Tanacross
Stream basi ns near Tanacross were studied for their abi 1 i ty to supply
part of the energy demand of the intertied Tanacross-Tok-Dot Lake
System •.
Closest to the community, all the creeks running Northeast ~ff Mount
Neuberger go underground into the alluvial gravel s before reaching the
Tanana River. Because of their proximity, however, the potential for
sites further upstream was investigated. The two most attractive creek
basins, located at the northern and southern most extremities of the
Northeast face of Mt. Neuberger, were studied in field. At the time of
the end of August site visit the northernmost creek (Site 02) proved,
however, to be dry. Flow measurements made of the southernmost creek
(Site 9) showed development here to be less attractive than on Yerrick
Creek (Site OIl.
Of the two Cathedral Rapids Creeks 12 miles west of Tanacross, Creek
No. 2 has been judged to be more attractive duri ng the prescreeni ng
stage. It, too, proved, however, to be dry during the site visit.
3-5
Yerrick Creek fonns a major deeply "incised flat-bottomed valley,
running north to the Tanana River past the western end of Mount
Neuberger. The creek is a typical example of a large, braided creek in U
the foothill s of the Alaska Range, with one to several 10 to 30 foot
wide stream channels within a 200 to 400 foot wide valley, with an
almost unifonn gradient.
At the proposed site the valley floor narrows to approximately 200
feet, with the stream bed fonned in large sized gravel and up to two
foot boulders. Whil.e the right abutment is fonned by biotite gneiss
and schist, the fact that the left abutment is largely made up of
glacial till (of Delta glaciation) may make construction of high dams
unattractive on this creek. The intake for the proposed diversion dam
was assumed to be located some 50 to 100 feet upstream, to avoid having
bed load materials in time deposited against the dam face. The right
abutment appeared to be too rocky and scree-covered for the penstock
route but routing it within the left abutment would probably also prove
expensive, with burial required along part of its length within the
steeply dipping glacial till face.
3.2.3 Tok
Potential hYdro sites for the intertied Tok-Tanacross-Dot Lake utility
system were investigated near each of the three communities. Site 08,
five miles west of Tetlin Lake, was overflown but disclosed no
faVOrable site factors sufficiently attractive to offset the need for
seven miles cross-country site access from Route 1.
As opposed to this, only three miles of track along the gradually
sloping Clearwater Creek is required to provide access to Site 01. An
optimum dam location is not readily defined along the braided stream
channels within a 300 foot wide gravelly alluvium flood plain. The
provisional location is 300 to 400 feet upstream of the junction with a
left bank tributary from the north. It might be economical to
intercept this tributary by diverting it around the abutment spur,
probably fonned of biotite schist and gneiss. Only 0.5 mile of very
easy access would be required to the powerhouse site, located probably
on granitic rocks near the Cl earwater Campground.
3-6 u
u
NOTE I TOPOGRAPHY FROM U. S. G. S. -TANACROSS
AlASKA t I: 250,000
LEGEND
~ DAM SITE
• POWERHOUSE o . SITE NO
-----PENSTOCK
_ .. -TRANSMISSION LINE
-WATERSHED
5 0 5
REGIONAL INVENTORY a RECONNAISSANCE STUD'f
SMALL HYDROPOWER ~CTS
NORTHEAST ALASKA
HYDROPOWER SITES IDENTIFIED
IN PREUMINARY SCREENING
TANACROSS
DEPARTMENT OF THE ARMY
ALASKA DISTRICT CORPS OF ENGINEERS
u
u
NOTE: TOPOGRAPHY FROM U. S. G. S. -MT. HAYES
ALASKA, I : 250,000
LEGEND
.. DAM SITE
• POWERHOOSE o SITE NO
PENSTOCK
- - -TRANSMtSSION LINE
--WATERSHED
5 o 5
E3 E3 E3
SCALE I.N MILES
REGIONAL INVENTORY a REOONNAISSANCE STUD'(
SMALL HYDROPOWER PROJECTS
NORTHEAST ALASKA
HYDROPOWER SITES IDENTIFIED
I N PREll MINARY SCREEN I NG
DOT LAKE
DEPARTMENT OF THE ARMY
ALASKA DISTRICT CORPS OF ENGINEERS
u
NOTE: TOPOGRAPHY FROM U. S. G. S. -TANACROSS
ALASKA, 1:250,000
LEGEND
~ DAM SITE
• POWERHOUSE o SITE NO.
--- --PENSTOCK
---TRANSMISSION LINE
---WATERSHED
5 0 5
E3 t==1 E3
SCALE I N MILES
srUDY
HYDROPOWER SITES IDENTIFIED
IN PRELIMINARY SCREENING
TOK
DEPARTMENT OF THE ARMY
ALASKA DISTRICT CORPS OF ENGINEERS
u
NOTE: TOPOGRAPHY FROM U. S. G. S. -TANACROSS
ALASKA, 1:250,000
LEGEND
~ DAM SITE
• POWERHOUSE o SITE NO.
- -_. -PENSTOCK
---TRANSMISSION LINE
--WATERSHED
5
E3
1560 \. ". -',
\
\
\
\
\ , " ,
-\'-\ -... ----~~
. " . . ''r
""'r
o
SCALE I N MILES
5
REGIONAL INVENTORY & RECONNAISSANCE STUDY
SMALL HYDROPOWER PROJECTS
NORTHEAST ALASKA
HYDROPOWER SITES IDENTIFIED
IN PRELIMINARY SCREENING
MANSFIELD VILLAGE
DEPARTMENT OF THE ARMY
ALASKA DISTRICT CORPS OF ENGINEERS
u
~dro~ower POtential
Installed
Capacity
Si te No. (kW)
* 1 299
Demographic Characteristics
1981 Population: 117
SUMMARY DATA SHEET
DETAILED INVESTIGATIONS
TANACROSS, ALASKA
Cost of
Installed Alternaj1 ve
Cost Power-
($1000) (mill s/kWh)
6,288 436
1981 Number of Households: 34
Economic Base
Seasonal Construction
11 5 Percent Fuel Escalation, Capital Cost Excluded.
Cost of
I-(ydropower Benefit/Cost
(mill s/kWh) Ratio
690 0.63
See Appendix C (Table C-8) for example of method of computation of
cost of alternative power.
* This site was identified in the drainage basin inventor,y for Mansfield
Vi 11 age.
~dro~ower Potential
Installed
Capacity
Si te No. (kW)
2 699
Demographic Characteristics
1981 Population: 66
SUMMARY DATA SHEET
DETAILED INVESTIGATIONS
DOT LAKE, ALASKA
Cost of
Installed Al ternative
Cost Power.!1
($1000 ) (m; 11 s/kWh)
9,840 440
1981 Number of Households: 19
Economic Base
Subsi stence
Government
II 5 Percent Fuel Escalation, Capital Cost Excluded.
Cost of
I-IYd ropowe r Benefi tlCost
(mi 11 s/kWh) Ratio
480 0.91
See Appendix C (Table C-8) for example of method of computation of
cost of alternative power.
u
u
liYdro~ower Potentf a 1
Installed
Capacity
Site No. (kW)
7 412
Demographic Characteristics
1981 Population: 750
SUMMARY DATA SHEET
DETAILED INVESTIGATIONS
TOK, ALASKA
Cost of
Installed Al ternaj}ve
Cost Power-\
(SlOOO) (mi 11 s/kWh)
10,876 436
1981 Number of Households: 214
Economic Sase
Touri sm
~vernment
Seasonal construction
1/ 5 Percent Fuel Escalation, Capital Cost Excluded.
Cost of
liYdropower Seneff t/Cost
(mills/kWh) Ratio
880 0.50
See Appendix C (Table C-8) for example of method of computation of
cost of a 1 ternati ve power.
/iYdr0E!0wer Potenti al
Installed
SUMMARY DATA SHEET
DETAILED INVESTIGATIONS
MANSFIELD VILLAGE, ALASKA
Cost of
Installed Cost of
Capacity Cost
Al ternaj}ve
Power_ IiYdropower Benefit/Cost
Site No. (kW) ($1000 ) (mills/kWh) (mill s/kWh) Ratio
1 299 6,288 436 699 0.63
Demographic Characteristics
1981 Population: 0
1981 Number of Households: 0
Economic Base
N/A
y 5 Percent Fuel Escalation, Capital Cost Excluded.
See Appendix C (Table C-8) for example of method of computation of
cost of a 1 ternati ve power.
u
REGIONAL INVENTORY & RECONNAISANCE SrruDY -St4ALL HYDROPOWER PROJECTS
ALASKA DISTRIC'r -CORPS OF ENGINEERS
LOAD FORECAST -TANACROSS
U KILOWATT-HOURS PER YEAR ANNUAL PEAK DEMAND-KW
YEAR Lmv MEDIUM HIGH LOW MEDIUM HIGH
1980 501429. 501.429. 501429. 172 • 172 • 172.
1981 519055. 519055. 519055. 178. 178. 178.
1982 536681. 536681. 536681. 184. 184. 184.
1983 554307. 554307. 554307. 190. 190. 190.
1984 571933. 571933. 571933. 196. 196. 196.
1985 589559. 589559. 589559. 202. 202. 202.
1936 6071135. 607185. 607185. 208. 208. 208.
1987 624811. 624811. 624811. 214. 214. 214.
1988 642437. 642437. 642437. 220. 220. 220.
1989 660063. 660063. 660063. 226. 226. 226.
1990 677689. 677689. 677689. 232. 232. 232.
1991 694209. 732957. 771705. 238. 251. 264.
1992 710729. 788225. 865722. 243. 270. 296.
1993 727249. 843494. 959738. 249. 289. ·329.
1994 743769. 898762. 1053755. 255. 308. 361.
1995 760288. 954030. 1147771. 260. 327. 393.
lY96 776808. 1009298. 1241787. 266. 346 • 425.
1997 793328. 1064566. 1335804. 272. 365. 457.
1998 809848. 1119835. 1429820. 277. 384. 490.
1999 826368. 1175103. 1523836. 283. 402. 522.
2000 842888. 1230371. 1617853. 289. 421. 554.
2001 859923. 1298596. 1737268. 294. 445. 595.
2002 876959. 1366821. 1856682. 300. 468. 636.
2003 893994. 1435046. 1976097. 306. 491. 677.
2004 911030. 1503271. 2095512. 312. 515. 718.
2005 928065. 1571496. 2214926. 318. 538. 759.
2006 945100. 1639721. 2334341. 324. 562. 799.
2007 962136. 1707946. 2453755. 329. 585. 840.
2008 979171. 1776171. 2573170. 335. 608. 881.
2009 996206. 1844396. 2692584. 341. 632. 922.
2010 1013242. 1912621. 2811999. 347. 655. 963.
2011 1035558. 1949375. 2863192. 355. 668. 981.
2012 1057873. 1986130. 2914385. 362. 680. 998.
2013 1080189. 2022884. 2965578. 370. 693. 1016.
2014 1102505. 2059638. 3016771. 378. 705. 1033.
2015 1124821. 2096392. 3067964. 385. 718. 1051.
2016 1147136. 2133147. 3119157. 393. 731. 1068.
2017 1169452. 2169901. 3170350. 400. 743. 1086.
2018 1191768. 2206655. 3221543. 408. 756. 1103.
2019 1214084. 2243409. 3272736. 416. 768. 1121.
2020 1236399. 2280164. 3323929. 423. 781. 1138.
2021 1251261. 2311782. 3372304. 429. 792. 1155.
2022 1266123. 2343401. 3420679. 434. 803. 1171.
2023 1280984. 2375019. 3469054. 439. 813. 1188.
2024 1295846. 2406637. 3517429. 444. 824. 1205.
2025 1310708. 2438255. 3565804. 449. 835. 1221.
2026 1325570. 2469874. 3614179. 454. 846. 1238.
2027 1340431. 2501492. 3662554. 459. 857. 1254.
U 2028 1355293. 2533110. 3710929. 464. 868. 1271.
2029 1370155. 2564728. 3759304. 469. 878. 1287.
2030 1385017. 2596347. 3807679. 474. 889. 1304.
Hr;GIONAL INVENTORY & RECONNAI!->ANCE STUDY -SHALL HYDROPOWER PROO EC'l'S
ALASKA DISTRICT -CORPS OF ENGINEERS
LOAD FOIU;;CAST -DOT LAKE
KILOW/\T'1'-HOUR5 PER YEAR ANNUAL PEAK DEMA:.JD-I~~l U
YEfd-\ LOV-J MEDIUH HIGH LOW l-1EDIUr.., HIGII
1980 282857. 282857. 282857. 97. 97. 97.
19B1 292800. 292800. 292800. 100. 100. lOa.
19H2 302743. 302743. 302743. 104. 104. 104.
1983 312686. 312686. 312686. 107. 107. 107.
19B4 322629. 322629. 322629. 1 10. 110. 110.
19f35 332572. 332572. 332572 • 114. 114. 1 1,1 •
19a6 342514. 342514. 342514. 117 • 117 • 117 •
19P7 352457. 352457. 352457. 121. 121. 121.
19~iB 362400. 362400. 362400. 124. 124. 124.
1989 372343. 372343. 372343. 128. 128. 128.
1990 382286. 382286. 382286. 131. 131. 131 •
1991 391605. 413463. 435321. 134. 142. 149.
1992 400924. 444640. 488356. 137. 152. 167.
1993 410243. 475817. 541391. 140. 163. 18:';.
1994 419562. 506994. 5941126. 144. 174. 20<1.
1995 4288U 1. 538171. 647460. 147. 184. 222.
1996 438199. 569347. 700495. 150. 195. 240.
1997 447518. 600524. 753530. 153. 206. 258.
1998 456837. 631701. 806565. 15(,. 216. 276.
1.999 46615f~. 662878. B59600. HiO. 227. 294.
2000 475475. 694055. 912635. 163. 2313. 313 •
2001 485085. 732541. 979997. 166. 251. 33G.
2002 494695. 771027. 1047359. 169. 264. 359.
2003 504304. 809513. 1114721. 173. 277. 3~32 •
2004 513914. 847999. 1182084. 176. 290. 405.
2005 523524. 386484. 1249446. 179. 304. 429.
2006 533134. 924970. 1316808. 183. 317. 451.
2()07 542744. 963456. 13134170. 186. 330. 474.
2008 552354. 1001942. 1451532. 189. 343. 497.
2009 561963. 104042B. 15188')4. 192. 356. 520.
2010 571573. 1078914. 1586256. 196. 369. 543.
2011 5B4161. .1099647. 1615134. 200. 377. 553.
2012 596750. 1120381. 1644012. 204. 384. 563.
2013 609338. 1141114. 1672n90. 209. 391. 573.
2014 621926. 1161847. 1701769. 213. 398. 583.
201S 634515. 1182580. 1730647. 217 • 405. 593.
2016 647103. 1203314. 1759525. 222. 412. 603.
2017 659691. 1224047. 1788403. 226. 419. 612.
20H! 672280. 1244780. 1817281. 230. 426. 622.
2019 6H4B6U. 1265513. 1846159. 235. 433. 632.
2020 697456. 1286246. 1875037. 239. 440. 642.
2021 705B40. 1304082. 1902325. 242. 447. 651.
202/. 7142/.3. 1321918. 1929614. 245. 453. 661.
2023 722607. 1339754. 1956902. 247. 459. 670.
2024 730990. 1357590. 1984191. 250. 465. 680.
2025 739374. 1375426. 2011479. 253. 471. 6P'1.
2026 747757. 1393262. 203£1767. 256. 477. 69P.
2()27 756141. 1411098. 2066056. /.59. 483. 708.
2028 764524. 1428934. 2093344. 262. 489. 717. U 2029 7720,08. 1446770. 21201)33. 265. 495. 72(,.
2030 781291. 1464006. 2147921. 268. 502. 736.
REGIONAL INVENTORY & RECONNAISANCE STUDY -SMALL HYDROPOWBR PROJECTS
ALASKA DISTRICT -CORPS OF ENGINEERS
LOAD FORECAST -TOK
KILOWAT'I'-HOURS PER YEAR ANNUAL PEAK DEMAND-KW
YEAR LOW ~1EDIUM HIGH LOW MEDIUM HIGH
1980 3150000. 3150000. 3150000. 1079. 1079. 1079.
1981 3260728. 3260728. 3260728. 1117. 1117. 1117.
1982 3371456. 3371456. 3371456. 1155. 1155. 1155.
1983 34!:l2183. 3402183. 3482183. 1193. 1193. 1193.
1984 3592911. 3592911. 3592911. 1230. 1230. 1230.
1985 3703639. 3703639. 3703639. 1268. 1268. 1268.
19!:l6 3814367. 3814367. 3814367. 1306. 1306. 1306.
1987 3925094. 3925094. 3925094. 1344. 1344. 1344.
1988 4035822. 4035822. 4035822. 1382. 1382. . 1382.
1989 4146550. 4146550. 4146550. 1420. 1420. 1420.
1990 4257277 • 4257277. 4257277. 1458. 1458. 1458.
1991 4361056. 4604475. 4847893. 1494. 1577. 1660.
1992 4464835. 4951672. 5438509. 1529. 1696. 1863.
1993 4568614. 5298870. 6029125. 1565. 1815. 2065.
1994 4672393. 5646067. 6619741. 1600. 1934. 2267.
1995 4776172. 5993265. 7210357. 1636. 2052. 2469.
1996 4879951. 6340462. 7800973. 1671. 2171. 2672.
1997 4983730. 6687660. 8391589. 1707. 2290. 2874.
1998 5087509. 7034857. 8982205. 1742. 2409. 3076.
1999 5191288. 7382055. 9572821. 1778. 2528. 3278.
2000 5295067. 7729253. 10163439. 1813. 2647. 3481.
2001 5402085. 8157846. 10913607. 1850. 2794. 3738.
2002 5509102. 8586439. 11663775. 1887. 2941. 3994.
2003 5616120. 9015032. 12413943. 1923. 3087. 4251.
2004 5723137. 9443625. 13164111. 1960. 3234. 4508.
2005 5830155. 9872218. 13914279. 1997. 3381. 4765.
2006 5937172. 10300811. 14664447. 2033. 3528. 5022.
2007 6044190. 10729404. 15414615. 2070. 3674. 5279.
2008 6151207. 11157997. 16164783. 2107. 3821. 5536.
2009 6258225. 11586590. 16914952. 2143. 3968 •. 5793.
2010 6365242. 12015182. 17665122. 2180. 4115. 6050.
2011 6505430. 12246075. 17906718. 2228. 4194. 6160.
2012 6645618. 12476968. 18308314. 2276. 4273. 6270.
2013 6785806. 12707861. 18629910. 2324. 4352. 6380.
2014 6925994. 12938754. 18951506. 2372. 4431. 6490.
2015 7066182. 13169647. 19273102. 2420. 4510. 6600.
2016 7206370. 13400540. 19594698. 2468. 4589. 6711.
2017 7346558. 13631433. 19916294. 2516. 4668. 6821.
2018 7486746. 13862326. 20237890. 2564. .4747. 6931.
2019 7626934. 14093219. 20559486. 2612. 4826. 7041.
2020 7767124. 14324107. 20881090. 2660. 4906. 7151.
2021 7860486. 14522735. 21184984. 2692. 4974. 7255.
2022 7953848. 14721363. 21488878. 2724. 5042. 7359.
2023 8047210. 14919991. 21792772 • 2756. 5110. 7463.
2024 8140572. 15118619. 22096666. 2788. 5178. 7567.
2025 8233934. 15317247. 22400560. 2820. 5246. 7671.
2026 8327296. 15515875. 22704454. 2852. 5314. 7775.
2027 8420658. 15714503. 23008348. 2884. 5382. 7880.
U 2028 8514020. 15913131. 23312242. 2916. 5450. 7984.
2029 8607382. 16111759. 23616136. 2948. 5518. 8088.
2030 8700744. 16310387. 23920030. 2980. 5586. 8192.
REGIONAL INVENTOHY & RECONNAISANCE STUUY -SI·1ALL HYDROPOWER PROJECTS
ALASKA DISTRICT -CORPS OF ENGINEERS
LOAD FORECAST -l'viANSf'IELD VILLAGE -AP&T
KILOWATT-BOURS PEl{ YEAR ANNU1\L PEAK DEt-lANlJ-Kvi
YEP.R LOH HEDIUt1 HIGH LO~'l MEDIUI'; HIGH
1980 3934286. 3934286. 3934286. 1347. 1347. 1347.
1981 4090687. 4090687. 4090687. 1401. 1401. 1401.
1982 4247088. 4247088. 4247088. 1454. 1454. 145<1.
1933 4403489. 4403489. 4403489. 1508. 1508. 1508.
1984 4559890. 4559890. 4559890. 1562. 1562. 1562.
19B5 4716291. 4716291. 4716291. 1615. 1615. 1615.
1986 48726')2. 4872692. 4872692. 1669. 1669. 1669.
1987 5029093. 5029093. 5029093. 1722. 1722. 1722.
1988 5185494. 5185494. 5185494. 1776. 1776. 1776.
1989 5341895. 5341895. 5341895. 1829. 1829. Hl29.
1990 5498296. 5498296. 5498296. 1883. 1883. 1883.
1991 5635486. 5949557. 6263627. 1930. 2038. 2145.
1992 5772675. 6400817 • 7028958. 1977 • 2192. 2407.
1993 5909865. 6B52078. 7794289. 2024. 2347. 2669.
1994 6047054. 7303338. 8559620. 2071. 2501. 2931.
1995 618424<1. 7754599. 9324951. 2118. 2656. 3193.
1996 6321433. f3205H59. 100902132. 2165. 2810. 3456.
19')7 6458623. !3657119. 10855613. 2212. 2965. 371l'.
1998 6595812. 9108379. 11620944. 2259. 3119. 3980.
1999 6733002. 9559639. 12386275. 2306. 3274. 4242.
2000 6870192. 10010899. 13151606. 2353. 342[). 4504.
2001 7010400. 10566027. 14121647. 2401. 3619. 4B36.
2002 7150623. 11121155. 15091688. 2449. 3809. 5168.
2003 7290839. 11676283. 16061729. 2497. 3999. 5501.
2004 7431054. 12231411. 17031770. 2545. 4189. 5833.
2005 7571269. 12786539. 18001810. 2593. 4379. 6165.
2006 7711485. 13341667. 18971850. 2641. 4569. 6497.
2007 7851701. 13896795. 19941890. 2689. 4759. 6B29.
2008 7991916. 14451923. 20911930. 2737. 4949. 7162.
2009 8132132. 15007051. 21881970. 2735. 5139. 7494.
2010 8272348. 15562180. 22852012. 2833. 5330. 7826.
2011 8451235. 15858098. 23264962. 2i194. 5431. 7967.
2012 8630122. 16154016. 23677912. 2956. 5532. 8109.
2013 8809009. 16449934. 240<)0862. 3017. 5634. 8250.
2014 8987896. 16745852. 24503812. 3078. 5735. 8392.
2015 9166783. 170417 70. 24916762. 3139. 5836. 8533.
2016 9345670. 17337688. 25329712. 3201. 5938. 8675.
2017 9524557. 17633606. 25742662. 3262. 6039. 8816.
2018 9703444. 17929524. 26155612. 3323. 6140. 8957.
2019 9882331. 10225442. 26'l6R562. 3384. 6242. 9099.
2020 10061214. 18521358. 26981502. 3446. 6343. 9240.
2021 10182417. 18778380. 27374344. 34H7. 6431. 9375.
2022 10303620. 19035402. 27767186. 3529. 6519. 9509.
2023 10424823. 19292424. 28160028. 3570. 6607. 9644.
2024 1(1546026. 19549-1116. 28552870. 3612. 6695. 9778.
2025 10667229. 19806468. 2B945712. 3653. 6783. 9913.
2026 10788432. 20063490. 29338554. 3695. 6B71. 10047.
2027 10909635. 20320512. 297313'::J6. 3736. 6959. 101B2.
2028 11030[l38. 20577534. 30124238. 3778. 7047. 10317 • U 2029 11152041. 20A34556. 30517080. 3819. 7135. 10451.
20)0 11273244. 21091578. 30909922. 3861. 7223. 10586.
U
\
NE/SC ALASKA SMALL HYDRO RECONNAI SANCE STUDY
PLANT FACTOR PROGRAM
COMMUNITY: TANACROSS
SITE NUMBER: 1
NET HEAD (FT): 237.
DESIGN CAPACITY (KW): 299.
MINIMUM OPERATING FLOW (1 UNIT) (CFS): 1.86
LOAD SHAPE FACTORS: 0.50 0.75 1.60 2.00
HOUR FACTORS: 16.00 15.00 13.00 3.00
MONTH (#DAYS/MO.) AVERAGE POTENTIAL PERCENT ENERGY USABLE
MONTHL Y HYDROELECTRIC OF AVERAGE DEMAND HYDRO
FLOW ENERGY ANNUAL ENERGY ENERGY
(CFS) GENERATION (KWH) (KWH)
JANUARY 1.94 23233. 10.00 622458. 15488.
FEBRUARY 1.66 o. 9.50 591335. O.
MARCH 1.61 o. 9.00 560212. o.
APRIL 2.80 32450. 9.00 560212. 21633.
MAY 25.50 222456. 8.00 497966. 148304.
JUNE 39.30 215280. 5.50 ' 342352. 141682.
JULY 26.20 222456. 5.50 342352. 146167.
AUGUST 23.00 222456. 6.00 373475. 146816.
SEPTI:::MBER 13.60 157614. 8.00 497966. 105076.
OCTOBER 6.41 76764. 9.00 560212. 51176.
NOVEMBER 3.14 36390. 10.00 622458. 24260.
DECEMBER 2.50 29939. 10.50 653581. 19959.
TOTAL 1239038. 6224578. 820563.
PLANT FACTOR(1997): 0.31
PLANT FACTOR(LIFE CYCLE): 0.31 '.
U
HYDROPOWER COST DATA -DETAILED RECONNAISSANCE INVESTIGATIot~S
Community: Tanacross U
Si te: 01
Stream: Yerrick Creek
ITEM COST
1. Dam (including intake and spillway) ~ 350,000
2. Penstock ~ 542,000
3. Powerhouse and Equipment
-Turbines and Generators ~ 202,000
-r~isc. Mechanical and Electrical ~ 195,000
-Structure ~ 30,000
-Val yes and Bifurcations $ 19,000
4. Swi tcl'\Y a rd ~ 179,000
5. Access $ 24,000
6. Transmission $ 38,000
TOTAL DIRECT CONSTRUCTION COSTS ~1,579,000
7. Construction Facilities and Equipment,
Camp, Mobilization, and Demobilization
TOTAL INDIRECT CONSTRUCTION COSTS AT 10 PERCENT ~ 158,000
SUBTOTAL ~1, 737,000
Geographic Factor = 2.3
SUBTOTAL ~3,995,OOO
Contingency at 25 percent ~ 999,000
SUBTOTAL ~4,994,OOO
Engineering and Administration at 15 percent ~ 749,000
TOTAL CONSTRUCTION COST ~5, 743,000
Interest Duri ng Construction at 9.5 percent ~ 546,000
TOTAL PROJECT COST ~6,288,000
Cost per kW Installed Capacity ~ 21,030
ANNUAL COSTS
Annuity at 7-5/8 percent (A/P = 0.07823) $ 491,900
Operations and Maintenance Cost at 1.2 percent 75,500
TOTAL ANNUAL COSTS ~ 567,400 U Cost per kWh ~ 0.69
Benefit-Cost Ratio: 0.63
U
NE/SC AlASKA SMALL HYDRO RECONNAISANCE STUDY
PLANT FACTOR PROGRAM
COMMUNITY: DOT LAKE
SITE NUMBER: 2
NET HEAD (FT): 151.
DESIGN CAPACITY (KW): 699.
MINIMUM OPERATING FLOW (1 UNIT) (CFS) : 7.42
LOAD SHAPE FACTORS: 0.50 0.75 1.60 2.00
HOUR FACTORS: 16.00 15.00 13.00 3.00
MONTH (#DAYS/MO.) AVERAGE POTENTIAL PERCENT ENERGY USABLE
MONTHLY HYDROELECTRIC OF AVERAGE DEMAND HYDRO
FLOW ENERGY ANNUAL ENERGY ENERGY
(CFS) GENERATION (KWH) (KWH)
JANUARY 7.77 59285. 10.00 622458. 39524.
FEBRUARY 6.62 O. 9.50 591335. O.
MARCH 6.43 o. 9.00 560212. O.
APRIL 11.20 82700. 9.00 560212. 55133.
MAY 102.00 520056. 8.00 497966. 323194.
JUNE 157.00 503280. 5.50 342352. 301139.
JULY 105.00 520056. 5.50 342352. 310226.
AUGUST 92.10 520056. 6.00 373475. 312820.
SEPTEMBER 54.20 400207. 8.00 497966. 258276.
OCTOBER 25.60 195329. 9.00 560212. 130219.
NOVEMBER 12.60 93037. 10.00 622458. 62025.
DECEMBER 10.10 77063. 10.50 653581. 51376.
TOTAL 2971070. 6224578. 1843932.
PLANT FACTOR(1997): 0.30
PLANT FACTOR(LIFE CYCLE): 0.30
u-
HYDROPOWER COST DATA -DETAILED RECONNAISSANCE It~VESTIGATIONS
Community: Dot Lake
02 Si te:
Stream: Bear Creek
1.
2.
3.
4.
5.
6.
7.
ITEM
Dam (including intake and spillway)
Penstock
Powerhouse and Equipment
-Turbines and Generators
-Misc. Mechanical and Electrical
-Structure
-Val yes and Bifurcations
Switchyard
kcess
Transmission
TOTAL DIRECT CONSTRUCTION COSTS
Construction .Facilities and Equipment,
Camp, Mobilization, and Demobilization
TOTAL INDIRECT CONSTRUCTION COSTS AT 10 PERCENT
SUBTOTAL
Geographic Factor =
SUBTOTAL
Conti ngency at 25 percent
SUBTOTAL
Engineering and Administration at 15 percent
TOTAL CONSTRUCTION COST
Interest During Construction at 9.5 percent
TOTAL PROJECT COST
Cost per kW Installed Capacity
ANNUAL COSTS
Annuity at 7-5/8 percent (AlP = 0.07823)
Operati ons and r~ai ntenance Cost at 1. 2 percent
TOTAL ANNUAL COSTS
Cost per kWh
Benefit-Cost Ratio:
COST
$ 406,000
$ 905,000
$ 426,000
$ 242,000
$ 30,000
$ 26,000
$ 170,000
$ 18,000
$ 248,000
$ 2,471,000
Z 247,000
$ 2,718,000
2.3
Z 6,252,000
$ 1,563,000
$ 7,815,000
$ 1,172,000
$ 8,987,000
Z 854,000
$ 9,840,000
$ 14,080
$ 769,800
$ 118,100
$ 887,900
$ 0.48
0.91
-u
NE/SC AlASKA SMALL HYDRO RECONNAISANCE STUDY
PLANT FACTOR PROGRAM
COMMUNITY: TOK .
SITE NUMBER: 7
NET HEAD (FT): 353.
DESIGN CAPACITY (KW): 412.
MINIMUM OPERATING FLOW (1 UNIT) (CFS): 1.72
LOAD SHAPE FACTORS: 0.50 0.75 1.60 2.00
HOUR FACTORS: 16.00 15.00 13.00 3.00
MONTH (#DAYS/MO.) AVERAGE POTENTIAL PERCENT ENERGY USABLE
MONTHLY HYDROELECTRI C OF AVERAGE DEMAND HYDRO
FLOW ENERGY ANNUAL ENERGY ENERGY
(CFS) GENERATlON(KWH) (KWH)
JANUARY 1.81 32285. 10.00 622458. 21523.
FEBRUARY 1.54 o. 9.50 591335. O.
MARCH 1.50 o. 9.00 560212. o.
APRIL 2.60 44880. 9.00 560212. 29920.
MAY 23.70 306528. 8.00 497966. 201954.
JUNE 36.60 296640. 5.50 342352. 189209.
JULY 24.40 306528. 5.50 342352. 194565.
AUGUST 21.40 306528. 6.00 373475. 197159.
SEPTEMBER 12.60 217497. 8.00 497966. 144998.
OCTOBER 5.97 106487. 9.00 560212. 70992.
NOVEMBEI{ 2.93 50577. 10.00 622458. 33718.
DECEMBER 2.33 41560. 10.50 653581. 27707.
TOTAL 1709512. 6224578. 1111746.
PLANT FACTOR(1997): 0.31
PLANT FACTOR(LIFE CYCLE): 0.31
u
HYDROPOWER COST DATA -DETAILED RECONNAISSANCE INVESTIGATIONS
Community: Tok
Si te: 07
Stream: C1 earwater Creek
ITEM
1. Dam (including intake and spillway)
2. Penstock
3. Powerhouse and Equipment
-Turbi nes and Generators
-Misc. Mechanical and Electrical
-Structure
-Val yes and Bifurcations
4. SwitchYard
5. Access
6. Transmission
TOTAL DIRECT CONSTRUCTION COSTS
7. Construction Facilities and Equipment,
Camp, Mobilization, and Demobilization
TOTAL INDIRECT CONSTRUCTION COSTS AT 10 PERCENT
SUBTOTAL
Geographic Factor =
SUBTOTAL
Conti ngency at 25 percent
SUBTOTAL
Engineering and Administration at 15 percent
TOTAL CONSTRUCTION COST
Interest Duri ng Construction at 9.5 percent
TOTAL PROJECT COST
Cost per kW Installed Capacity
ANN UAL COSTS
Annuity at 7-5/8 percent (AlP = 0.07823)
Operations and Maintenance Cost at 1.2 percent
-TOTAL ANNUAL COSTS
Cost per kWh
Benefit-Cost Ratio:
COST
$ 500,000
$ 1,169,000
$ 280,000
$ 223,000
$ 30,000
$ 19,000
$ 158,000
$ 47,000
$ 305,000
$ 2,731,000
$ 273,000
$ 3,004,000
2.3
$ 6,909,000
$ 1,727,000
$ 8,637,000
$ 1,296,000
$ 9,932,000
$ 944,000
$10 ,876,000
$ 26,400
$ 850,800
$ 130,500
$ 981,300
0.88
0.50
RECiIONAL INVENTORY & RECONNAI$ANCE STUDY -SMALL HYDROPOWER
ALASKA DISTRICT -CORPS OF ENGINEERS
DETAILED RECONNAISSANCE INVESTIGATIONS
PRO.JECT~~;
COST OF HYDROPOWER -BENEFIT COST RATIO
YEAR
1984
1986
1.9::::7
1'::'190
1991
1.992
199:=:
1994
1995
1'::'96
1997
1998
199':;
2000
:;;:~(l0 1
2002
:;;:~OO:~:
2004
2005
2001;'.
2007
2008
2009
2010
2011
2012
2013
2014
2(11 ~i
2016
2017
::2t) 1:::
2019
2020
2021
Tm<
SITE NO. 7
KWH/YEAR CAPITAL
1079552. 856376.
1082664. 856376.
1085776. 856376.
1088887. 856376.
1091999. 856376.
1094760. 856376.
1097180. 856376.
1099433. 856376.
1101485. 856376.
1103537.856376.
1105590.
1107642.
1109694.
1111746.
1113799.
1115851.
1117903.
1120020.
1121:977.
1123492.
11'25107.
1126411.
1127!::,67.
1128317.
1128980.
1129454.
1129'7127.
11 :;:0547.
11::::1167.
1131787.
11 :3240:::.
1133028.
11 ~::3t::'48.
11 ::::4268 •.
11:3488:3.
11 ::'=:~;508 •
1136128.
113~.541.
113&..954.
1137367.
856376.
85e.376.
856376.
8~56376.
85(:.:37 e· a
856:~:'76.
85c,376.
856376.
:356.:376.
8~i637<' .••
856371:. .•
E:~ic:,37 (:'.
856::::71:.,.
:::56371:. ••
85(:.3'" t:,.
856:376.
!=~56:37 (: .•
85(:,:~:7 6 ••
856376.
856376.
:951:..376.
856::::76.
856376.
85637(: .•
85c,376.
856:376.
2024 1137780.
202~i 11:38110.
2026 11 :38377.
:2027 113E:t.:.45.
2028 11:3:3912.
2029 11:39179.
20:30 11 39354.
AVERAGE COST·
:35637&. .•
S5637e .•
856376.
856:376.
856371:,..
856376.
856376.
856376.
:::56:376.
856376.
o 8< M
1 :'::0500.
130500.
130500.
1:305(10.
1:30500 •.
1:30500.
1 :30500.
1:30500~
1:30500.
1 :30500.
1 :30500.
1 :;:0500.
:1.30500.
130500.
1 :;:0500.
1 ::::0~500.
130500.
130500.
130500.
1 :=:0500.
1:30500.
130500.
130500.
130500. ,
130500.
1,:30500.
130500.
130500.
1:30500.
1:30500.
130500.
130500.
1 :;:0500.
130500.
130500.
1:30500.
130500.
1:'::0500.
130500.
130500.
130500.
130500.
130500.
1 :;i0500.
130500.
1:30500.
130500.
$/!<WH $/KWH
TOTAL$ NONDISC DISC
986876. 0.914 0.681
986876. 0.912 0.631
986876. 0.909 0.585
986876. 0.906 0.542
986816. O~904 ·0.502
986876. 0.901 0.465
986876. 0.899 0.431
986876. 0.898 0.400
986876. 0.896 0.371
986876. 0.894 0.344
98687e .•
98&',876.
986r::Q6.
986871:. .•
':;86876.
98e,:::7t::..
986876.
986876.
986876.
9:3(-..:::71:. ••
98687e .•
986876.
98687e,.
'~!36876.
'::/86876.
98l-:tE:76.
Si 8 1:..::: 7 (:.' •
986876.
986876 .•
9:3687(:o~
986876.
981:..871': .•
986876.
986876.
986876.
986876.
986876.
986876.
986876.
986876.
986876.
9:96876.
':;86871::,.
981:..876.
986876.
986876.
0.891
()a ,:;":::::''9
()" (~:En::
0.881
0.880
0 .. 87:::
0.877
0.876
'().875
0.875
O. :374
(I. F,:7.4
0.87:::'::
o. 87~3
()" E:72
0.872
O. :::;:71
0.871
O. :::7:1.
O. :::f70
0.870
0.869
o. :=:69
O. :'-368
0.86:3
0.86:::
0 .. ::':::19
(J« ~?f3,'(:)
0.:27'1-
t) If ~~!'5e:t
(I .2~::6
0.219
0.:20::?
()., 18:::
0.1.75
0.162
O. 1 ~50
0.140
0.130
0.120
0.11::;~
O. 104
0.096
0.089
O.Of:::::3
0.(177
0.072
0.0/:..7
0.062
0.057
0.05::::
0.04''9
0.046
0.04:::
0.040
0.037
0.034
0.032
0.030
0.027
0.025
0.024
0.022
O. 194
BENEFIT-COST RATIO (5% FUEL COST ESCALATION):
0.867
0.867
0.867
O. :3b7
0.867
O.8e.e.
0.866
0.881
0.50
u
Tana cross Villag e
Man sf ield Villag e
Clearwater Creek DalTlsite
Clearwater Creek Powerhouse
Site
Aerial View of Dot Lake
View Upstream Toward
Bear Creek Damsite
Yerrick Creek Damsite-
Aerial Vi ew
Yerri ck Creek
Channe l of Damsite
u
u
4.0 EAGLE -EAGLE VIllAGE
4.1, COMMUNITY DESCRIPTION
Eagle and Eagle Vfllage are located at the end of the Taylor Highway on
the Yukon River. Eagle, an fncorporated city, fs separated by 3 mfles
of dirt road from Eagle Village, a native community. The two
communities are substantially different fn terms of their social and
economic structure, fnc1udfng the current and predfcted electric energy
requirements. The two communities have been treated as one unit since
the sites that were investigated could serve both Eagle and Eagle Vi 11 age. .
4.1.1 Eagle
Eagle has a population of 164 distributed among 62 households. The
city has 6 stores, l'ibrary, city hall, BlM office, restaurant, 2
historical museums, and several buildings that, as part of Fort Egbert,
have been restored. Additfonal houses, not presently served with
electriCity, are removed from the community center, which would make
the installation of distribution lfnes costly.
The electric system is owned and operated by Ralph Helmer, an Eagle
resident. Current demand is exceedi ng the capacity of the 22.5 kW
diesel generator, which is operatfng 24 hours/day. Eagle has grown fn
population fn the last 5 years and total electricity demand has been
increased. A 50 kW diesel generator fs planned to be fnstalled fn the
spri Og of 1982. The cost of power is 38 cents/kWh and all 40
households that use e1ectrfcfty are metered. The cost of dfese1 fuel
fs SI.35/gallon. load fs heavfest durfng the summer when there are
more resfdents and operatfon of freezers fs greatest. Indfvfdua1
generators are operated to supplement the city power system and are
used to run power tools. Household end uses of e1ectrfcity fnclude
most modern appliances and a few households have vfdeo machines. More
appliances would be acquired if the cost of power was reduced. Wood
burnfng fs the princfpal method for space heatfng (90 percent) followed
by oil burners (10 percent).
The economy of Eagl e f s based on tourf sO) and a few jobs wf th the
government. Newcomers usually do not ffnd jobs. The upgradfng of the
Taylor Highway and its bridges and construction of a school are two
projects fn the planning stage that may employ local people. Several
small gold clafms are worked in the area.
4.1.2 Eagle Village
Eagle Village is an Athabascan community with a subsfstence economy of
fishing and trapping. In recent years Eagle Vfllage has been losing
residents and the current popu1atfon fs 54. The school for the two
4-1
communities is located in Eagle Village and educates students in grades
1 through 12. Residences are without electricity although the HUD
houses are wired for electrical appliances. Electricity at the school
is provided by 2 -85 kW diesel generators. The community hall has a
10 kW generator to meet the lighting and small appliance needs.
One project that may stimulate growth is the proposed asbestos mining
operation approximately 30 miles to the south in the Slate Creek area
owned by the native corporation Doyon Ltd. If thi s project
materializes, it may employ as many as 3,000 persons.
4.2 SITE SELECTION
Field inspection was narrowed down to two sites after having eliminated
the upstream site on Mission Creek (Site No. 03) due to relative
difficulty of access and the downstream site at junction with Excelsior
Creek due to its immediate proximity to the Tintina Fault. For the
remaining site, the subsequent overflight of Boundary Creek and of the
possible transmission line routes to Site No. 05 confirmed that access
both to this project area and to considerable sections of its
transmission line could involve major expense and would not be feasible
along the Yukon River.
The proposed dam location at Site No.1 was visited and measurement
made of flow in American Creek. A concrete intake dam with a central
overflow section was assumed to bridge the two hundred foot wide plain
within which the fifty foot wide creek flows. No bedrock exposures on
the abutments coul d be observed due to scree cover. Stream bed
material consists of up to two-foot sized oblong boulders and two to
four inch gravel. The topographY of the site is admirably suited to a
several hundred foot high dam, with a spillway through the right
abutment spur. Such a development, which could not be economically
justified at present, involving also major relocation of the Taylor
Highway that follows the valley some forty feet above the creek, was
not investigated as part of this study.
The intake for the proposed dam would be located 50 to 100 feet
upstream of it, thus avoiding danger of burial by bed material
transported and deposited during floods.
Because the flow in American Creek appears to practically cease duri ng
the winter months, it is proposed that the powerplant be a single unit
plant.
All the elements of the proposed development have ideal access
conditions from Taylor Highway.
4-2 u
u
NOTE: TOPOGRAPHY FROM U.S.G.S.-EAGLE
ALASKA, 1:250,000
LEGEND
• DAM SITE
• POWERHOUSE o SITE NO.
-----PEN STOCK
---TRANSMISSION LINE
--WATERSHED
5 o 5
E3 t==t E3
SCALE I N MILES
REGIONAL INVENTORY a RECONNAISSANCE STUDY
SMALL HYDROPOWER PROJECTS
NORTHEAST ALASKA
HYDROPOWER SITES IDENTIFIED
IN PRELIMINARY SCREENING
EAGLE VILLAGE
DEPARTMENT OF THE ARMY
ALASKA DISTRICT CORPS OF ENGINEERS
REG IOH1\L INVENTORY & RECONNAISANCE STUDY -SMALL HYDROPOVJER PROJEC'rs
ALASKA DISTRICT -CORPS OF ENGINEERS
U LOAD FORECAS'r -EAGLE
KILOWATT-HOURS PER YEAR ANNUAL PEAK DEr-1AND-KW
YEAR LO\~ MEDIUM HIGH LOW MEDIU~l HIGH
1980 656000. 656000. 656000. 225. 225. 225.
1981 683436. 683436. 683436. . 234. 234 • 234.
1982 710871. 710871. 710871. 243. 243. 243.
1983 738307. 738307. 738307. 253. 253. 253.
1984 765743. 765743. 765743. 262. 262. 262.
1985 793178. 793178. 793178. 272. 272. 272.
1986 820614. 820614. 820614. 281. 281. 281.
1987 84f!049. 8480'49. 848049. 290. 290. 290.
1988 875485. 875485. 875485. 300. 300. 300.
1989 902921. 902921. 902921. 309. 309. 309.
1990 930356. . 930356. 930356 • 3i9. 319. 319.
1991 954100. 996344. 1038588. 327. 341. 356.
1992 977844. 1062332. 1146820. 335. 364. 393.
1993 1001588. 1128320. 1255052. 343. 386. 430.
1994 1025332. 1194309. 1363285. 351. 409. 467.
1995 1049076. 1260297. 1471517. 359. 432. 50'1.
1996 1072820. 1326285. 1579749. 367. 454. 541.
1997 1096564. 1392273. 1687981. 376. 477. 578.
1998 112030B. 1458261. 1796213. 384. 499. 615.
1999 1144052. 1524249. 1904445. 392. 522. 652.
2000 1167796. 1590237. 2012677. 400. 545. 6B9.
2001 1181545. 1659794. 2138042. 405. 568. 732.
2002 1195294. 1729350. 2263406. 409. 592. 775.
2003 1209042. 179B907. 2388771. 414. 616. 8113.
2004 1222791. 1868464. 2514135. 419. 640. 861.
2005 1236540. 1938020. 2639500. 423. 664. 904.
2006 1250289. 2007577. 2764864. 428. 688. 947.
2007 1264037. 2077133. 2890229. 433. 711-990.
2008 1277786. 2146690. 3015593. 438. 735. 1033.
2009 1291535. 2216247. 3140958. 442. 759. 1076.
2010 1305284. 2285803. 3266322. 447. 783. 1119.
2011 1321935. 2318196. 3314456. 453. 794. 1135.
2012 1338587. 2350589. 3362590. 458. 805. 1152.
2013 1355238. 2382981. • 3410724. 464. 816. 1168.
2014 1371890. 2415374. 3458858. 470. 827. 1185.
2015 1388541. 2447767. 3506992. 476. 838. 1201.
2016 1405192. 2480160. 3555126. 481. 849. 1218.
2017 1421844. 2512552. 360.1260. 487. 860. 1234.
2018 1438495. 2544945. 3651394. 493. 872. 1250.
2019 1455146. 2577338. 3699528. 498. 883. 1267.
2020 1471798. 2609730. 3747661. 504. 894. 1283.
2021 1485385. 2641585. 3797785. 509. 905. 1301.
2022 1498972 • 2673440. 3847908 .• , 513. 916. 1318.
2023 1512558. 2705295. 3898032. 518. 926. 1335.
2024 1526145. 2737150. 3948155. 523. 937. 1352.
2025 1539732. 2769005. 3998279. 527. 94B. 1369.
2026 1553319. 2800860. 4048402. 532. 959. 1386.
U 2027 1566905. 2832715. 4098526. 537. 970. 1404.
2028 1580492. 2864570. 4148649. 541. 981. 1421.
2029 1594079. 2896425. 4198773. 546. 992. 1438~
2030 1607666. 2928280. 4248896. 551. 1003. 1455.
REGIONAL INVENTORY & RECONNAISANCE STUDY -SMALL HYDROpmvER PROJECTS
ALASKA. DISTRICT -CORPS OF ENGINEERS
LOAD FORECAS'l' -EAGLE VILLAGE·
KILOWATT-HOUHS PER YEAR ANNUAL PEAK DEMANIJ-KW
,""~-
YEAR LOW MEDIUlJJ HIGH LOW MEDIUfvl HIGH
1980 O. O. O. O. O. O.
1981 25068. 25068. 25068. 9. 9. 9.
1982 50135. 50135. 50135. 17. 17. 17.
1983 75203. 75203. 75203. 26. 26. 26.
1984 100271. 100271. 100271. 34. 34. 34.
1985 125339. 125339. 125339. 43. 43. 43.
1986 150406. 150406. 150406. 52. 52. 52.
1987 175474. 175474. 175474. 60. 60. 60.
1988 200542. 200542. 200542. 69. 69. 69.
1989 225609. 225609. 225609. 77. 77. 77.
1990 250677. 250677. 250677. 86. 86. 86.
1991 261161. 275071. 288980. 89. 94. 99.
1992 271645. 299464. < 327283. 93. 103. 112.
1993 282129. 323858. 365587. 97. 111. 125.
1994 292613. 348251. 403890. 100. 119. 138.
1995 303097. 372645. 442193. 104. 120. 15"
1996 313580. 397038. 480496. 107. 136. 165.
1997 324064. 421432. 518799. 1 11. 144. 178.
1998 334548. 445825. 557103. 115. 153. 191.
1999 345032. 470219. 595406. 118. 161. 204.
2000 355516. 494612. < 633709. 122. 169. 217.
2001 364589. 522061. 679534. 125. 179. 233.
2002 373663. 549510. 725358. 128. 188. 248.
2003 382736. 576959. 771183. 131. 198. 264.
2004 391809. 604408. 817008. 134. 207. 280.
2005 400883. 631858. 862832. 137. 216. 295.
2006 409956. 659307. 908657. 140. 226. 311.
2007 419029. 686756. 954482. 144. 235. 327.
2008 42R103. 714205. 1000307. 147. 245. 343.
2009 < 437176. 741654. 1046131. 150. 254. 358.
2010 446249. 769103. 1091956. 153. 263. 374.
2011 451503. 779540. 1107576. 155. 267. 379.
2012 456757. 789977. 1123196. 156. 271. 385.
2013 462010. 800414. 1138816. 158. 274. 390.
2014 467264. 810851. 1154437. 160. 278. 395.
2015 472518. 821287. 1170057. 162. 281. 401.
2016 477772. 831724. 1185677. 164. 285. 406.
2017 483026. 842161. 1201297. 165. 288. 411.
2018 488280. 852598. 1216917. 167. 292. 417 •
2019 493533. <863035. 1232537. 169. 296. 422.
2020 498787. 873472. 1248157. 171. 299. 427.
2021 505150. 885850. 1266550. 173. 303. 434.
2022 511513. 898228. 1284944. , 175. 30B. 440.
2023 517376. 910607. 1303337. 177 • 312. 446.
2024 524239. 922985. 1321731. 180. 316. 453.
2025 530602. 935363. 1340124. 182. 320. 459.
2026 536965. 947741. 1358517 • 184. 325. 465.
2027 543328. 960119. 1376911. 186. 329. 472. U 2028 549691. 972498. 1395304. 188. 333. 478.
2029 556054. 984876. 1413697. 190. 337. 484.
2030 562417. 997254. 1432091. 193. 342. 490.
I U
NE/SC ALASKA SMALL HYDRO RECONNAISANCE STUDY
PLANT FACTOR PROGRAM
COMMUNITY: EAGLE
SITE NUMBER: 1
NET HEAD (FT): 269.
DESIGN CAPACITY (KW): 59.
MINIMUM OPERATING FLOW (1 UNIT) (CFS) : 0.64
LOAD SHAPE FACTORS: 0.50 0.75 1.60 2.00
HOUR FACTORS: 16.00 15.00 13.00 3.00
MONTH (HDAYS/MO.) AVERAGE POTENTIAL PERCENT ENEHGY USAljLE
MUNTHLY HYDROELECTRIC OF AVERAGE DEMAND HYI.)RO
FLOW ENERGY ANNUAL ENERGY ENERGY
(CFS) GENERATION (KWH) (KWH)
JANUARY 0.08 o. 10.00 109656. O.
FEBRUARY 0.08 o. 9.50 104174. O.
MARCH 0.08 o. 9.00 98691-O.
APRIL 2.89 38015. 9.00 98691. 25344.
MAY 104.00 43896. 8.00 87725. 29263.
JUNE 75.60 42480. 5.50 60311. 27806.
JULY 32.40 43896. 5.50 60311. 28691-
AUGUST 40.20 43896. 6.00 65794. 28806.
SEPTEMBER 28.30 42480. 8.00 87725. 28320.
OCTOBER 5.11 43896. 9.00 98691. 29264.
NOVEMliER 0.83 10918. 10.00 109656. 7279.
DECEMI>ER 0.13 O. 10.50 115139. O.
TOTAL 309477 • 1096564. 204772.
PLANT FACTOR(1997): 0.40
PLANT FACTOR(LIFE CYCLE): 0.40
U
u
u
HYDROPOWER COST DATA -DETAILED RECONNAISSAt~CE INVESTIGATIONS
Community: Eagle
Site: 01
Stream: American Creek
ITEM
1. Dam (including intake and spillway)
2. Penstock
3. Powerhouse and Equipment
-Turbines and Generator~
-Misc. Mechanical and Electrical
-Structure
-Val yes and Bifurcati ons
4. Switchyard
5. Access
6. Transmission
TOTAL DIRECT CONSTRUCTION COSTS
7. Construction Facilities and Equipment,
Camp, Mobilization, and Demobilization
TOTAL INDIRECT CONSTRUCTION COSTS AT 10 PERCENT
SUBTOTAL
Geographic Factor =
SUBTOTAL
Contingency at 25 percent
SUBTOTAL
Engineering and Administration at 15 percent
TOTAL CONSTRUCTION COST
Interest During Construction at 9.5 percent
TOTAL PROJECT COST
Cost per kW Installed Capacity
ANNUAL COSTS
Annuity at 7-5/8 percent (AlP = 0.07823)
Operations and Maintenance Cost at 1.5 percent
TOTAL ANNUAL COSTS
Cost per kWh
Benefit-Cost Ratio:
COST
$ 352,000
$ 377,000
$ 34,000
$ 143,000
$ 15,000
$ 6,000
~ 106,000
$ 0
$ 138,000
$ 1,171,000
$ 117,000
$ 1,288,000
2.6
$ 3,349,000
$ 837,000
$ 4,186,000
$ 628,000
$ 4,814,000
$ 457,000
$ 5,272,000
$ 89,360
$ 412,400
$ 79,100
$ 491,500
$ 2.41
0.22
REGIONAL INVENTORY & RECONNAISANCE STUDY -SMALL HYDROPOWER 'PROJECTS
ALASKA DISTRItT'~ tORPS OF ENGINEERS
DETAILED RECONNAISSANCE INVE!:::TIC;ATIONS U
COST OF HYDROPOWER -BENEFIT COST RATIO
EAGLE
~;ITE NO. 1
YEAR KWH/YEAR
19::::4 199294.
19:35 199877.
19::::6 200460.
19:'37 2010::::7.
1 r~::::=: :;:~() 15t.9.
19:39 202100.
1990 2026:32.
1 ';I'~/l 203092.
1'::-/~)2 2():35:39.
1 '~/j)~: ~:():3E:65.
1994 204192.
1 ~;195 204452.
19';)6 204649.
1997 204772.
199:3 204858.
1999 204942.
2000 205026.
2001 205075.
2002 205124.
2003 20!::i 1 72.
2004 205221 .
:2005 205270.
2006 205:318.
2007 205367.
20(1:::: 205416.
2009 205464.
2010 205513.
2011 205572.
2012 2056:31.
201:3 205690.
201.4 205749.
2015 205808.
2016 205867.
201 7 20!:i92~,.
2(J 1 :::: 2059:::5.
20 1 '~) 206044.
2020
2021
2()2:2
;~()2:~:
2024
2025
2027
:2()2:?
~:();~';J
20:30
206092.
20t.123.
206154.
2061::::5 •
206217.
206248.
206269.
206285.
206:300.
20631~, •
206:318.
CAPITAL
415117.
415117.
415117.
415117.
415117.
415117.
415117.
415117.
415117.
415117.
415117.
415117.
415117.
415117.
415117.
415117.
415117.
415117.
415117.
415117.
415117.
415117.
415117.
415117.
415117.
415117.
415117.
41!:il17.
415117.
415117.
415117.
415117.
415117.
415117.
415117.
415117.
415117.
415117.
41.5117.
415117.
415117.
415117.
415117.
415117.
415117.
41.5117.
415117.
o ~I, M
79100.
79100.
79100.
79100.
79100.
79100.
79100.
79100.
79100.
79100.
79100.
79100.
79100.
79100.
79100.
79100.
79100.
79100.
79100.
79100.
79100.
79100.
79100.
79100.
7',?100.
79100.
79100.
79100"
79100.
79100.
79100.
79100.
'79100.
79100.
79100.
79100.
79100.
79100.
79100.
79100.
79100.
79100.
79100.
79100.
79100.
79100.
79100.
$/KWH $/KWH
TOTAL$ NONDISC DISC
494217. 2.480 1.848
494217. 2.473 1.712
494217. 2.465 1.586
494217. 2.458 j.470
494217. 2.452 1.362
494217. 2.445 1.262
494217. 2.439 1.170
494217. 2.433 1.084
494217. 2.428 1.005
494217. 2.424 0.933
494217. 2.420 0.865
494217. 2.417 0.803
494217. 2.415 0.745
494217. 2.414 0.692
494217. 2.412 0.643
494217. 2.411 0.597
494217. 2.411 0.554
494217. 2.410 0.515
494217. 2.409 0.478
494217. 2.409 0.444
494217. 2.408 0.418
494217. 2.408 0.883
494217. 2.407 0.356
494217. 2.407 0.331
494217~ 2.406 0.307
494217. 2.405 0.286
494217. 2.405' 0.265
494217. 2.404 0.246
494217. 2. 40:3 (I. 2~·:S'1
494217. 2.403 0.213
494217. 2.402 0.197
494217. 2.401 0.183
494217. 2.401 0.170
494217. 2.400 0.158
494217. 2.399 0.147
494217. 2.399 0.137
494217. 2.398 0.127
494217. 2.398 0.118
494217. 2.397 0.109
494217. 2.397 0.102
494217. 2.397 0.094
494217. 2.396 0.088
494217. 2.396 0.082
494217. 2.396 0.076
494217. 2.396 0.070
494217. 2.395 0.065
494217. 2.395 0.061
AVERAGE COST 2.414 0.~527
BENEFIT-COST RATIO (5% FUEL COST ESCALATION): 0.22
u
Eagle-Eagle Vill age, Alaska
Aerial Vi ew of Ea gle
Aerial Vi ew of Ea gle Village
American Creek Damsite and
Existing Access Roa d
. .,.
, .
Z' ... ---
5. 0
SCALE IN MILES
.NOTEa·lOPOGRAPHY FROM us.G.S.-MT. HAYES
. ALASKA, I' 250,000
""'I"'~ / I..: &. .. "''-''
, tit· . . :.: .. • • ...
oov
<:) ,
" <.1
II D
LEGEND
... DAM SITE • o SITE NO.
•• -. -PENSTOCK
UNE
HYatOPOWER SITES IDENTIFIED
IN PREUMINARY SCREENING
DELTA JUNCTION
DEPARTMENT OF THE ARMY'
ALASKA DISTRICT CORPS OF ENGINEERS
".;" ;,1,'
t.~
Z~F ___ -
5
SCALE IN MILES
NaTE' TOPOGRAPHY FROM U. S. G. S. -FAIRBANKS
ALASKA. 1:250.000 '
LEGEND \
~ DAM SIT~
• POWERH SE o SITE NO.
- - - --PENSTOCK~
---TRANSMIS ION
-WATERSH 0
LINE'
REGIONAL INVENTORY a RECONNAISSANCE STUDY
SMALL HYDROPOWER PROJECTS
NORTHEAST .ALASKAI' z....
HYDROPOWER SITES IDENTIFIED
IN PREUMINARY SCREENING
CHENA
DEPARTMENT OF THE ARMY
ALASKA DISTRICT CORPS OF ENGINEERS
u
SUMMARY DATA SHEET
DETAILED INVESTIGATIONS
BIG DELTA-DELTA JUNCTION, ALASKA
~dropower Potenti a 1
Cost of
Installed Installed Alternajive Cost of
Capacity Cost Power_/ ~dropower
Si te No. (kW) (SlOOO) (mi 11 s/kWh) (mi lls/kWh)
2 612 12,692 324 490
Demographic Characteristics
1981 Population Big Delta -30; Delta Junction -945
1981 Number of Households: Big Delta -9; Delta Junction -270
Economic Base
Unknown
11 5 Percent Fuel Escalation, Capital Cost Excluded.
Benefit/Cost
Ratio
0.66
See Appendix C (Table C-8) for example of method of computation of
cost of alternative power.
Hldro~ower Potential
Installed
Capacity
Si te No. (kW)
3 1,028
2 108
1 91
Demographic Characteristics
1981 Population: 35
SUMMARY DATA SHEET
PRELIMINARY SCREENING
CHEN A, ALASKA
Cost of
Installed Alterna\}ve
Cost Power-
(S1000 ) (mills/kWh)
12,215 324
2,148 324
2,576 324
1981 Number of Households: 10
Economic Base
Unknown
11 5 Percent Fuel Escalation, Capital Cost Excluded.
Cost oJ
Jiydropower Benefit/Cost
(mi 11 s/kWh) Ratio
296 1.09
406 0.80
577 0.56
REGIONAL INVENTORY & RECONNAISANCB STUDY -SMALL HYDROPOWER PROJECTS
ALASKA DISTRICT -CORPS OF l::NGINEERS
LOAD FORECAST -BIG D;ELTA
~ KILOWATT-HOURS PER YEAR ANNUAL PEAK DEMAND-KW
YEAR LOW MEDIUM HIGH LOW MEDIUM HIGH
1980 128571. 128571. 128571. 44. 44. 44.
1981 133091. 133091. 133091. 46. 46. 46.
1982 137610. 137610. 137610. 47. 47. 47.
1983 142130. 142130. 142130. 49. 49. 49.
1984 146649. 146649. 146649. 50. 50. 50.
1985 151169. 151169. 151169. 52. 52. 52.
1986 155688. 155688. 155688. 53; 53. 53.
1987 160208. 160208. 160208. 55. 55. 55.
1988 164727. 164727. 164727. 56. 56. 56.
1989 169247. 169247. 169247. 58. 58. 58.
1990 173766. 173766. 173766. 60. 60. 60.
1991 178002. 187937. 197873. 61-64. 68.
1992 182238. 202109. 221980. 62. 69. 76.
1993 186474. 216280. 246086. 64. 74. 84.
1994 190710. 230452. 270193. 65. 79. 93.
1995 194946. 244623. 294300. 67. 84. 101.
1996 199181. 258794. 318407. 68. .89. 109.
1997 203417 • 272966. 342514. 70. 93. 117.
1998 207653. 287137. 366620. 71. 98. 126.
1999 211889. 301309. 390727. 73. 103. 134.
2000 216125. 315480. 414834. 74. 108. 142.
2001 220493. 332974. 445453. 76. 114. 153.
2002 224861. 350467. 476072 • 77. 120. 163.
2003 229229. 367961. 506691. 79. 126. 174.
2004 233597. 385454. 537310. 80. 132. 184.
2005 237965. 402948. 567930. 81. 138. 194.
2006 242334. 420442. 598549. 83. 144. 205.
2007 246702. 437935. 629168. 84. 150. 215.
2008 251070. 455429. 659787. 86. 156. 226.
2009 255438. 472922. 690406. 87. 162 .• 236.
2010 259806. 490416. 721025. 89. 168. 247.
2011 265528. 499840. 734151. 91. 171. 251.
2012 271250. 509264. 747278. 93. 174. 256.
2013 276972 • 518688. 760404. 95. 178. 260.
2014 282694. 528112. 773531. 97. 181-265.
2015 288416. 537537. 786657. 99. 184. 269.
2016 294137. 546961. 799783. 101-187. 274.
2017 299859. 556385. 812910. 103. 191-278.
2018 305581. 565809. 826036. 105. 194. 283.
2019 311303. 575233. 839162. 107. 197. 287.
2020 317025. 584657. 852289. 109. 200. 292.
2021 320836. 592764. 864693. 110. 203. 296.
2022 324646. 600872 • 877097. 111. 206. 300.
2023 328457. 608979. 889501. 112. 209. 305.
2024 332268. 617086. 901905. 114. 211. 309.
2025 336078. 625194. 914308. 115. 214. 313.
2026 339889. 633301. 926712. 116. 217. 317.
2027 343700. 641408. 939116. 118. 220. 322.
U 2028 347511. 649516. 951520. 119. 222. 326.
2029 351321. 657623. 963924. 120. 225. 330.
2030 355132. 665730 •. 976328. 122. 228. 334.
REGIONAL I;-';VENTOHY &. RECONNAISANCE STUDY -SMAI.L HYDROPOWER PROJECTS
ALASKA DISTRICT -CORPS OF ENGINELHS
YEAH
1980
1981
1982
19B3
19B4
19B5
1986
19137
1':lB8
19139
1990
1 C) 91
1 Cj 92
1993
1994
1995
19%
1997
199U
1999
2000
2001
2U(l2
2003
2(104
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
20~!2
2023
2024
2025
2026
2027
20'::B
2(J~9
2030
LOAD FORECAST -DELTA JUNCTION
KILOt-1A'I"f-1l0UHS 1'1::R Yli:AR
LOH
4050000.
4192364.
4334729.
4477093.
4619457.
4761821.
4904185.
5046549.
51H8913.
5331277.
5473G42.
5607072.
5740502.
5873932.
6LJ07362.
6140792.
6:::74222.
6407652.
6541082.
6674512.
6807943.
6945537.
7083131-
7:n0725.
7358319.
7495913.
7633507.
7771101.
7908695.
8046289.
8183882.
8364124.
85<J4366.
8724608.
8904E50.
9085092.
92653.34.
')445576.
9625818.
9806060.
9986301.
10106338.
10226375.
10346412.
10466449.
1 1l5B648().
111706523.
1082CSGO.
1 094r,597 •
11066634.
11186671.
P.EDIUH
4050000.
4192364.
4334729.
4477093.
4619457.
4761821.
4904185.
5046549.
5188913.
5331277.
5473642.
5920039.
6366436.
6H12833.
7259230.
7705627.
8152024.
8598421.
9044818.
9491215.
9937610.
104B8658.
11039706.
11590754.
12141802.
12692!:l50.
13243898.
13794946.
14345994.
14897042.
15'141-1091 •
15744953.
1f,041H15.
1633H677.
16635539.
16932400.
1722Q 262.
17526124.
17e22906.
1!J119848.
18416708.
16672086.
1B927464.
19182842.
19438220.
19()')35gB.
199413976.
202U4354.
20459732.
20715110.
20970488.
IUGH
4050000.
4192364.
4334729.
4477093.
4619457.
4761821.
4904185.
5046549.
51AB913.
5331277.
5473642.
6233006.
6992369.
7751733.
~3511096.
9270460.
10029624.
10789188.
11548552.
1230791(:i.
13067277.
1403177'.:).
149962131.
15960783.
169252Cl6.
178f~97S8 •
11:3854290.
198113792.
20783294.
21747796.
22712300.
23125782.
23539264.
23g52746.
2436(,22H.
24779710.
25193192.
25606674.
26020156.
26433631'1.
26847116.
27237836.
27628556.
2R019276.
21:3409996.
28800716.
29191436.
295821%.
29972H76.
30363596.
30754316.
I,Nl-iUAL PEAK UENANIJ-KW
LOVJ f1EDIur·! U IGH
1387. 1387. 1387.
1436. 1436. 1436.
1484.
1533.
1582.
1631.
1680.
1728.
1777.
1026.
1875.
1920.
1966.
2012.
2057.
2103.
2149.
2194.
22411.
2286.
2331.
2379.
2,l2().
2473 •
2520.
2567.
2614.
2661.
non.
2756.
2~W3.
2864.
2926.
2988.
3050.
3111.
3173.
3235.
3297.
335n.
3420.
34n 1.
3502.
3543.
3584.
362().
3()f';7.
J708.
3749.
3790.
3831.
1484.
1533.
1582.
1631.
1680.
1728.
1777 •
1826.
1875.
2027.
2180.
2333.
24!l6.
2G3'.:l.
27Y2.
2945.
30')H.
3250.
3 i lt)) •
35')2.
3781.
3969.
41513.
4347.
4536.
4724.
4(")13.
5102.
52C)O.
5392.
5494.
5595.
5697.
5799.
5c)OO.
6002.
6104.
6205.
6307.
6395.
64d2.
6569.
6657.
(,744.
6flJ2.
(,:)19.
7007.
7094.
7H32.
1484.
1533.
1582.
1631.
1680.
172B.
1777.
1H26.
1875.
2135.
2395.
2655.
2915.
3175.
3435.
3f)95.
3':55.
4215.
4475.
4B05.
5136.
5466.
57%.
6127.
6457.
6787.
71113.
74413.
7778.
7920.
cj061.
8203.
8345.
B48G.
862t, •
8769.
8911.
9053.
919t1.
9328.
9t16?.
9596.
9729.
98b3.
9997.
10131.
lu2fi5.
1039<:3.
10532.
u
u
HYDROPOWER COST DATA -DETAILED RECONNAISSANCE INVESTIGATIONS
Community: Big Delta/Delta Junction
Site: 02
Stream: Granite Creek
ITEM
1. Dam (including intake and spl1lway)
2. Penstock
3. Powerhouse and Equipment
-Turbi nes and Generators
-Misc. Mechanical and Electrical
-Structure
-Val yes and Bifurcations
4. SwftcJ\yard
5. Access
6. Transmission
TOTAL DIRECT CONSTRUCTION COSTS
7. Construction Facilities and Equipment,
Camp, Mobil1 zation, and Demobl1 i zatfon
TOTAL INDIRECT CONSTRUCTION COSTS AT 10 PERCENT
SUBTOTAL
Geographic Factor =
SUBTOTAL
Contingency at 25 percent
SUBTOTAL
Engineering and Administration at 15 percent
TOTAL CONSTRUCTION COST
Interest During Construction at 9.5 percent
TOTAL PROJECT COST
Cost per kW Installed Capacity
ANNUAL COSTS
Annuity at 7-5/8 percent (A/P = 0.07823)
Operations and Mai ntenance Cost at 1. 2 percent
TOTAL ANNUAL COSTS
Cost per kWh
Benefit-Cost Ratio:
COST
$. 385,000
$ 1,133,000
$ 420,000
$ 294,000
S 30,000
$ 19,000 , 180,000 , 33,000
$ 838 1 000
, 3,332,000
, 333,000
, 3,665,000
2.2
, 8,063,000
, 2,016,000
'10,079,000
$ 1,512,000
'11,591,000
$ 1,101,000
$12,692,000
$ 20,700
$ 992,900
, 152,300
$ 1,145,200
$ 0.49
0.66
H~U!UNAL INVENTORY & RECONNAISANCE STUDY -SMALL HYDROPOWER PROJECTS
ALASKA DISTRICT -CORPS OF ENGINEERS
YEAR
1984
1985
1986
1987
1988
1989
1990
1991
1~2
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
DETAILED RECONNAISSANCE INVESTIGATIONS
COST OF ~YDROPOWER -BENEFIT COST RATIO
BIG DELTA/DELTA JUNCTION
SITE NO. 2
KWH/YEAR
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2~58900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
2358900.
CAPITAL a & M
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 1523(~.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368.. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152800.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
999368. 152300.
$/KWH $/KWH
TOTALS NONDISC DISC
1151668. 0.488 0.364
1151668. 0.488 0.338
1151668. 0.488 0.314
1151668. 0.488 0.292
1151668. 0.488 0.271
1151668. 0.488 0.252
1151668. 0.488 0.234
1151668. 0.488 0.218
1151668. 0.488 0.202
1151668. 0.488 0.188
1151668. 0.488 0.175
1151668. 0.488 0.162
1151668. 0.488 0.151
1151668. 0.488 0.140
1151668. 0.488 0.130
1151668. 0.488 0.121
1151668. 0.488 0.112
1151668. 0.488 0.104
1151668. 0.488 0.097
1151668. 0.488 0.090
1151668. 0.488 0.084
1151668. 0.488 0.078
1151668. 0.488 0.072
1151668. 0.488 0.067
1151668. 0.488 0.062
1151668. 0.488 0.058
1151668. 0.488 0.054
1151668. 0.488 0.050
1151668. 0.489 0.046
1151668. 0.488 0.043
1151668. 0.488 0.040
1151668. 0.488 0.037
1151668.. 0.488 0.035
1151668. 0.488 0.032
1151668. 0.488 0.030
1151668. 0.488 0.028
1151668. 0.488 0.026
1151668. 0.488 0.024
1151668. 0.4880.022
1151668.
1151668.
1151668.
1151668.
1151668.
1151668.
1151668.
1151668.
AVERAGE COST
0.488 0.021
0.488 0.019
0.488 0.018
0.488 0.017
0.488 0.015
0.488 0.014
0.488 0.013
0.488 0.012
0.488 0.106
0.66 BENEFIT-COST RATIO (5% FUEL COST ESCALATION):
u
z· ... _--
5 0
F3 It E3
SCALE IN MILES
I '
i
NOTEs TOPOGRAPHY FROM U.S.G.S.-BARTER ISLAND
ALASKA, 1:~tOOO
5
LEGEND I
", DAM SITE \
• POWERHOU E o SITE NO.
-----PENSTOCK
---TRANSMISS ON UNE'
-WATERSHE
/
/
/
/
/"0
/
,'C
REGIONAL INVENTORY a RECONNAISSANCE srUDr
SMALL HYDROPOWER PRO.JECTS
NORTHEAST .AlASKA!
HYDROPOWER SITES IDENTIFIED
IN PREUMINARY SCREENING
KAKTOVIK
DEPARTMENT OF THE ARMY
ALASKA DISTRICT CORPS OF ENGINEERS
u
SUMMARY DATA SHEET
PRELIMINARY SCREENING
KAKTOVIK/BARTER ISLAND. ALASKA
Hvdro~ower Potential
Installed Installed
Capacity Cost
Si te No. (kW) ('1000)
2 404 6 .. 939
1 535 11 .. 517
Demographic Characteristics
1981 Population: 165
1981 Number of Households: 47
Economic Base
Constructi on
Government
Cost of
Al ternati ve
Power.lI
(mill s/kWh)
612
612
11 5 Percent Fuel Escalation. Capital Cost Excluded.
Cost of
~dropower
(mill s/kWh)
566
915
Benefit/Cost
Ratio
1.08
0.67
REGIONAL INVENTORY & RECONNAISANCE STUDY -SMALL HYDROPOWER PROJECTS
. ALASKA DISTRICT -CORPS OF ENGINEERS
LOAD FORECAST -KAKTOVIK/BARTJo:J{ ISLAND
KILOWA'l"l'-lIOUHS PER YEAR ANNUAL PEAK DEMAND-KN
YEAR LOt-J r·1EDIUN HIGH LO\v MEDIUM HIGH·
1980 707143. 707143. 707143. 242. 242. 242.
1981 732000. 732000. 732060. 251 ~ 251. ·251.
1982 756857. 756857. 756857. 259. 259. 259.
1983 781715. 781715. 781715. 268. 268. 268.
1984 806572. 806572 • 806572. 276. 276. 276.
1985 831429. 831429. 831429. . 285. 285 • 285.
19B6 856286. 856286. 856286. 293. 293. 293.
1987 881143. 881143. 881143. 302. 302. 302.
1988 906001. 906001. 906001. 310. 310. 310".
1989 930858. 930858. 930858. 319. 319. 319.
1990 955715. 955715. 955715. 327. 327. 327.
1991 979012. 1049253. 1119494. 335. 359. 383.
1992 1002310. 1142792. 1283273. 343. 391. 439.
1993 1025607. 1236330. 1447052. 351. 423. 496.
1994 1048904. 1329868. 1610831. 359. 455. 552.
1995 1072202. 1423406. 1774610. 367. 487. 608.
1996 1095499. 1516945. 1938389. 375. 520. 664.
1997 1118796. 1610483. 2102168. 383. 552. 720.
1998 1142093. 1704021. 2265947. 391. 584. 776.
1999 1165391. 1797559. 2429726. 399. 616. 832.
2000 1188688. 1891097. 2593505. 407. 648. 888.
2 no 1 1212712. 2007915. 2803117. 415. 688 •. 960.
2002 1236737. 2124733. 3012729. 424. 728. 1032.
2003 1260761. 2241551. 3222341. 432. 760. 1104.
2004 1284786. 2358369. 3431953. 440. 808. 1175.
2005 1308810. 2475187. 3641565. 448. 848. 1247.
2006 1332834. 2592005. 3851177. 456. 888. 1319.
2007 1356859. 2708823. 4060789. 465. 928. 1391.
2009 1380883. 2825641. 4270401. 473. 968. 1462.
2009 1404907. 2942459. 4480013. 481. 1008. 1534.
2010 1428932. 3059278. 4689625. 489. 1048. 1606.
2011 1460403. 3116923. 4773443. 500. 1067. 1635.
2012 1491874. 3174567. 4857261. 511. 1087. 1663.
2013 1523344. 3232212. 4941079. 522. 1107. 1692.
2014 1554815. 3289856. 5024897. 532. 1127. 1721.
2015 1586286. 3347501. 5108715. 543. 1146. 1750.
2016 1617757. 3405145. 5192533. 554. 1166. 1778.
2017 1649227. 3462790. 5276351. 565. 1186. 1807.
2018 1680698. 3520434. 5360169. 576. 1206. 1836.
2019 1712169. 3578079. 5443987. 586. 1225. 1864.
2020 1743640. 3635722. 5527805. 597. 1245. 1893.
2021 1764599. 3687057. 5609515. 604. 1263. 1921.
2022 1785558. 3738391. 5691225. 611. 1280. 1949.
2023 1806516. 3789726. 5772935. 619. 1298. 1977.
2024 1827475. 3841060. 5854645. 626. 1315. 2005.
2025 1848434. 3892395. 5936355. 633. . 1333. 2033.
2026 1869393. 3943729. 6018065. 640. 1351. 2061.
2027 1890351. 3995064. 6099775. 647. 1368. 2089.
2028 1911310 •. 4046398. 6181485. 655. 1386. 2117. U 2029 1932269. 4097733. 6263195. 662. 1403. 2145.
2030 1953228. 4149067. 6344905. 669. 1421. 2173.
'-1
z .. z----
5 0 5 ~e=:;--'---e--3~~--'e--3--~---------------'1 "
SCALE IN MILES
NaTE I TOPOGRAPHY FROM U. S. G. S. -BEAVER
ALASKA, I.~ 250,000
LEGEND
... DAM SIT
• POWERH SE o SITE NO.
-----PENSTOC
--- -TRANSMI StON LINE'
-WATERS ED
'" '" y '''\. ),.
I
./
'-
,
) , 0),
REGIONAL INVENTORY a RECONNAISSANCE STI.IOY'
SMALL HYDROPOWER PROJECTS aUU7''I"I.IEASTALASKA I
HYDROPOWER SITES IDENTlFIED
IN PREUMINARY SCREENING
BEAVER
DEPARTMENT OF THE ARMY
ALASKA DISTRICT CORPS OF ENGINEERS
u
ijvdro~ower Potential
Installed
Capacity
Site No. (kW)
1 178
2 178
3 178
"
Demographic Characteristics
1981 Population: 66
SUMMARY DATA SHEET
PRELIMINARY SCREENING
BEAVER, ALASKA
Cost of
Installed Alterna\}ve
Cost Power-
(JI000) (mill s/kWh)
5,138 572
5,108 572
6,909 572
1981 Number of Households: 15
Economic Base
Unknown
11 5 Percent Fuel Escalation, Capital Cost Excluded.
Cost of
fiydropower Benefit/Cost
(mill s/kWh) Ratio
1,095 0.52
1,089 0.53
1,473 0.39
REGIONAL INVENTORY & RECONNAISANCE STUDY -SMALL HYDROPOWER PROJECTS
ALASKA OISTRIC'r -CORPS OF ENGINEERS
LOAD FORECAST -DEAVER
KILOWATT-HOURS PER YEAR ANNUAL PEAK DEMAND-KW
YEAR LOW MEDIUM HIGH LOW MEDIUM HIGH
1980 264000. 264000. 264000. 90. 90. 90.
1981 275041. 275041. 275041. 94. 94. 94.
1982 286082. 286082. 286082. 98. 98. 98.
1983 297123. 297123. 29'7123. 102. 102. 102.
1984 308164. 308164. 308164. 106. 106. 106.
1985 319205. 319205. 319205. 109,. 109. 109.
1986 330247. 330247. 330247. 113. 113. 113.
1987 341288. 341288. 341288. 117. 117. 117.
1988 352329. 352329. 352329. 121. 121. 12l.
1989 363370. 363370. 363370. 124. 124. 124.
1990 374411. 374411. 374411. 128. 128'. 128.
1991 383967. 400967. 417968. 131. 137. 143.
1992 393522. 427523. 461525. 135. 146. 158.
1993 403078. 454080. 505082. 138. 156. 173.
1994 412633. 480636. 548639. 141. 165. 188.
1995 422189. 507192. 592196. 145. 174. 203.
1996 431745. 533748. 635752. 148. 183. 218.
1997 441300. 560304. 679309. 151. 192. 233.
1998 450856. 586861 ~ 722866. 154. 201. 248.
1999 460411. 613417. 766423. 158. 210. 262.
2000 469967. 639973. 809980. 161. 219. 277.
2001 475500. 667965. 860432. 163. 229. 295.
2002 481033. 695958. 910883. 165. 238. 312.
2003 486566. 723950. 961335. 167. 248. 329.
2004 492099. 751942. 1011786. 169. 258. 347.
2005 497632. 779935. 1062238. 170. 267. 364.
2006 503165. 807927. 1112689. 172. 277. 381 •.
2007 508698. 835919 •. 1163141. 174. 286. 398.
2008 514231. 863912. 1213592. 176. 296. 416.
2009 519764. 891904. 1264044. 178. 305. ,433.
2010 525297. 919896. 1314495. 180. 315. 450.
2011 531998. 932932. 1333866. 182. 319. 457.
2012 538699. 945968. 1353237. 184. 324. 463.
2013 545401. 959004. 1372608. 187. 328. 470.
2014 552102. 972041. 1391979. 189. 333. 477.
2015 558803. 985077. 1411350. 191 • 337. 483.
2016 565504. 998113. 1430721. 194. . 342. 490.
2017 572205. 1011149. 1450092. 196. 346. 497.
2018 578907. 1024185. 1469463. 198. 351. 503.
2019 585608. 1037221. 1488834. 201. 355. 510.
2020 592309. 1050257. 1508205. 203. 360. 517.
2021 597777. 1063077. 1528377. 205. 364. 523.
2022 603245. 1075897. 1548549. 207. 368. 530.
2023 608712. 1088716 •. 1568720. 208. 373. 537.
2024 614180. 1101536. 1588892. 210. 377. 544.
2025 619648. 1114356. 1609064. 212. 382. 551.
2026 625116. 1127176. 1629236. 214. 386. 558.
2027 630584. 1139995. 1649407. 216. 390. 565.
2028 636052. 1152815. 1669579. 218. 395. 572. U 2029 641519. 1165635. 1689751. 220. 399. 579.
2030 646987. 1178455. 1709923. 222. 404. 586.
NOTE: TOPOGRAPHY FROM US. G. S. -FORT YUKON
ALASKA, 1:250,000
LEGEND
• DAM SITE
• POWERHOUSE o SITE NO.
- - -• -PENSTOCK
- - -TRANSMISSION LINE
-WATERSHED
5 0 5
E3 E3 E3
SCALE IN MILES
REGIONAL INVENTORY a RECONNAISSANCE STUDY
SMALL HYDROPoWER PRO.IECTS
NORTHEAST AL KA
HYDROPOWER SITES IDENTIFIED
IN PREUMINARY SCREENING
BIRCH CREEK
DEPARTMENT OF THE ARMV
ALASKA DISTRICT CORPS OF ENGINEERS
SUMMARY DATA SHEET
~ PRELIMINARY SCREENING
BIRCH CREEK, ALASKA
~dropower Potential
Cost of
Installed Installed Alternaj}ve Cost of
Capacity Cost Power-IiYdropower Benefi t/Cos1
Site No. (kW) (J1000) (mill s/kWh) (mill s/kWh) Ratio
2 91 2,795 628 1,985 0.32
1 91 2,883 628 2,047 0.31
3 91 6,771 628 4,808 0.13
Demographic Characteristics
1981 Population: 32
1981 Number of Houeholds: 7
Economic Base
Unknown
11 5 Percent Fuel Escalation, Capital Cost Excluded.
REGIONAL INVENTORY & RECONNAISANCE STUDY -SMALL HYDROPOWER PROJECTS
ALASKA DISTRICT -CORPS OF ENGINEERS
YEAR
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
LOAD FORECAST -BIRCH CREEK
KILOWATT-HOURS PER YEAR
LOW
o.
14855.
29710.
44565.
59420.
74275.
89129.
103984.
118839.
133694.
148549.
154762.
160974.
167187.
173400.
179613.
185825.
192038.
198251.
204463.
210676.
216053.
221430.
226806.
232183.
237560.
242937.
248314.
253690.
259067.
264444.
267557.
270671.
273784.
276898.
280011.
283124.
286238.
289351.
292465.
295578.
299349.
303119.
306890.
310660.
314431.
318202.
321972.
325743.
329513.
333284.
MEDIUM
o.
14855.
29710.
44565.
59420.
74275.
89129.
103984.
118839.
133694.
148549.
163005.
177460.
191916.
206371.
220827.
235282.
249738.
264193.
278649.
293104.
309370.
325636.
341902.
358168.
374434.
390701.
406967.
423233.
439499.
455765.
461950.
468135.
474319.
480504.
486689.
492874.
499059.
\
505244.
511428.
517613.
524948.
532283.
539619.
546954.
554289.
561624.
568959.
576295.
583630.
590965.
HIGH
o.
14855.
29710.
44565.
59420.
74275.
89129.
103984.
118839.
133694.
148549.
171247.
193945.
216644.
239342.
262040.
284738.
307436.
330135.
352833.
375531.
402686.
429842.
456997.
484153.
511308.
538463.
565619.
592774.
619930.
647085.
656341.
665598.
674854.
684110.
693367.
702623.
711879.
721136.
730392.
739648.
750548.
761448.
772347.
783247.
794147.
805047.
815947.
826847.
837746.
848646.
ANNUAL PEAK DEMAND-KW
LOW MEDIUM HIGH
o. o. o.
5. 5. 5.
10. 10. 10.
15. 15. 15.
20. 20. 20.
25. 25. 25.
31. 31. 31.
36. 36. 36.
41. 41. 41-
46. 46. 46.
51. 51. 51.
53. 56. 59.
55. 61. 66.
57. 66. 74.
59. 71. 82.
62. 76. 90.
64. 81. 98.
66. 86. 105.
68. 90. 113.
70. 95. 121.
72. 100. 129.
74. 106. 138.
76. 112. 147.
78. 117. 157.
80. 123. 166.
81 • 1 28 • 17 5 •
83. 134. 184.
85. 139. 194.
87. 145. 203.
89. 151.212.
91. 156. 222.
92. 158. 225.
93. 160.· 228.
94. 162. 231.
95. 165. 234.
96. 167. 237.
97. 169. 241.
98. 171. 244.
99. 173. 247.
100.
101.
103.
104.
105.
106.
108.
109.
110.
112.
113 ..
114.
175.
177.
180.
182.
185.
187.
190.
192.
195.
197.
200.
202 •.
250.
253.
257.
261.
265.
268.
272.
276.
279.
283.
287.
291.
u
u
NOTE: TOPOGRAPHY FROM U. S. G. S. -CIRCLE
ALASKA, 1:250,000
LEGEND
• DAM S~TE
• POWERHOUSE o SITE NO.
- -_. -PENSTOCK
- - -TRANSMISSION LINE
-WATERSHED
5 0
E3 E3 t==I
SCALE I N MILES
REGIONAL INVENTORY Ii RECONNAISSANCE STUD'f
SMALL HYDROPOWER PROJECTS
NORTHEAST ALASKA
HYDROPOWER SITES IDENTIFIED
IN PREUMINARY SCREEN I NG
CENTRAL, QRQ.E HOT SPRINGS
DEPARTMENT OF THE ARMV
ALASKA DISTRICT CORPS OF ENGINEERS
SUMMARY DATA SHEET
PRELIMINARY SCREENING
CENTRAL-CIRCLE HOT SPRINGS, ALASKA
~dro~ower Potential
Cost of
Installed Installed Alternative Cost of
Capacity Cost Power.lI IiYdropower Seneff t/Cost
Si te No. (kW) (S1000) (mill s/kWh) (mi 11 s/kWh) Ratio
4 125 2,736 484 977 0.50
1 125 3,014 484 1,076 0.45
5 125 3,114 484 1,112 0.44
6 125 3,250 484 1,160 0.42
3 125 3,709 484 1,324 0.37
2 125 3,754 484 1,340 0.36
Demographic Characteristics
1981 Population: Central -20; Circle Hot Springs -25
1981 Number of Households: Central -5; Circle Hot Springs -6
Economi c Sa se
Subsistence
u 11 5 Percent Fuel Escalation, Capital Cost Excluded.
REGIONAL INVENTORY & RECONNAISANCE STUDY -SMALL HYDROPo\>lER PROJECTS
ALASKA DISTRICT -CORPS OF ENGINEERS
LOAD FORECAST -CIRCLE HOT SPRINGS -CENTRAL
KILOWATT-HOURS PER YEAR ANNUAL PEAK DEMAND-KW V
YEAR LOW MEDIUM HIGH LOW MEDIUM HIGH
1980 80000. 80000. 80000. 27. 27. 27.
1981 94951. 94951. 94951. 33~ 33. 33.
1982 109902. 109902. 109902. 38. 38. 38.
19B3 124854. 124854. 124854. 43. 43. 43.
1984 139805. 139805. 139805. 48. 48. 48.
1985 154756. 154756. 154756. 53. 53. 53.
1986 169707. 169707. 169707. 58. 58. 58.
1987 184658. 184658. 184658. 63. 63. 63.
1988 199610. 199610. 199610. 68. 68. 68.
1989 214561. 214561. 214561. 73. 73. 73.
1990 229512. 229512. 229512. 79. 79. 79.
1991 237261. 248853. 260444. 81. 85. 89.
1992 245011. 268193. 291376. 84. 92. 100.
1993 252760. 287534. 322308. 87. 98. 110.
1994 260509. 306874. 353240. 89. 105. 121.
1995 268259. 326215. 384172. 92. 112. 132.
1996 276008. 345556. 415104. 95. 118. 142.
1997 283757. 364896. 446036. 97. 125. 153.
1998 291506. 384237. 476968. 100. 132. 163.
1999 299256. 403577. 507900. 102. 138. 174.
2000 307005. 422918. 538832. 105. 145. 185.
2001 312882. 444108. 575336. 107. 152. 197.
2002 318760. 465299. 611839. 109. 159. 210.
2003 324637. 486489. 648343. 111. 167. 222.
2004 330514. 507680. 684846. 113. 174. 235.
2005 336392. 528870. 721350. 115. 181. 247.
2006 342269. 550060. 757853. 117. 188. 260 •.
2007 348146. 571251. 794357. 119. 196. 272.
2008 354024. 592441. 830860. 121. 203. 285.
2009 359901. 613632. 867364. 123. 210. .297.
2010 365778. 634822. 903867. . 125. 217 •. 310.
2011 370241. 643604. 916969. 127. 220. 314.
2012 374704. 652387. 930070. 128. 223. j 19.
2013 379167. 661169. 943172. 130. 226. 323.
2014 383630. 669951. 956273. 131. 229. 327.
2015 388093. 678734. 969375. 133. 232. 332.
2016 392556. 687516. 982476. 134. . 235. 336.
2017 397019. 696298. 995578. 136. 238. 341.
2018 401482. 705081. 1008679. 137. 241. 345.
2019 405945. 713863. 1021781. 139. 244. 350.·
2020 410408. 722645. 1034882. 141. 247. 354.
2021 415011. 732260. 1049510. 142. 251. 359.
2022 419613. 741876. 1064138. 144. 254. 364.
2023 424216. 751491 •. 1078766. 145. 257. 369.
2024 428819. 761107. 1093395. 147. 261. 374.
2025 433421. 770722. 1108023. 148. 264. 379.
2026 438024. 780337. 1122651. 150. 267. 384.
2027 442627. 789953. 1137279. 152. 271. 389.
2028 447230. 799568. 1151907. 153. 274. 394. U 2029 451832. 809183. 1166535. 155. 277. 399.
2030 456435. 818799. 1181163. 156. 280. 405.
REGIONAL INVENTORY & R~CONNAISANCE STUDY -SMALL HYDROPOWER PROJECTS
ALASKA DISTRICT -CORPS OF ENGINEERS
LOAD FORECAST -CENTRAL
V KILOl-IATT-UOURS PER YEAR ANNUAL PEAK DEMAND-KW
YEAR LOW MEDIUM HIGH LO\,l MEDIUM HIGH
1980 80000. 80000. 80000. 27. 27. 27.
1981 83346. 83346. 83346. 29. 29. 29.
1982 86692. 86692. 86692. 30. 30. 30.
1933 90037. 90037. 90037. 31. 31. 31 •.
1984 93383. 93383. 93383. 32. 32. 32.
1985 96729. 96729. 96729. 33. 33. 33.
19136 100075. 100075. 100075. 34. 34. 34.
1987 103421. 103421. 103421. 35. 35. 35.
1988 106766. 106766. 106766. 37. 37. 37.
1989 110112. 110112. 110112. 38 • 38. 38.
. 1990 113458. 113458. 113458. 39. 39. 39.
1991 116354. 121505. 126657. 40. 42. 43.
1992 119249. 129553. 139856. 41. 44. 48.
1993 122145. 137600. 153055. 42. 47. 52.
1994 125040. 145647. 166254. 43. 50. 57.
1995 127936. 153694. 179453. 44. 53. 61.
1996 130832. 161742. 192652. 45. 55. 66.
1997 133727. 169789. 205851. 46. 58. 70.
19913 136623. 177836. 219050. 47. 61. 75.
1999 139518. 185884. 232249. 48. 64. 80.
2000 142414. 193931. 245448. 49. 66. 84.
2001 144091. 202414. 260736. 49. 69. 89.
2002 145767. 210896. 276025. 50. 72. 95.
2003 147444. 219379. 291313. 50. 75. 100.
2004 149121. 227861. 306602. 51. 78. 105.
2005 150798. 236344. 321890. 52. 81. 110.
2006 152474. 244826. 337178. 52. 84. 115.
2007 154151. 253309. 352467. 53. 87. 121.
2008 155828. 261791. 367755. 53. 90. 126.
2009 157504. 270274. 383044. 54. 9.3. 131.
2010 159181. 278756. 398332. 55. 95. 136.
2011 161212. 282706. 404202. 55. 97. 138.
2012 163242. 286657. 410072. 56. 98. 140.
2013 165273. 290607. 415942. 57. 100. 142.
2014 167304. 294558. 421812. 57. 101. 144.
2015 169335. 298508. 427682. 58. 102. 146.
2016 171365. 302458. 433552. 59. 104. 148.
2017 173396. 306409. 439422. 59. 105. 150.
2018 175427. 310359. 445292. 60. 106. 152.
2019 177457. 314310. 451162. 61. 108. 155.
2020 179488. 318260. 457032. 61. 109. 157.
2021 181145. 322145. 463145. 62. 110. 159.
2022 182802. 326029. 469257. 63. 112. 161.
2023 184459. 329914. 475370. 63. 113. 163.
2024 186116. 333799. 481482. 64. 114. 165.
2025 187773. 337683. 487595. 64. 116. 167.
2026 189429. 341568. 493708. 65. 117. 169.
2027 191086. 345453. 499820. 65. 118. 171.
U 2028 192743. 349338. 505933. 66. 120. 173.
2Q29 194400. 353222. 512045. 67. 121. 175.
2030 196057. 357107. 518158. 67. 122. 177.
REGIONAL INVENTORY & RECONNAISANCE STUDY -Sl-1ALL HYDROPOWER. PROJECTS
ALASKA DISTRICT -CORPS OF ENGINEERS
LOAD FORECAST -CIRCLE HOT SPRINGS
KILOWATT-HaJRS PER YEAR ANNUAL PEAK DEMAND-KW V
YEAR LOW MEDIID-I HIGH LOW MEDIUM HIGH
1980 o. o. o. 0 .• o. o.
1981 11605. 11605. 11605. 4. 4. 4.
1982 23211. 23211. 23211. 8. 8. 8.
1983 34816. 34816. 34816. 12. 12. 12.
1984 46422. 46422. 46422. 16. 16. 16.
1985 58027. 58027. 58027. 20. 20. 20.
1986 69632. 69632. 69632. 24. 24. 24.
1987 81238. 81238. 81238. 28. 28. 28.
1988 92843. 92843. 92843. 32. 32. 32.
1989 104449. 104449. 104449. 36. 36. 36.
1990 116054. 116054. 116054. 40. 40. 40.
1991 120908. 127347. 133787. 41. 44. 46.
1992 125761. 138641. 151520. 43. 47. 52.
1993 130615. 149934. 169253. ,45. 51. 58.
1994 135469. 161227. 186986. 46. 55. 64.
1995 140323. 172520. 204719. 48. 59. 70.
1996 145176. 183814. 222452. 50. 63. 76.
·1997 150030. 195107. 240185. 51. 67. 82.
1998 154884. 206400. 257918. 53. 71. 88.
1999 159737. 217694. 275651. 55. 75. 94.
2000 164591. 228987. 293384. 56. 78. 100.
2001 168792. 241695. 314599. 58. 83. 108.
2002 172992. 254403. 335814. 59. 87. 115.
2003 177193. 267111. 357029. 61 •. 91. 122.
2004 181393. 279819. 378244. 62. 96. 130.
2005 185594. 292527. 399459. 64. 100. 137.
2006 189795. 305234. 420675. 65. 105. 144.
2007 193995. 317942. 441890. 66. 109. 151.
2008 198196. 330650. 463105. 68. 113. 159.
2009 202396. 343358. 484320. 69. 118. ' 166.
2010 206597. 356066. 505535. 71. 122. 173.
2011 209029. 360898. 512767. 72. 124. 176.
2012 211462. 365730. 519998. 72. 125. 178.
2013 213894. 370562. 527230. 73. 127. 181.
2014 216326. 375394. 534461. 74. 129. 183.
2015 218758. 380226. 541693. 75. 130. 186.
2016 221191. 385057. 548924. 76. . 132. 188 •
2017 223623. 389889. 556156. 77. 134. 190.
2018 226055. 394721. 563387. 77. 135. . 193.
2019 228488. 399553. 570619. 78. 137. 195.
2020 230920. 404385. 577850. 79. 138 .•. 198.
2021 233866. 410116. 586366. 80. 140. 201. ,
2022 236812. 415846. 594881. 81. 142. 204.
2023 239757. 421577 •. 603397. 82. 144. 207.
2024 242703. 427308. 611912. 83. 146. 210.
2025 245649. 433038. 620428. 84. 148. 212.
2026 248595. 438769. 628943. 8S. 150. 215.
2027 251541. 444500. 637459. 86. 152. 218.
2028 254486. 450231. 645974. 87. 154. 221. U 2029 257432. 455961. 654490. 88. 156. 224.
2030 260378. 461692. 663005. 89. 158 •. 227.
u
u
NOTE; TOPOGRAPHY FROM U. S. G. S. -EAGLE
ALASKA 1 I: 250 1 000
LEGEND
• DAM SITE
• POWERHCXJSE o SITE NO
-----PENSTOCK
---TRANSMtSSION LINE
--WATERSHED
5 o 5
E3 H E3
SCALE IN MILES
REGIONAL INVENTORY a REOONNAISSANCE STUDY
SMALL HYDROPOWER PROJECTS
NORTHEAST ALASKA
HYDROPOWER SITES IDENTIFIED
IN PRELIMINARY SCREENING
CHICKEN
DEPARTMENT OF THE ARMY
ALASKA DISTRICT CORPS OF ENGINEERS
Demographic characteristics
1981 Population: 30
1981 Number of Households: .7
Economic Base
Unknown
11 5 Percent Fuel Escalation, Capital Cost Excluded.
REGIONAL INVENTORY.& RECONNAISANCE STUDY -SMALL HYDROPOWER PROJECTS
ALASKA DISTRICT -CORPS OF ENGINEERS
LOAD FORECAST ..: CHICKEN
V
KlLOWA'l"l'-HOURS PER YEAR ANNUAl. PEAK DEMAND-KW
YEAR LO\'l MEDIUM HIGH LOW 14EIJIUM HIGH
1980 O. O. O. O. O. O.
19B1 13927. 13927. 13927. 5. 5. 5.
1982 27853. 27853~ 27853. 10. 10. 10.
1983 41780. 41780. 41780. 14. 14. 14.
1984 55706. 55706'. 55706. 19. 19 •. 19.
1985 69633. 69633. 69633. 24. 24. 24.
1986 83559. 83559. 83559. 29. 29. 29.
1987 97486. 97486. 97486. 33. 33. 33.
1988 111412. 111412. 111412. 38. 38. 38.
1989 125339. 125339. 125339. 43. 43. 43.
1990 139265. 139265. 139265. 48. 48. 48.
1991 145089. 152817 • 160545. 50. 52. 55.
1992 150914. 166369. 181824. 52. 57. 62.
1993 156738. 179921. 203104. 54. 62. 70.
1994 162563. 193473. 224383. 56. 66. 17.
1995 168387. 207025. 245663. 58. 71. 84.
1996 174211. ' 220577. 266942. 60~ 76. 91.
1997 ,180036. 234129. 288222. 62. 80. 99.
1998 185860. 247681. 309501. 64. 85. 106.
1999 191685. 261233. 330781. 66. 89. 113.
2000 197509. 274785. 352060. 68. 94. 121.
2001 202550. 290034. 377518. 69. 99. 129.
2002 207590. 305284. 402976. 71. 105. 138.
2003 212631. 320533. 428435. 73. 110. 147.
2004 217672. 335783. 453893. 75. 115. 155.
2005 222713. 351032. 479351. 76. 120. 164.
2006 227753. 366281. 504809. 78. 125. 173.
2007 232794. 381531. 530267. 80. 131. 102.
2008 237835. 396780. 555725. 81. 136. 190.
2009 242875. 412030. 581184. 83. 141. 199.
2010 247916. 427279. 606642. 85. 146. 208.
2011 250835. 433077. 615320. 86. 148. 211.
2012 253754. 438876. 623998. 87. 150. 214.
2013 256672. 444674. 632675. 88. 152. 217.
2014 259591. 450472. 641353. 89. 154. 220.
2015 262510. 456271. 650031. 90. 156. 223.
2016 265429. 462069. 658709. 91. 158. 226.
2017 268348. 467867. 667387. 92. 160. 229.
2018 271266. 473666. 676065. 93. 162. 232.
2019 274185. 479464. 684742. 94. 164. 235.
2020 277104. 485262. 693420. 95. 166. 237.
2021 280639. 492139. 703639. 96. 169. 241.
2022 284174. 499016. 713857. 97. 171. 244.
2023 287709. 505892. 724076. 99. 173. 248.
2024 291244. 512769. 734295. 100. 176. 251.
2025 294779. 519646. 744513. 101. ·178. 255.
2026 298314. 526523. 754732. 102. 180. 258.
2027 301849,. 533400. 764950. 103. 183. 262.
2028 305384. 540277. 775169. 105. 185. 265. V
2029 308919. 547153. 785388. 106. 187. 269.
2030 312454. 554030. 795606. 107. 190. 272.
u
NOTE:
u
ALASKA,
LEGEND
• DAM SITE
• POWERHOUSE o SITE NO.
- - - --PENSTOCK
---TRANSMISSION LINE
-----WATERSHED
o 5
E3 1--1
SCALE I N MILES
REGIONAL INVENTORY a RECONNAISSANCE STUDY
SMALL HYDROPOWER PROJECTS
NORTHEAST ALASKA
HYDROPOWER SITES IDENTIFIED
IN PRELIMINARY SCREENING
CIRCLE
DEPARTMENT OF THE ARMY
ALASKA DISTRICT CORPS OF ENGINEERS
u
Jiydro~ower Potenti a 1
Installed
Capacity
Site No. (kW)
1 215
2 215
Demo9ra~hic Characteristics
1981 Population: 80
SUMMARY DATA SHEET
PRELIMINARY SCREENING
. CIRCLE, ALASKA
Cost of
Install ed A1 ternaji ve
Cost Power-'
($1000 ) (mill s/kWh)
4,532 484
4,683 484
1981 Number of Households: 18
Economi c Base
Subsi stence
Cost of
~dropower
(mills/kWh)
797
824
11 5 Percent Fuel Escalation, Capital Cost Excluded.
Benefit/Cost
Ratio
0.61
0.59
REGIONAL INVENTORY & RECONNAISANCE STUDY -SMALL HYDROPOWER PRQJEC'rS
ALASKA DISTRICT -CORPS OF ENGINEERS
LOAD FORECAST -CIRCLE
KILOWATT-HOURS PER YEAR ANNUAL PEAK DEMAND-KW
YEAR LOW MEDIUM HIGH LOW r-IEDIUM HIGH
1980 320000. 320000. 320000. 110. 110. 110.
1981 . 333383. 333383. 333383. 114. 114. 114.
1982 346766. 346766. 346766. 119. 119. 119.
1983 360150. 360150. 360150. 123. 123. 123.
1984 373.533. 373533. 373533. 128. 128. 128.
1985 386916. 386916. 386916. "-133. 133. 133.
1986 400299. 400299. 400299. 137. 137. 137.
1987 413682. 413682. 413682. 142. 142. 142.
1988 427066. 427066. 427066. 146. 146. 146.
1989 440449. 440449. 440449. 151. 151-151.
1990 453832. 453932. 453832. 155. 155. 155.
1991 465415. 486021. 506628. 159. 166. 174.
1992 476997. 518211. 559424. 163. 177. 192.
1993 488580. 550400. 612221. 167. 188. 210.
1994 500162. 582589. 665017. 171. 200. 228.
1995 511745. 614779. 717813. 175. 211. 246.
1996 523327. 646968. 770609. 179. 222.· 264.
1997 534910. 679157. 823405. 183. 233. 282.
1998 546492. 711347. 876202. 187. 244. 300.
1999 558075. 743536. 928998. 191. 255. 318.
2000 569657. 775725. 981794. 195. 266. 336.
2001 576364. 809655. 1042947. 197. 277. 357.
2002 583070. 843585. 1104101. 200. 289. 378.
2003 589777. 877515. 1165254. 202. 301. 399.
2004 596484. 911446. 1226408. 204. 312. 420.
2005 603190. 945376. 1287561. 2Q7. 324. 441.
2006 609897. 979306. 1348714. 209. 335. 462.
2007 616604. 1013236. 1409868. 211. 347. 483.
2008 623311. 1047166. 1471021. 213. 359. .S04.
2009 630017. 1081096. 1532174. 216. 370. 525.
2010 636724. 1115026. 1593328. 218. 382. 546.
2011 644847. 1130827. 1616808. 221. 387~ 554.
2012 652969. 1146629. 1640288. 224. 393. 562.
2013 661092. 1162430, 1663768 •. 226. 398. 570.
2014 669215. 1178231. 1687248. 229. 404. 578.
2015 677337. 1194032. 1710728. 232. 409. 586.
2016 685460. 1209834. 1734208. 235. 414. 594.
2017 693583. 1225635. 1757688. 238. 420. 602.
2018 701706. 1241436. 1781168. 240. 425. 610.
2019 709828. 1257237. 1804648. 243. 431 •. 618.
2020 717951. 1273039. 1828128. 246. 436. 626.
2021 724579. 1288578. 1852578. 248. 441. 634.
2022 731206. 1304117. 1877029. 250. 447. 643.
2023 737834. 1319656. 1901479. 253. 452. 651.
2024 744462. 1335195. 1925930. 255. 457. 660.
2025 751089. 1350734. 1950380. 257. 463. 668.
2026 757717. 1366273. 1974830. 259. 468. 676.
2027 764344. 1381812. 1999281. 262. 473. 685.
2028 770972 • 1397351. 2023731. 264. 479. 693. U 2029 777600. 1412890. 2048181. 266. 484. 701.
2030 784227. 1428429. 2072632. 269. 489. 710.
HYdropower Potential
Si te No.
Installed
Capacity
e kW)
No sites identified
Demographic Characteristics
1981 Population: 619
SUMMARY DATA SHEET
PRELIMINARY SCREENING
FORT YUKON, ALASKA
Installed
Cost
(S1000 )
Cost of
A1 ternaji,ve
Power-
emf 11 s/kWh)
1981 Number of Households: 176
Economic Base
Subsf stence
Government
Cost of
tiYdropower
emf 11 s/kWh)
11 5 Percent Fuel Escalation, Capital Cost Excluded.
Benefi t/Cost
Ratio
'REG:IONAL INVENTORY & RECONNAISANCE S.TUDY -SMALL HYDROPOWER PROJEG'fS
ALASKA DISTRICT -CORPS OF ENGINEERS
LOAD FORECAST -FORT YUKON
KILOWA'l'T-HOURS PER YEAR ANNUAL PEAK DEMAND-KW
YEAR LOW MEDIUM HIGH LOW MEDIUM HIGH
1980 2652857. 2652957. 2652857. 909. 909. 909.
1981 2746109. 2746109. 2746109. 940. 940. 940.
1982 2839362. 2839362. 2839362. 972. 972. 972.
1983 2932614. 2932614. 2932614. 1004. 1004. 1004.
1984 3025866. 3025866. 3025866. 1036. 1036. 1036.
1985 3.119118. 3119118. 3119118. 1068. 1068. 1068.
1986 3212370. 3212370. 3212370. 1100. 1100. 1100.
1987 3305623. 3305623. 3305623. 1132. 1132. 1132.
1988 3398875. 3398875. 3398875. 1164. 1164. 1164.
1989 3492127. 3492127. 3492127. 1196. 1196. 1196.
1990 3585380. 3585380. 3585380. 1228. 1228. 1228.
1991 3672780. 3936290. 4199800. 1258. 1348. 1438.
1992 3760181. 4287200. 4814219. 1288. 1468. 1649.
1993 3847581. 4638110. 5428639. 1318. 1588. 1859.
1994 3934981. 4989020. 6043058. 1348. 1709. 2070.
1995 4022381. 5339929. 6657478. 1378. 1829. "RO.
1qq~ 4109782. 5690840. 7271897. 1407. 1949. 2490.
1997 4197182. 6041750. 7886317. 1437. 2069. 2701.
1998 4284583. 6392660. 8500736. 1467. 2189. 2911.
1999 4371983. 6743570. 9115155. 1497. 2309. 3122.
2000 . 4459383. 7094478. 9729573. 1527. 2430 • 3332.
2001 4549511. 7532723. 10515935. 1558. 2580. 3601.
2002 4639638. 7970968. 11302297. 1589. 2730. 3871.
2003 4729766. 8409213. 12088659 •. 1620. 2380. 4140.
2004 4819893. 8847458. 12875021. 1651. 3030. 4409.
2005 4910021. 9235703. 13661383. 1682. 3180. Mi79.
2006 5000148. 9723948. 14447745. 1712. 3330. 4948.
2007 5090276. 10162193. 15234107. 1743. 3480. 5217.
2008 5180403. 10600438. 16020469. 1774. 3630. 5486.
2009 5270531. 11038683. 16806832. 1805. 3780. 5756.
2010 5360659. 11476928. 17593196. 1836. 3930. 6025.
2011 5478723. 11693182. 17907640. 1876. 4005. 6133.
2012 5596786. 11909436. 18222084. 1917. 4079. 6240.
2013 5714850. 12125690. 18536528. 1957. 4153. 6348.
2014 5832913. 12341944. 18850972. 1998. 4227. 6456.
2015 5950976. 12558198. 19165416. 2038. 4301. 6563.
2016 6069040. 12774452. 19479860. 2078. 4375. 6671.
2017 6187104. 12990706. 19794304. 2119. 4449. 6779.
2018 6305167. 13206960. 20108748. 2159. 4523. 6887.
2019 . 6423231. 13423214 • 20423.192. 2200. 4597. 6994.
2020 6541292. 13639467. 20737642. 2240. 4671. 7102.
2021 ,6619919. 13832049. 21044178. 2267. 4737. 7207.
2022 6698546. 14024631. 21350714. 2294. 4803. 7312.
2023 6777173. 14217213. 21657250. 2321. 4869. 7417.
2024 6B55BOO. 14409795. 21963786. 2348. 4935. 7522.
2025 6934427. 14602377. 22270322. 2375. 5001. 7627.
2026 7013054. 14794959. 22576858. 2402. 5067. 7732.
2027 7091681. 14987541. 22883394. 2429. 5133. 7837.
2028 7170308. 15180123. 23189930. 2456. 5199. 7942. V 15372705.
'.
2029 7248935. 23496466. 2483. 5265. 8047.
2030 7327562. 15565287. 23803002. -,2509'.
'" ~ 5331. 8152.
NOTE: TOPOGRAPHY FROM U. S. G. S. -LIVENGOOD NE.
ALASKA, 1:250,000
LEGEND
.. DAM SITE
• POWERHOUSE
O. SITE NO.
-- - --PENSTOCK
- - -TRANSMISSION LINE
----WATER SHED
5 o 5
SCALE IN MILES
REGIONAL INVENTORY a RECONNAISSANCE STUDY
SMALL. HYDROPOWER PROJECTS
NORTHEAST ALASKA
HYDROPOWER SITES IDENTIFIED
IN PRELIMINARY SCREENING
LIVENGOOD
DEPARTMENT OF THE ARMY
ALASKA DISTRICT CORPS OF ENGINEERS
u
I1Ydro~ower Potenti a 1
Installed
Capacity
Si te No. (kW)
2 69
1 67
Demographic Characteristics
1981 Population: 50
SUMMARY DATA SHEET
PRELIMINARY SCREENING
LIVENGOOD, ALASKA
Cost of
Installed Al ternaj} ve
Cost Power_
($1000 ) (mills/kWh)
1,774 484
3,453 484
1981 Number of Households: 11
Economic Base
Unknown
11 5 Percent Fuel Escalation, Capital Cost Excluded.
Cost of
I1Ydropower Benefit/Cost
(mill s/kWh) Ratio
673 0.72
972 0.50
REGIONAL INVENTORY & RECONNAISANCE STUDY -SMALL HYDROPOWER PROJECTS
ALASKA DISTRICT -CORPS OF ENGINEERS
LOAD FORECAST -LIVENGOOD
0
KILOWATT-HOURS PER YEAR ANNUAL PEAK DEMAND-K\v
YEAR LOW MEDIUf1 HIGH LOW MEDIm~ HIGH
1980 200000. 200000. 200000. 68. 68. 68.
1981 208365. 208365. 208365. 71. 71. 71.
1982 216729. 216729. 216729. 74. 74. 74.
1983 225094. 225094. 225094. 77. 77. 77.
1984 233458. 233458. 233458. 80. 80. 80.
1985 241823. 241823. 241823. 83. 83. 83.
1986 250187. 250187. 250187. 86. 86. 86.
1987 258552. 258552. 258552. 89. 89. 89.
1988 266916. 266916. 266916. 91. 91. ·91-
1989 275281. 275281. 275281. 94. 94. 94.
1990 283645. 283645. 283645. 97. 97. 97.
1991 290884. 303763. 316643. 100. 104. 108.
1992 298123. 323882. 349640. 102. 111. 120.
1993 305362. 344000. 382638. 105. 118. 131.
1994 312601. 364118. 415635. 107. 125. 142.
1995 319840. 384237 ~ 448633. 110. 132. 154.
1996 327079. 404355~ 481631. 112. 138. 165.
1997 334318. 424473. 514628. 114. 145. 176.
1998 341557. 444592. 547626. 117 • 152. 188.
1999 348796. 464710. 580623. 119. 159. 199.
2000 356035. 484828. 613621. 122. 166. 210.
2001 360227. 506034. 651842. 123. 173. 223.
2002 364418. 527241. 690063. 125. H:!1. 236.
2003 368610. 548447. 728284 •. 126. 188. 249.
2004 372802. 569653. 766505. 128. 195. 263.
2005 376993. 590860. 804725. 1;29. 202. 276.
2006 381185. 612066. 842946. 131. 210. 289.
2007 385377. 633272. 881167. 132. 217. 302.
2008 389569. 654479. 919388. 133. 224. 315.
2009. 393760. 675685. 957609. 135. .231. 328.
2010 397952. 696891. 995830. 136. . 239. 341.
2011 403029. 706767. 1010505. 138. 242. 346.
2012 . 408105. 716643. 1025180. 140. ·245. 351.
2013 413182. 726518. 1039855. 142. 249. 356.
2014 418259. 736394. 1054530. 143. 252. 361.
2015 423335. 746270. 1069205. 145. 256. 366.
2016 428412. 756146. 1083880. 147. 259. 371.
2017 433489. 766022. 1098555. 148. 262. 376.
2018 438566. 775898. 1113230. 150. 266. 381.
2019 443642. 785773. 1127905. 152. 269. 386.
2020 44S719~ 795649. 1142580. 154. 272. 391.
2021 452861. 805361. 1157862. 155. 276. 397.
2022 457004. 815073. 1173143. 157. 279. 402.
2023 461146. 824785. 1188425. 158. 282. 407.
2024 465288. 834497. ·1203706. 159. 286. 412.
2025 469431. 844208. 1218988. 161-289. 417.
2026 473573. 853920. 1234269. 162. 292. 423.
2027 477715. 863632. 1249551. 164. 296. 428.
2028 481858. 873344. 1264832. ·165. 299. 433. U
2029 4(16000. 883056. 1280114. 166. 302. 438.
2030 490142. 892768. 1295395. 168. 306. 444.
' .. ' "
z .... _--
o
E3
MILES
NOTE: TOpru:=RA!PHY FROM U. S. G. S. -LIVENGOOD a -mNANA
II2!50.000
LEGEND
Y DAM SITE •
-----PENSTOCK .
HYDROPO\'IER SITES IDENTIFIED
IN PREUMINARY SCREENING
RAMPART
o SITE N0.l;
---TRANSMIS rON LrNE' ..... --DE-PARTME---NT-O-F-TH-E-.-A-R-MY---...
-WATERSHED ALASKA DISTRICT CORPS OF ENGINEERS
SUMMARY DATA SHEET
U PRELIMINARY SCREENING
RAMPART, ALASKA
Hydropower Potential
Cost of
Installed Installed Alternative Cost of
Capacity Cost Powerl/ IiY drop owe r Benefit/Cost
S1 te No. (kW) (JlOOO) (mi 11 s/kWh) (mi 11 s/kWh) Ratio
1 142 2,507 542 1,075 0.50
3 151 2,957 542 1,268 0.43
4 151 2,980 542 1,278 0.42
2 151 4,025 542 1,726 0.31
Demographic Characteristics
1981 Population: 53
1981 Number of Households: 12
Economi c Base
Unknown
J! 5 Percent Fuel Escalation, Capital Cost Excluded.
R!:.'GI ONAL INVENTORY & RECONNAISANCE STUDY -SMALL HYDROPOWER PROJECTS
ALASKA DISTRICT -CORPS OF ENGINEERS
LOAD FORECAST -RM1PART
KILOWATT-HOURS PER YEAR ANNUAL PEAK DEHAND-Kt-l V
YEAR LOI-v t-tEDIUM HIGH LOW MEDIUM HIGH
1980 O. O. O. O. O. O.
1981 24604. 24604. 24604. 8. 8. 8.
1982 49207. 49207. 49207. 17. 17. 17.
1983 73811. 73811. 73811. 25. 25. 25.
1984 98414. 98414. 98414. 34. 34. 34.
1985 123018. 123018. 123018. 42. 42. 42.
1986 147621. 147621. 147621. 51. 51. 51.
1987 172225. 172225. 172225. 59. 59. 59.
1988 196828. 196828. 196828. 67. 67. 67.
1989 221432. 221432. 221432. 76. 76. 76.
1990 246035. 246035. 246035. 84. 84. 84.
1991 256325. 269977. 283629. 88. 92. 97.
1992 266614. 293919. 321223. 91. 101. 110.
1993 276904. 317860. 358816. 95. 109. 123.
1994 287194. 341802. 396410. 98. 117. 136.
1995 297483. 365744. 434004. 102. 125. 149.
1996 307773. 389686. 471598. 105. 133. 162.
1997 318063. 413628. 509192. 109. 142. 174.
1998 328353. 437570. 546786. 112. 150. 187.
1999 338642. 461511. 584379. 116. 158. 200.
2000 348932. 485453. 621973. 119. 166. 213.
2001 357837. 512394. 666949. 123. 175. 228.
2002 366743. 539334. 711925. 126. 185. 244.
2003 375648. 566275. 756902. 129. 194. 259.
2004 384553. 593216. 801878. 132. 203. 275.
2005 393459. 620156. 846854. 135. 212. 290.
2006 402364. 647097. 891830. 138. 222. 305.
2007 411269. 674038. 936806. 141. 231. 321.
2008 420175. 700979. 981783 ~ 144. 240. 336.
2009 429080. 727919. 1026759., 147. 249. .352.
2010 4379B5. 754860. 1071735. 15.0. 259. 367.
2011 443142. 765104. 1087066. 152. 262. 372.
2012 448298. 775347. 1102397. 154. 266. 378.
2013 453455. 785591. 1117727. 155. 269. 383.
2014 458611. 795B35. 113305B. 157. 273. 388.
2015 463768. 806078. 1148389. 159. 276. 393.
2016 468924. 816322. 1163720. 161. 280. 399.
2017 474081. 826565. 1179050. 162. 283. 404.
2018 479237. 836809. 1194381. 164. 287. 409.
2019 484394. 847053. 1209712. 166. 290. 414.
2020 489550. 857296. 1225043. 168. 294. 420.
2021 495795. 869445. 1243096. 170. 298. 426.
2022 502040. 881594. 1261149. 172. 302. 432.
2023 508286. 893743. 1279201. 174. 306. 438.
2024 514531. 905892. 1297254. 176. 310. 444.
2025 520776. 918041. 1315307. 179. 314. 450.
2026 527021. 930190. 1333360. 180. 319. 457.
2027 533266. 942339. 1351412. 183. 323. 463.
2028 539512. 954488. 1369465. 185. 327. 469.
2029 545757. 966637. 1387518. 187. 331. 475.
2030 552002. 978786. 1405571. 189. 335. 481.
u
~'\ ' , , ,
NOT E: TO POGRAPHY FROM U. S. G. S. -LIVENGOOD, BEAVER
ALASKA. I: 250.000
LEGEND
~ DAM SITE
•. POWERHOJSE o SITE NO
•• ---PENSTOCK
---TRANS MtSSION LINE
--WATERSHED
, ,,. -----..;;;,.
5 0 5
seAL E IN MILES
REGIONAL INVENTORY .:. REOONNAISSANCE SfUOV
SMALL HYDROPOWER PROJECTS
NORTHEAST ALASKA
HYDROPOWER SITES IDENTIFIED'
IN PREUMINARY SCREENING
STEVENS VILLAGE.
DEPARTMENT OF THE ARMY
ALASKA DISTRICT CORPS OF ENGINEERS
SUMMARY DATA SHEET
U PRELIMINARY SCREENING
STEVENS VILLAGE, ALASKA
t1Ydropower Potent; a 1
Cost of
Installed Installed Al terna1f ve Cost of
Capacity Cost PowerJ f1ydropower Benefit/Cost
Site No. (kW) (S1000) (mills/kWh) (m; 11 s/kWh) Ratio
3 55 1,575 560 738 0.76
4 68 1,661 560 762 0.74
1 187 3,869 560 1,020 0.55
2 251 6,734 560 1,739 0.32
Demographic Characteristics
1981 Population: 88
1981 Number of Houeho 1 ds: 20
Econom; c Base
Unknown
u 1/ 5 Percent Fuel Escalation, Capital Cost Excluded.
REGIONAL INVENTORY & RECONNAISANCE STUDY -Sf1ALL HYDROPOWER PROJECTS
ALASKA DISTRICT -CORPS OF ENGINEERS
YEAR
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
LOAD FORECAST -STEVENS VILLAGE.
KILOWATT-HOURS PER YEAR
LOW MEDIUr·1 HIGH
O. O. O.
40851.
81702.
122553 •.
163404.
204255.
245106.
285957.
326808.
367659.
408510.
425595.
442680.
459765.
476850.
493935.
511019.
528104.
545189.
562274.
579359.
594145.
608931.
623717.
638504.
653290.
668076.
682862 •.
697648.
712434.
727220.
735782.
744344.
752905.
761467.
770029.
778591.
787153.
795715.
804276.
812838.
823207.
833577.
843946.
854316.
864685.
875054.
885424.
895793.
906162.
916532.
40851.
81702.
122553.
163404.
204255.
245106.
285957.
326808.
367659.
408510.
448263.
488015.
527768.
567520.
607273.
647025.
686778.
726530.
766283.
806035.
850767.
895498.
940230.
984962.
1029693 •.
1074425.
1119157.
1163889.
1208620.
1253352.
1270360.
1287369.
1304377 •
1321386.
1338394.
1355402.
1372411.
1389419.
1406427.
1423436.
1443608.
1463780.
1483951.
1504123.
1524295.
1544467.
1564638.
40851.
81702.
122553.
163404.
204255.
245106.
285957.
326808.
367659.
408510.
470930.
533350.
595770.
658190.
720610.
783030.
845450.
907870.
970290.
1032710.
1107388.
1182065.
. 1256743.
1331420.
1406098.
1480775.
1555453.
1630130.
1704808.
1779485.
1804940.
1830395.
1855849.
1881304.
1906759.
1932214.
1957668.
1983123.
2008578.
2034033.
2064007.
2093982.
2123956.
2153931.
2183905.
2213880.
2243854.
1584810. ··2273829.
1604982.
1625154.
2303803.
2333778.
ANNUAL PEAK DEMAND-KW
LOW MEDIUM HIGH
O.
14.
28.
42.
56 •.
70.
84.
98.
112.
126.
140.
146.
152.
157.
163.
169.
175.
181-
187.
193.
198.
203.
209.
214.
219.
224 •.
·229.
234.
239.
244.
249.
252.
255.
258.
261.
264.
267.
270.
273.
275.
278.
282.
~85.
289.
293.
296.
300.
303.
307.
310.
314.
o.
14.
28.
42.
56.
70.
84.
98.
112.
126.
140.
154.
167.
181.
194.
208.
222.
235.
249.
262.
276.
291.
307.
322.
337.
353.
368.
383.
. .399.
414.
429.
435.
441.
447.
453.
458.
464.
470.
476.
482.
487.
494.
501.
508.
515.
522.
529.
536.
543.
550.
557.
o.
14.
28.
42.
56.
70.
84.
98.
112.
126.
140.
161.
lB3.
204.
225 •.
247.
268.
290.
311.
332.
354.
379.
405.
430.
456.
482.
507.
533 •.
558 •
. 584.
609.
618.
627.
636.
644.
653.
662.
670.
679.
688.
697.
707.
717.
727.
738.
748.
758.
768.
779.
789.
799.
u
c
Z·~j·· ----
5 o
.8 t==I F3
SCALE IN MILES
NOTE' TOPOGRAPHY FROM U.S.G.S.-WISEMAN
ALASKA. 1:250,000
,
LEGEND
DAM SITE
'RAI~SlVIIS$:rON LINE
HYDROPOWER SITES IDENTIFIED
IN PREUMINARY SCREENING
WISEMAN
DEPARTMENT OF THE ARMV
ALASKA DISTRICT CORPS OF ENGINEERS
SUMMARY DATA SHEET
~ PRELIMINARY SCREENING
WISEMAN, ALASKA
Hydropower Potenti a1
Cost of
Installed Installed Alternative Cost of
Capacity Cost Powerll Hydropower Benefi t/Cost
Si te No. (kW) (SlOOO) (mi 11 s/kWh) (mi 11 s/kWh) Ratio
5 34 658 494 1,764 0.28
2 34 722 494 1,860 0.27
6 34 771 494 1,933 0.26
4 34 1,370 494 2,837 0.17
3 34 1,752 494 3,413 0.14
1 34 2,757 494 5,220 0.09
Demographic Characteristics
1981 Population: 12
1981 Number of Households: 3
Economic Base
Unknown
1/ 5 Percent Fuel Escalation, Capital Cost Excluded.
u
REGIONAL INVENTORY & RECONNAISANCE STUDY -SMALL HYDROPOWER PROJECTS
ALASKA DISTRICT -CORPS OF ENGINEERS
LOAD FORECAST -\VlSEMAN
\
KILOWATT-HOURS PER YEAR ANNUAL PEAK DEMAND-KW V
YEAR LOW t1EDIUM HIGH LOW MEDIm1 HIGH
1900 O. O. O. 0., O. O.
1981 5571. 5571. 5571. ' 2. " 2. 2.
1982 11141. 11141. 11141. 4. 4. 4.
1983 16712. 16712. 1671.2. 6. 6. 6.
'1984 22282. 22282. 22282. 8. 8. 8.
1985 ,27853. 27853. 27853. 10. 10. 10.
1986 33424. 33424. 33424. 11. 11. 11.
1987 38994. 38994. 38994. 13. 13. 13.
19138 44565. 44565. 44565. 15. 15. 15.
1989 50135. 50135. 50135. 17. 17. 17.
1990 55706. 55706. 55706. 19. 19. 19.
1991 58036. 62009. 65982. 20. 21. 23.
1992 60366. 68312. 76258. 21. 23. 26.
1993 62695. 74615. 86535. 21. 26. 30.
1994 65025. 80918. 96811. 22. 28. 33.
1995 67355. 87221. 107087. 23. 30. 37.
1996 69685. 93524. 117363. 24. 32. 40.
1997 72015. 99827. 127639., 25. 34. 44.
1998 74344. 106130. 137916. 25. 36. 47.
1999 76674. 112433. 148192. 26. 39. 51.
2000 79004. 118736. 151;468. 27. 41. 54.
2001 81020. 126001. 170982. 28. 43. 59.
2002 8303G. 133266. 183496. 28. 46. 63.
2003 85053. 140532. 196011. 29. 48. 67.
2004 870G9. 147797. 208525. 30. 51. 71.
2005 89085. 155062. 221039. 31. 53. 76.
2006 91101. 162327. 233553. 31. 56. 80.
2007 93117 • 169592. 246067. 32. 58. 84.
2008 95134. 176858. 258582. 33. 61. 89.
2009 97150. 184123. 271096. 33. 63. 93.
2010 99166. 191388. 283610. 34. 66. 97.
2011 100334. 194036. 287739. ,34. 66. 99.
2012 10f501. 196684. 291867. 35. 67. 100.
2013 102669. 199332. 295996. 35. 68. 101.
2014 103836. 201980. 300124. 36. 69. 103.
2015 105004. 204628. 304253. 36. 70. 104.
20l(> 106172. 207276. 308381. 36. 71. 106.
2017 107339. 209924. 312510. 37. 72. 107.
2018 108507. 212572. 316638. 37. 73. 108.
2019 109674. 215220. 320767. 38. 74. 110.
2020 110842. 217868. 324895. 38. 75. -111.
2021 112256. 221000. 329746. 38. 76. 113.
2022 113670. 224133. 334596. 39. 77. 115.
2023 115084. 227265. 339447. 39. 78. 116.
2024 116498. 230397. 344297. 40. 79. 118.
2025 117912. 233529. 349148. 40. 80. 120.
2026 119326. 236662. 353998. 41. 81. 121.
2027 120740. 239794. 358849. 41. 82. 123.
2028 122154. 242926. 363699. 42. 83. 125. U 2029 123568. 246059. 368550. 42. 84. 126.
2030 124982. 249191. 373400. 43. 85. 128.
u
APPENDIX A
UTILITY RATE SCHEDULES
Table A-I
North Slope Borough
Residential Electricity Rate Schedule -Kaktovik
Quantity Consumed per Month
(kwh)
under 100 kWh
101-600 kWh
Cost
ts Ikwh)
minimum charge of $15.00
.35
No charge for elderly or handicapped heads of households
Table A-2
Fort Yukon Utilities
Residential Electricity Rate Schedule
Quanti ty Consumed per Month
(kWh)
1st 100 kWh
next 400 kWh
next SOO kWh
Additional Charges
Fuel Surcharge per kWh
Table A-3
Cost
($ /kWh)
.3186
.1911
.1274
.08281
Golden Valley Electric Association
Interim Residential Electricity Rate Schedule
Quanti ty Consumed per Month
(kWh)
1st 100
next 1,400
over 1, SOO
Mi nimum charge
A-I
Cost
(J lkWh)
.186
.105
.0847
Sl1.35
u
APPENDIX B
METHODOLOGY FOR DRAINAGE BASIN INVENTORY
AND
PRELIMINARY SCREENING
APPENDIX B
METHODOLOGY FOR DRAINAGE BASIN INVENTORY AND PRELIMINARY SCREENING
This Appendix contains the assumptions and methodology used in the
drai nage" basi n inventory and prel imi na ry screeni ng phase for the
reconnai ssance study of small hydropower projects in Northeast Al aska.
The purpose of the first screening is to identify those potentially
viable hydroelectric sites which, based on a preliminary comparison
with costs of alternative thermal generation, warrant more detailed
i nvesti gati ons.
Outline of Proposed Methodology for Basin Inventory
and Preliminary Site Screening
A. Basi n Se 1 ecti on
1. Using USGS 1:250,000 maps locate each community and draw a
15 mile radius circle around the community center.
2. Visually reconnoiter all drainage basins. Select approxi-
mately the six (6) best sites, preferably located within the
circle, for investigation. Sites should be sized to meet the
following criteria:
Provide 80 percent of the year 2030 low demand scenario. This
is approximately equal to average day peak demand. Intertied
communities are sized based on the intertied average peak d~
demands for the communities in this study. Sites that exceed
the demand are costed to identify above average potential for
industrial or "new town" expansion. These sites are to be
scaled down to meet the above criteria in the second loop of
the evaluation process.
The sites for the 1 i st are to be selected ina logical manner,
beginning with the principal river or stream and moving thence
into the smaller tributaries. The best sites meeting the
above load criteria shall then be entered into the summary
table. No sites in Canada are considered.
3. Indicate the sites selected on the USGS map, including the
following features:
1) Drainage basin boundaries above damsite
2) Dam and powerhouse location
3) Penstock route
4) Transmission line route
5) Site identification number
B-1
B. Compilation of Summary Table
1. For each site selected for the Summary Table proceed to
measure and/or calculate the following parameters and enter
the values in the table:
a. Pl ani meter basi n areas (Ab) us; ng a zero setti ng
planimeter, calibrated to yield a value in square miles
in 2 passes;
b. Using maps obtained from Joint Federal State Land Use
Planning Commission estimate isolines for mean annual
runoff (Rm) in cfs per square mile;
c. Determine average flow:
( Q) = Ab X Rm ; n c f s ;
d. Measure transmission distance (D t ) in miles and
penstock length (Dp) in feet and record penstock
elevati on range;
e. Estimate gross head (H g ), the elevation difference
between damsite and powerhouse site, and add a 5 foot
diversion dam height allowance;
f. Calculate net head (Hn) as 90 percent x Hg;
g. Calculate installed c.apacity (Pi) in kilowatts as:
Pi = (1.5 x Q x Hn x 0.85)/11.8;
h. Calculate individual machine capacity (Mc) as Pi/N
(where N is the number of units, assumed to be 2 in this
study) ;
i. Calculate annual energy production (E) as:
E = Pi x P.F. x 8760 hr/yr,
where P.F. is the plant factor, equal to 0.45 for plant
sites where installed capacity exceeds 25 percent of the
2030 average day peak demand and 0.55 for sites with less
than or equal to 25 percent.
j. Using the modified Gordon-Penman equation estimate the
capital cost of generating equipment and powerhouse:
Ce = 13639.5 S KeKa (NM c )0.7 (Hn)-0~35
where S is the siting factor relating project cost to
powerhouse and equipment cost and is taken to be 3.7 for
plants less than 500 kW and 2.6 for plants greater than ( \
or equal to 500 kW. Ke is the escalation factor to ~
B-2
k.
October 1981 from January 1978, based on the composite
index from WPRS, and is equal to 1.35 for this study.
K is an Alaska cost adjustment which was assumed to be
2.00 for this study.
Calculate October 1981 transmission costs (Ct) in
dollars as follows:
1) Pi x Dt = kW -mi
2)
3)
4)
5)
6)
If kW -mi > 133,909, Ct (cost of transmission) =
300,000 Dt (115 kV, 3 phase)
If 24,000 < kW -mi < 133,909 (38 kV, 3 phase)
Ct = 150,000 Dt -
If 12,000 < kW -mi < 24,000 (14.4 kV 3 phase)
Ct = 120,000 Dt -
If kW -mi < 12,000
Ct = 50,000-+ 50,000 Dt (14.4 single phase)
If single wire ground return transmission systems
(single phase) are allowable and
kW -mi ~ 15,000 use
Ct = 50,000 Dt + 50,000
7) Submarine cable
550,000 x length of cable in miles
line losses are limited to 5 percent.
1. Calculate penstock costs (C p ) in dollars:
Cp = Ks [37.21 C1.5Q)1/2 -15] Dp Hn/600
where a minimum Hn is computed based on the USBR
minimum handling thickness design and used where the net
head is less than the resultant pressure for handling
thickness, Q min is 0.5 cfs, and K = 1.14, the
escalation factor to October 1981 from June 1980.
m. Mobilization and Dam costs (Cd) as follows:
10/81
Installed Capacity N(Mt)
0-100 kW
101-500 kW
501-1000 kW
>1000 kW
8-3
Cost of Mobilization plus Dam
S15O,000
250,000
400,000
600,000
Dam costs are based on 30 foot wide sheetpi1e dam, 5 feet
high and are estimated at $50,000. V
n. Calculate sum 0 f costs. (C s ) indo 11 ars
Cs = (C e + Ct + Cp + Cd) Kr
Where Kr is a remoteness factor, equal to 1.0 in the
Southcentra1 region.
o. Operation and maintenance costs are calculated as the
greater of 2 percent of capital costs or $40,000.
p. Calculate cost of energy (Ck) in mills per ki10wat hour
Ck = 0.09823 Kr Cs 1000 mill s/$
Where 0.09823 is the sum of the 0 and M factor, 0.02 and
0.07823, the alRortization factor at 7-5/8 percent
; nterest over 50 years.
1/ Kaktovik, Arctic Vi11age~ Wiseman, Venetie, Stevens Village,
Beaver,Bi rch Creek, Fort Yukon, Cha'i kyi tsi k.
Y All other northeast communities.
B-4
APPENDIX C
ECONOMIC ANALYSIS METHODOLOGY
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Northeast
APPENDIX C
ECONOMIC ANALYSIS METHODOLOGY
1.0 INTRODUCTION
The methodology used to perform the economic analysis of nydropower
sites is presented in this Appendix. The preliminary screening
methodology is discussed in Section 2.0, which includes the generic
assumptions that were applied to all sites investigated. The economic
analysis applied at the more detailed stage is discussed in Section
3.0. In Section 4.0 of this Appendix, the community of Venetie serves
as an example to illustrate the progression of analysis from the
preliminary screening through the detailed screening. Data tables for
Venetie, the same as those presented in Part II of the report, are
included with an explanation of how the results from the preliminary
and detailed screenings were derived.
2.0 PRELIMINARY SCREENING METHODOLOGY
2.1 Summary
Benefit/cost ratios were calculated for each site identified in the
drainage basin inventory. The objective of the economic analysis in
the preliminary screening was to compare the cost of nydroelectric site
development to the cost of the most likely alternative form of
electricity generation, which in all cases was assumed to be diesel or
combustion turbines. Plant sizes were based on low electric energy
growth projections. Fuel costs of alternative power were escalated at
rates of 0, 2, and 5 percent.
For the purposes of estimating the cost of alternative power, the
communities were classified into three categories: 1) isolated
communities; 2) communities that could utilize nydropower more
economically through interties than from independent systems, and
3) communities that are intertied currently and rely on electrical
power generated by diesel or other fossil fuel based systems. Diesel
generators were assumed to be the most likely alternative for isolated
communities, proposed intertied communities, and communities served by
Alaska Power and Telephone {AP and n. Combustion turbines were
assumed as the most likely alternative for the communities served by
Golden Valley Electric Association (GVEA).
Six sets of benefit-cost ratios were calculated based on 0, 2, and 5
percent fuel escalation, both including and excluding the capital costs
of alternative power. The criterion used for preliminary screening of
all identified sites was the set of benefit-cost ratios based on
5 percent fuel cost escalation, excluding the capital costs of
alternative power. The methodology for computing the costs of
alternative power, both including and excluding capital costs, is
presented in this Appendix. The benefit-cost ratios provided the basis
C-l
for identifying communities and sites which would for identifying
communities and sites which would be visited in the field and subjected
to more detailed reconnaissance-level investigation.
2.2.1 Cost of Hydroelectric Power
For each of the sites identified in the map reconnaissance, costs were
estimated for the major project components and then summed to provide a
total estimated capital cost. The project components for which
separate cost estimates were developed i ncl ude generation equipment
(including the powerhouse structure), penstocks, dams, mobilization,
and transmission facilities. The basis for estimating the costs of
these components is described in Chapter 6.0.
A plant factor of 0.55 for communities served by large utilities and
0.45 for other communities was used in establishing the cost of
hYdropower since it was assumed that not all power produced would be
consumed. The plant factor was assumed to reach these levels when
demand for power equaled or exceeded the supply.
Annual costs for each site were developed using a capital recover,y
factor based on an interest rate of 7-5/8 percent for project financing
over a 50-year project life, with additional costs included for
operation and maintenance. The average cost of electricity for~each
site was then based on the annual dollar expenditure for capital,
operating, and maintenance costs of the project divided by the
estimated annual electricity output. Specifically, the average cost
was computed for each year; then the averages were summed and divided
by 50.
The average cost of hYdroelectric power was calculated by the following
fonnul a:
~dro Costs in year t (HP t ) =
Where C = capital costs for year t
CRF = capital recover,y factor
o = operating costs for year t
HPt = hYdropower cost in year t .
kWht = power consumed in year t
(C x CRF) + 0 and M
kWh t
The CRF is taken for 50 years and kWht is defined as the kilowatt
hours produced by the project and consumed by the community in year t.
The kWht tenn adjusts for sites where the power output exceeds the
community (or intertied area) requirements. The term kWht is taken
from the load forecasts for the community, or in the case of a utility,
the summation of demand for all study area communities served by that
utility. The value used in the preliminary screening was 80 percent of
consumption in year 2030.11 In the detailed investigations, the term
1/ This was based on the assumption that the plant operates for
4380 hours per yea r.
C-2
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kWh was based on the demand in year 1997. The factor of 1.6, used in
both the preliminary screening and detailed investigations, accounts
for peak demand. ~dro costs were calculated using this term because
revenues from the hYdroelectric plant should be calculated from power
sold to the community rather than power produced.
The average annual cost of hYdropower (HP ave ) then was developed by
the follow; n9 fonnul a:
HPave = (~o HP t\ 50
t = 1981 :;
All costs are in 1981 dollars in that no general inflation or
escalation term has been built into the price forecasts. The
annualized capital cost of the hYdroelectric development is calculated
such that the net present value of the investment is SO in year 1981.
2.3 Cost of Diesel Alternative
2.3.1 Capital Costs Included
A stream of diesel costs in S/kwh were calculated for all isolated and
potentially intertied communities, and communities served by utilities
that use diesel generators. This cost stream was based on annualized
capital, operating and maintenance costs and, in the case of potential
interties, annualized transmission costs. Cost of fuel was calculated
using May 1, 1981 fuel prices. The formula used to calculate these
costs in any given year was the following:
lli esel Cost in year (OPt) = (C x CRF) + 0 and M + F
kWht
where C = capital costs for year t
CRF = capital recovery factor
o = operati n9 costs for year t
M = mai ntenance costs for year t
F = total fuel costs for year t (including lubricants)
UPt = diesel power cost in year t
kWh t = power produced and consumed in year t
An investment stream was calculated employing an average cost
calculation and based on an interest rate of 7-5/8 percent. The
present value of the capital investment was calculated using a capital
recovery factor. The capital costs were multiplied by a capital
recovery factor of .0991 based on a 20-year investment cycle. The
assumption of a 5 percent fuel escalation rate was used to calculate
diesel costs for the preliminary screening. For the potential
intertied communities, transmission costs were annualized based on a
capital recovery factor of .07823 for a 50-year investment cycle.
C-3
Other assumptions were used in calculating diesel generation costs.
Diesel generators were sized for peak hour of the final year of their
useful life (20th year), assuming the demand at that time would be 1.5
times greater than average demand. A diesel heft rate of 12.5 kWh/
gallon was used to calcul ate fuel requi rements.-' Operati ng time was
assumed to be 4380 hours per year, or half time on the average.
Assumptions regarding diesel costs are listed in Table C-1.
Average costs were then calculated as follows:
(
2030 \
DP ave = 1: 1981 DP y /50
All costs are in 1981 dollars in that no general inflatjon or
escalation tenn has been built into the price forecasts. The CRF tenn
annualizes the capital or investment cost such that the net present
value of the investment in year 1981 is $0. .
2.3.2 Capital Costs Excluded
A stream of diesel costs in $/kWh were calculated based on five percent
fuel cost escalation and excluding the costs of the diesel generators.
For each year, fuel costs were escalated at 5 percent from May 1, 1981
fuel prices and divided by the heat rate of diesel generators. The
arithmetic average of the cost of diesel power over the life of the
project was calculated by summing the values for each year and dividing
by the number of years (50).
2.4 Cost of Combustion Turbine Alternative
The alternative to hYdropower was assumed to be combustion turbines for
those communities that purchase electricity from Golden Valley Electric
Association, including Big Delta, Chatanika, Chena, and Delta
Junction. The Golden Valley Electric Association uses primarily diesel
fuel in the combustion turbines.
The assumptions used in the economic analysis of combustion turbine
power generation were the following:
25 year investment cycl e
heat rate of 10,500 Btu/kWh
capital cost of $720/kW for turbines 5-50 MW in size o and M cost of $0.005/kWh
1/ A heat rate of 12.7 kWh/gallon was derived from data provided by
Caterpillar Products and Sales Service. A value of 12.5 kWh/gallon
was used as a slightly more conservative estimate of the diesel
heat rate.
C-4
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Cost Parameters
Installed Capital
frlai ntenance
Operation
Fuel
Lubricant
TABLE C-l
DIESEL COST FACTORS
Factors
Derived from diesel cost curves provided by
Caterpillar Products and Sales Service
6 percent of installed capital improvements
1 worker per year for systems d MW
2 workers per year for systems >1 MW
Average annual salary of worker -$33,000
Varies with location -based on contacts with
utilities, fuel distributors, and trucking,
barge, and air carrier companies
10 percent of fuel costs
The equations for calculating the average cost of the combustion
turbine alternative were identical to the equations used to calculate
the average cost of diesel power, for both inclusion and exclusion of
capi ta 1 costs.
2.5 Benefit Cost Ratios for Preliminary Screening
Benefit/cost ratios were developed for screening purposes. Present
worth values were applied with respect to the capital investment of the
project. The generic formula employed was:
S/C ; Ave. Cost Diesel Power (S/kWh)
Ave. Cost Hydro Power (S/kWh)
I
The average was taken for power generated over the 1981-2030 period. A
B/C ratio yreater than 1.0 indicates that the hydro site is worthy of
further consi derati on.
Substituting the averaging equations into the generic equation yields
the following formula:
( 2030 DP) /SO
t ~ 1981 DP average B/C ;
( 2030
= HP average
HPj/50
t ~981
C-5
Because the DPt and HPt values are developed to yield an average
cost for a given system, where DP ave exceeds HP ave ' and BIC is \ )
greater than 1, the site should be retai ned for futher analysi s. Where "-"
DPaverage is greater than HPaverage' nydropower benefits represent
a cost savings over alternative sources of power •..
3.0 DETAILED INVESTIGATIONS METHODOLOGY
The detailed phase of economic analysis was performed for 7 sites
selected from t'he list of sites investigated in the preliminary
screening. At the conclusion of the preliminary screening, it was
decided that a community with sites having a benefit-cost ratio greater
than 1, based on 5 percent fuel cost escalation and excluding the
capital costs of alternative power, would be retained for more detailed
investigation. The capital cost of alternative power was excluded
because a nydroelectric facility would not be capable of meeting 100
percent of the power demand, thus necessitating alternative generating
methods to supplement hydropower.
Input to the detailed phase of economic analysis involved the
development of a plant factor program, revisions to the load forecasts,
and more detai 1 ed nydroel ectric cost estimates. It was assumed that
the nydroelectric plant would not begin to generate power until 1984.
This phase of analysis resulted in a new set of benefit-cost ratios
which is presented in Table 1-1 of the Overview.
4.0 SITE SPECIFIC EXN~PLE -VENETIE
This section uses Venetie as an example to illustrate how the economic
analysis was perfonned for sites located in the study area
communities. This section addresses the sequential process of applying
the economic analysis methodology through the preliminary and detailed
phases of investigation. All tables included in Part II of the report
are referenced in thi s section.
The methodology used to evaluate site feasibility involved the
comparison of benefit-cost ratios based on the arithmetic average of
nondiscounted nydropower and alternative power costs. All values are
in 1981 dollars since inflation was not accounted for. The present
value of capital investment was discounted over the period of analysis
usi ng a capital recovery factor.
4.1 Preliminary Screening
4.1.1 Introduction
Three sites were identified in the map reconnaissance of Venetie.
General costs of nydroelectric development for all three sites were
estimated. Alternative diesel generators were sized to meet the
projected electric energy requirements of the community. For both
nydroelectric development and diesel generation, the average discounted
costs were calculated.
C-6
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The load forecasts for Venetie are presented in Table C-2. Forecasts
were calculated for three growth scenarios (low, medium, high) as
explained in Chapter 3.0 of the Overview. It was decided that the low
growth scenari 0 vIas most representative of the future of northeastern
communities. The values for electric energy demand, expressed as
kilowatt hours per year, were input data to calculate both the cost of
alternative power and hYdroelectric power.
4.1.2 Diesel Cost Calculation
4.1.2.1 Capital Costs Included
Diesel costs were calculated by slzlng the diesel generator for the
three investment years -1981, 2001, and 2021. Values for the total
investment and the annual capital costs are presented in Table C-3.
Table C-3
Cost of Diesel Power Plant
Venetie
Total Capital Annual
Investment System Cost/kW Investment Recovery Capital
Year Si ze (kW) ( Z) on Factor Cost (Z)
1981 350 X 225 = 78,750 X .0991 = 7,804
2001 400 X 225 = 90,000 X .0991 = 8,919
2021 450 X 225 = 101,250 X .0991 = 10,034
Annual costs for operation and maintenance, fuel, and lubricant were
calculated and added to the cost of the capital investment. Taking
year 2001 as an example, the costs for year 2001 are presented in Table
C-4.
TABLE C-4
Annual Cost of Diesel Power, Year 2001
5 Percent Fuel Escalation
Venetie
(Dollars)
Capital Operation!! r4aintenance FuelY Lubricantll
8,919 5,400 33,000 369,650 36,965
Y 6 percent of $90,000 (see Table C-3)
~/ gal/kWh x kWh/yr x $/gal = Annual Fuel Cost
0.08 gal/kWh/ x 950,999 kWh/yr x Z4.86/gal = $369,650/yr
3/ 10 percent of fuel cost
C-7
Total
453,934
Table ~'-2
REGIONAL INVENTORY & RECONNAISANCE STUDY -SJ.tALL HYDROPOWER PROJECTS
ALASKA DISTRICT -CORPS OF ENGINEERS
LOAD FORECAST -VENETIE
KILOWATT-HOURS PER YEAR .ANNUAL PEAK DDtAND-KW V
YEAR LO\'l MEDItJPot HIGH LOW MEDIUM HIGH
1980 640000. 640000. 640000. 219. 219. 219.
1981 666766. 666766. 666766. 228. 228. 228.
1982 693533. 693533. 693533. 238. 238. 238.
1983 720299. 720299. 720299. 247. 247. 247.
1984 747066. 747066. 747066. 256. 256. 256.
1985 773832. 773832. 773832. 265. 265. 265.
1986 800598. 800598. 800598. 274. 274. 274.
1987 827365. 827365. 827365. 283. 283. 283.
1988 854131. 854131. 854131. 293. 293. 293.
1989 880897. 880897. 880897. 302. 302. 302.
1990 907664. 907664. 907664. 311. 311. 311.
1991 930829. 983805. 1036781. 319. 337. 355.
1992 953994. 1059946. 1165899. 327. 363. 399.
1993 977159. 1136088. 1295016. 335. 389. 443.
1994 1000324. 1212229. 1424134. 343. 415. 488.
1995 1023488. 1288370. 1553251. 351. 441. 532.
1996 1046653. 1364511. 1682368. 358. 467. 576.
1997 1069818. 1440653. 1811486. 366. 493. 620.
1998 1092983. 1516794. 1940603. 374. 519. 665.
19.99 1116140. 1592935. 2069720. 382. 546. 709.
2000 1139313. 1669076. 2198838. 390. 572. 753.
2001 1152727. 1752475. 2352223. 395. 600. 806.
2002 1166140. 1835875. 2505609. 399. 629. 858.
2003 1179554. 1919274. 2658994. 404. 657. 911.
2004 1192967. 2002673. 2812379. 409. 686. 963.
2005 1206381. 2086072. 2965764. 413. 714. 1016.
2006 1219794. 2169472. 3119150. 418. 743. 1068.
2007 1233208. 2252871. 3272535. 422. 772. 1121.
2008 1246621. 2336270. 3425920. 427. 800. 1173.
2009 1260035. 2419669. 3579305. 432. 829. 1226.
2010 1273448. 2503069. 3732690. 436. 857. 1278.
2011 1289693. 2539055. 3788416. 442. 870. 1297.
2012 1305939. 2575041. 3844142. 447. 882. 1316.
2013 1322184. 2611026. 3899868. 453. 894. 1336.
2014 1338429. 2647012. 3955594. 458. 907. 1355.
2015 1354674. 2682998. 4011320. 464. 919. 1374.
2016 1370920. 2718984. 4067046. 469. 931. 1393.
2017 1387165. 2754969. 4122772. 475. 943. 1412.
2018 1403410. 2790955. 4178498. 481. 956. 1431.
2019 1419655. 2826941. 4234224. 486. 968. 1450.
2020 1435901. 2862926. 4289951. 492. 980. 1469.
2021 1449156. 2899091. 4349026. .496. 993. 1489.
2022 1462412. 2935256. 4408100. 501. 1005. 1510.
2023 1475667. 2971420. 4467175. 505. 1018. 1530.
2024 1488922. 3007585. 4526249. 510. 1030. 1550.
I '\ 2025 1502177. 3043750. 4585324. 514. 1042. 1570.
2026 1515433. 3079915. 4644398. 519. 1055. 1591.
2027 1528688. 3116079. 4703473. 524. 1067. 1611. U 2028 1541943. 3152244. 4762547. 528. 1080. 1631.
2029 1555198. 3188409. 4821622. 533. 1092. 1651.
2030 1568454. 3224574. 4880696. 537. 1104. 1671.
~-8
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The nondiscounted cost of electricity ($.477/kWh) was obtained by
dividing the total annual cost (S453,915) by the amount of electricity
produced (950,999 kWh/year).
4.1.2.2 Capital Costs Excluded
The annual diesel costs were calculated by escalating the 1981 fuel
price ($1.83/gallon) at a 5 percent rate throughout the planning period
(50 years) and dividing that value by the heat rate of the diesel
generators (12.5 kWh/gallon). As shown in Table C-5 the nondiscounted
cost of alternative power if) year 1981, $0.146/kWh, was obtained by
dividing $1.83/gallon by the heat rate of 12.5 kWh/gallon. This
calculation was made for each year. The average cost of alternative
power ($.613/kWh) was calculated by taking the summation of values for
each year (30.669) dnd dividing that value by 50 years.
4.1.3 ~droelectric Cost Calculation
~~droelectric costs were calculated by sizing the plant for one
investment year -1981. Values for the total investment and the annual
costs are presented in Table C-6.
System
Investment Size
Yea r (kw)
1981 354
TOTAL C-6
Total Annual Costs of ~dropower
Kocacho Creek, Venetie
Installed
Cost
($)
Capital Annual
Recovery Cap; ta 1
Factor Cost
Annual ° and M ($)
Total
Annual
Cost
5,584,668 x 0.7823 = 436,889 + 111,693 = 548,582
The nondiscounted electricity costs were calculated for each year by
dividing the total annual cost by the amount of electricity produced.
An example of this procedure is shown in Table C-7.
Year
1981
2001
Total
Annual Cost
($ )
548,582
TABLE C-7
Cost of ~droelectric Energy
Kocacho Creek, Venetie
Electric Energy
Produced
( kWh/year)
divided by 550,082
548,582 divided by 950,999
C-9
Nondi scounted
Electricity Cost
(S/kWh)
= .997
= .577
Tabl e c-5 '
REGIONAL INVENTORY & RECONNAISANCE SltlnY -S~ALL HYDROPOWER PROJECTS
ALASKA DISTRICT -CORPS OF ENGINE~RS
DIESEL COSTS!IOW -VENETIE
YEAR $/KWH
1981 0.146
1982 O. i.SAt
1983 0.162
1984 0.170
19135 0.178
19B6 0.187
1987 0 .. 19t=.
1988 0.206
1989 0.216
1990 0.227
1991 0.239
1992 O.'?~j
1993 0.263
1994 \).276
1995 0.290
1996 0.305
1997 0.320
1998 0.336
1999 0.353
i~, 2000 0.370
2001 0.389
2002 0 .. 1,013
2003 0.4~9
2004 0.450
2005 0.472
?006 0.496
2007 0.521
2008 0.547
2009 0.574
2010 '0.603
2011 0.633
20L2 0.665
2013 0.698
2014 0.733
2015 0.770
2016 0.808
2017 0.848
2018 (). 89:i
2019 0.935
2020 \}.982
2021 1.031
202? 1.083
2i)23 :i.:i37
2024 1.194
,2()25 1.254
2\')26 1.316
2027 1.382
2028 " ,~. .J .. .f.~~.f.'
2029 1.524
2030 1.6t)O u
AVERAGE 0.6i3
C-IO
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The results of the preliminary screening indicated that site number 2,
Kocacho Creek, ranked highest among the three Venetie sites
investigated. Venetie was included in the communities visited in the
field. Observations in the field confirmed that this site was the most
favorable and, therefore, warranted a more' detailed analysis. Results
for communities with no sites IIsurviving" the preliminary screening are
presented in the tables entitled "Summary Data Sheet, Preliminary
Screeni ng" of Part II of the report.
4.2 Detailed Investigations
The secondary phase of economic analysis was performed after the site
visits and involved considerably more detail. Information gathered in
the field resulted in the refinement of some of the population and fuel
cost data. These revisions affected the load forecasts and the cost of
alternative power. Results of the detailed investigations are
presented for si te number 2 in Tabl e C-8 entitl ed IISummary Data Sheet,
Detailed Investigations". Similar tables are provided in Part II of
the report for each community with sites evaluated in the detailed
investigations phase of the study.
The results of the detailed investigations represent the cost of
alternative power based on a 5 percent fuel cost escalation and exclude
capital costs. The effect of excluding capital costs was to lower the
average cost of alternative power. The value of S.613/kWh, as shown in
Table C-8, represents an arithmetic average of the nondiscounted costs
of diesel power. It was calculated by taking the summation of values
for each year (30.669) and dividing that value by 50 years.
Hydropower costs were estimated in more detail. Layouts were developed
to reflect actual site conditions. In the case of unvisited sites,
more detailed mapping was utilized to develop conceptual costs. Site
specific data for each of the parameters presented in Table C-9 were
used to develop the cost data presented in Table C-IO. Further,
indirect costs were added to the direct construction costs, resulting
in significantly lower benefit-cost ratios than those resulting from
the preliminary screening. t~ethods used to derive project costs are
presented in Chapter 6.0 of the Overview.
Plant factors were calculated for each year to reflect the usable
energy from a hYdroelectric plant. The plant factors take into account
the limitations of hYdroelectric energy that could be sold, including
consumer demand, turbine limitations, and the available supply of
water. A plant factor of 33 percent for the 1 He cycle of the project
was derived from the load duration curve for isolated convnunities,
mi nimum turbi ne flow requi rements, and the load forecast for Veneti e.
Parameters used to determine the plant factor are presented in Table
C-ll.
C-ll
TABLE C-8
SUj\1t4ARY DATA SHEET
DETAILED INVESTIGATIONS
VENETI E, ALASKA
~dro~ower Potential
Cost of
Installed Installed Alternai}ve
Capacity Cost Power_
Site No. (kW) ($1000 ) (mills/kWh)
2 196 20,380 613
Demographic Characteristics
1981 Population: 160
Economic Base
1981 Number of Households: 45
Subs; stence
Government
Cqst of
Hydropower
(mills/kWh)
3,450
11 5 Percent Fuel Escalation, Capital Cost Excluded.
C-12
Benefit/Cost
Ratio
0.18
TABLE C-9
VENETIE -SITE 2
SIGNIFICANT DATA
DETAILED RECONNAISSANCE INVESTIGATIONS
1. LOCATION (diversion)
Stream: Kocacho Creek
Section!! 27, Township 27N, Range 7E, Fairbanks Meridian
Community Served: Venetie
Di stance: 10 mi
Direction (community to site): North-Northeast
Map: USGS, Christian, Alaska, 1:250,000
2. HYDROLOGY
Drainage Area:
Estimated Mean Streamflow:
Estimated Mean Annual Precipitation:
3. DIVERSION DAM
Type:
Height:
Crest Elevation:
Vol ume:
4. SPILLWAY
Type:
Openi ng Hei ght:
Wi dth:
Crest Elevation:
5. WATERCONDUCTOR
Type:
. Di ameter:
Length:
6. POWER STATION
Number of Units:
Tu rbi ne Type:
Tailwater Elevation:
Rated Net Head:
Installed Capacity:
Maximum Flow (both units combined):
Minimum Flow (single unit):
7. ACCESS
Length:
8. TRANSMISSION LIN~/
Voltage/Phase:
Terrain:~/ Flat (1.0)
Tota 1 Length:
9. ENERGY
Plant Factor:
Average Annual Energy Production:
t~ethod of Energy Computation:
10. ENVIRONMENTAL CONSTRAINTS: None noted
1/ Section number is approximate.
2/ Terrain Cost Factors Shown in Parentheses.
C-13
342
216
9
sq mi
cfs
in
Large Concrete Gravity
10 ft
660 fmsl
1920 cu yd
Cone rete Ogee
5 ft
260 ft
1920 fmsl
Ste'el· Penstock
66 in
5810 ft
2
Cross Flow
625 fmsl
31. 5 ft
196 kW
92 cfs
9.2 cfs
1.1
14.4
10.0
1O~0
mi
kV/l phase
mi
mi
33 percent
564 MWh
Pl ant' Factor Program
TABLE C-10
HYDROPOWER COST DATA
DETAILED RECONNAISSANCE INVESTIGATIONS
ComlDu ni ty :
Site:
Stream:
Venetie
2
Kocacho Creek
Item
1. Dam (including intake and spillway)
2. Penstock
3. Powerhouse and Equipment
-Turbines and Generators
-Misc. Mechanical and Electrical
-Structure
-Valves and Bifurcations
4. Switchyard
5. Access
6. Transmission
TOTAL DIRECT CONSTRUCTION COSTS
7. Construction Facilities and Equipment,
Camp, Mobilization, and Demobilization
TOTAL INDIRECT CONSTRUCTION COSTS At 20 PERCENT
SUBTOTAL
Geographic Factor =
SUBTOTAL
Conti nyency at 25 percent
SUBTOTAL
Engineering and Administration at 15 percent
TOTAL CONSTRUCTION COST
Interest Our; ng Construction at 9.5 percent
TOTAL PROJECT COST
Cost per kW Installed Capacity
ANNUAL COSTS
Annuity at 7-5/8 percent (AlP = 0.07823)
Operations and Mai ntenance Cost at 1.5 percent
TOTAL ANNUAL COSTS
Cost per kWh
Benefit-Cost Ratio
C-14
COST
~ 571,000
$ 1,569,000
$ 373,000
$ 188,000
$ 210,000
S 6,000
S 188,000
S 17,000
S· 250,000
$ 3,372,000
$ 674,000
S 4,046,000
3.2
S12,947,000
S 3,237,000
S16,184,000
S 2,428,000
$18,612,000
S 1,768,000
$20,380,000
S 104,000
S 1,594,300
S 305,700
$ 1,900,000
S 3.45
0.18
Community: Venetie
Si te Number: 2
Net Head (Ft): 32
TABLE C-ll
PLANT FACTOR PROGRAM
Design Capacity (kW): 196
Minimum Operating Flow (1 Unit) (CFS): 9.20
Load Shape Factors: 0.50 0.75 1.60 2.00
Hour Factors: 16.00 15.00 13.00 3.00
Potenti al
Average Hydroelectric
Month r>1onthly Energy
(aDays/Mo. ) Flow (CFS) Generation (kWh)
January 14.10 22443.
Februa ry 11.20 16102.
March 11.00 17509.
April 14.50 22335.
tJfay 820.00 145824.
June 671.00 141120.
July 206.00 145824.
August 316.00 145824.
September 371.00 141120.
October 86.90 138318.
November 34.40 52988.
December 20.50 32630.
TUTAL 1022037.
Plant Factor (1997) : 0.31
Plant Factor (Life Cycle): 0.33
C-15
Percent of Energy Usable
Average Demand Hydro
Annual Energy ( kWh) Energy
10.00 106982. 14962.
9.50 101633. 10735.
9.00 96284. 11672.
9.00 96284. 14890.
8.00 85585. 82417.
5.50 58840. 58840.
5.50 58840. 58840.
6.00 64189. 64189.
8.00 85585. 81829.
9.00 96284. 82946.
10.00 106982. 35325.
10.50 112331. 21753.
1069818. 538399.
The hYdropower cost data and the benefit-cost ratio for the detailed
investigation are presented in Table C-12. The value of $3.452/kWh
represents an arithmetic average of nondiscounted hydropower costs.
This value was obtained by calculating the summation of costs for each
year (162.22) and dividing it by the number of years (47). For
Venetie, the average cost of alternative power (613 mills/kWh) was
divi ded by the average cost of hydropO\'1er (3452 mi 11 s/kWh) to obtai n a
benefit-cost ratio of 0.18.
C-16
v
.TYPE AH7 L m:H Table C-12
lREGIONAL INVENTORY & RECONNAISANCE STUDY -SMALL HYDROPOWER PROJECTS
ALASKA DISTRICT -tORPS OF ENGINEERS
DETAILED RECONNAISSANCE INVESTIGATIONS
o COST OF HYDROPOWER -BENEFIT COST RATIO
VENETIE
SITE NO.
o $/KWH $n:~WH
(I
o
YEAR
1 f~:=:4
19::::5
1'~/:::7
1990
1 '~I'~1 1
1 ;'92
199~:
1994
19';:'5
1996
1997
1999
20<)0
2001
2002
200:3
2004
20(15
200t.
2007
2()():=:
2009
2010
2011
2012
201 ::;:
2014
2015
2016
2017
2018
20 1 '"i'
2020
2021
202:~:
2024
KWH/YEAR
422454.
444:::::;;::~i .
4~5!50:21 •
4(:'~5716.
476411.
4S'41~J'~/:3 It
~i():::::32:=: •
510661.
5176(10.
524540.
5:::: 14:3().
~i:;:83''''';) •
545290.
551454.
557107.
559667.
5C,2226.
564786.
567~:46.
569906.
5723t~t,.
574755.
57711:3.
57'r472.
581831.
5:34594.
5f::7227.
5 ~::t~""E~I:., () •
5';-~~:31 !:: •
!'594727.
!:i97137.
5';:/9547.
601':;/51.:,.
604:::::66.
606776.
60E:742.
61.0708.
612,1:,7~).
614641.
616607.
CAPITAL
1604721.
1604721.
1.604721.
1604721.
1(:.04721.
1604721.
1604721.
1604721.
1604721.
1604721.
1604721.
1604721.
1604721.
1604721.
1604721.
1604721-
1604721.
11.:,04721.
1604721.
1604721.
1604721.
1604721 ~
1604721.
1604721.
1604721.
1604721.
1604721.
1604721.
1604721.
1604721.
1604721.
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1604"721.
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1(~,04721 ,
2026 61857~, 160472].
2027 620152.
202::::: 6:;;:: 1 ~:i88.
:2029 ,1:,2::::0:24.
U·(l47:21.
16047:2'1.
16047:~:t ,
2(130 624460. 1604721.
AVEHACiE COST
BENEFIT-COST RATIO (5% FUEL
(I S< M
:305700.
305700.
::;::1)5700.
::::05700.
305700.
305700.
305700.
305700.
:305700.
305700.
305700.
:;:05700.
:305700.
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305700.
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305700.
305700.
305700.
305700.
:305700.
305700.
305700.
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:;:05700.
305700.
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::;:05700.
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305700.
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:305700.
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C-17
TOTAL$
1910421.
1';:'10421.
1'rl0421.
1910421.
1910421.
1910421.
1'::'10421.
1910421.
1910421.
1910421.
191(1421.
1910421.
1910421.
1910421.
1910421-
1910421-
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1910421.
1910421.
1910421-
1910421.
1910421.
1910421.
1910421.
1910421.
1910421.
1910421.
1910421.
1910421.
1910421-
1910421.
1910421.
1910421.
1910421.
1910421.
1910421.
1910421.
1910421.
1910421.
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1910421.
1910421.
'[9:1 ')4:::;: 1 •
'91 04:n.
191(lLL;~1 ,
1':" j lH21.
1 ';, 1 04::::: 1. •
NONDI::::C
4-.522
4.406
4. :300
4.199
4.102
4.010
3. E:59
3.7';J/:..
3.741
3.691
3.642
3.595
3.548
3.503
3.464
3.429
3.413
3.398
3. :383
3. ~:67
3.352
3.338
3.324
3.310
:3.297
:3.283 .
3.268
3.253
:3.239
3.225
3.212
3.199
3.174
3.161
:3. 14::::
::::. 1:~:8
~:. 12:3
:3. 118
:3. 10:::
:;:" (J::: 1
:3" CI~'1 ::~:
::: It <'~~'~J
:?: .. i~ ~:::~:.?
DISC
:3" ::~!71
::::.051
2.71:.,7
2.51c)
2. 27'7J
2.070
1. ::::::::::
1.720
1.572
1.4:3;'
1.319
1.210
1.109
1.017
0.933
0.858
0.789
0.729
0.675
O.62~
0.577
0.534
0.494
0..457
0.42:3
0.391
0.362
0.335
0.310
0.287
0.265
0.245
0.227
0.210
0.194
o. 1::::0
0.167
0.154
o. 14:3
0.1:32
0.114
0 .. 1 O~:i
0 .. 0':'1-7
0.090
0,0:>1
0 .. n~i':':
0"::::;:;'::::