HomeMy WebLinkAboutSmall Hydro Electric Inventory 2 of 2 1979Aia ' a pow: r Authority
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FOREWORD
The purpose of this report was to document the results of a hydroelec-
tric powersite reconnaissance, prepared by Alaska Power Administration
(Department of Energy), for the majority of western Alaska served by the
Alaska Village Electric Cooperative (AVEC). The report discusses: (1)
method of study, (2) criteria used for site evaluation, (3) basic data
used, and (4) cost estimating procedure and economic analysis methods.
The sites with the best hydro potential are identified as well as the
sites.near villages that have no likelihood for development.
It is APA's sincere hope that this report will provide some help and
direction for eventually developing other forms of electric energy so
that villages can reduce their dependence upon high-priced fuel oil for
their everyday energy needs.
APA appreciates the assistance received from AVEC personnel in Anchorage
and in the villages. We also want to thank the many local villagers who
gave us invaluable insight into the village economic and energy situa-
tion and local streamflow characteristics.
i
TABLE OF CONTENTS
TITLE PAGE NO,
FOREWORD i
TABLE OF CONTENTS
ii
PART
I - INTRODUCTION
1
PART
II - CONCLUSIONS AND RECOMMENDATIONS
4
PART
III - GENERAL DISCUSSION OF HYDRO TECHNOLOGY
7
PART
IV - STUDY METHODOLOGY
14
PART
V - INDIVIDUAL VILLAGE HYDROELECTRIC POTENTIAL
18
Villages with best hydro potential
Ambler
19
Elim
26
Goodnews Bay
31
Grayling
36
Kaltag
42
Kiana
49
Scammon Bay
56
Shungnak
65
Togiak
70
Old Harbor
74
Villages studied, but no economical hydro potential
77
Kalskag/Lower Kalskag
78
Mekoryuk
83
New Stuyahok
89
Tanunak
93
Toksook Bay
100
Wales
104
Villages without hydro potential
110
Yukon-Kuskokwim Delta Area
111
Alakanuk
112
Chevak
113
Eek
112
Emmoanak
112
Hooper Bay
114
Kasigluk
115
Nunapitchuk
115
Quinhagak
116
ii
TITLE PAr_v Mn
Lower Yukon River Area
117
Anvik
118
Holy Cross
119
Huslia
121
Marshall (Fortuna Ledge)
122
Mountain Village
123
Nulato
124
Pilot Station
125
Pitkas Point -St, Mary's
126
Shageluk
129
Norton Sound Area
130
Koyuk
131
Shaktoolik
132
St. Michael
132
Stebbins
133
Kotzebue Sound Area
134
Kivalina
135
Noatak
136
Noorvik
136
Shishmaref
137
Selawik
137
Buckland (potential AVEC village)
138
Deering (potential AVEC village)
138
Sites Not Examined 139
TABLES
1, INVESTIGATION COSTS 5
FIGURES
1. GENERAL MAP iv
2, TYPICAL DIVERSION 10
A - Project Cost Calculation Sheets
B - Load/Streamflow Curves
C - Existing Loads and Installed Capacity
D - Investigation Costs
iii
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UNITED STATES DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
GENERAL MAP
VILLAGES SERVED BY
ALASKA VILLAGE ELECTRIC COOPERATIVE
• December 1979.
Oil) HARBOR RB R
PART I. INTRODUCTION
In April 1979, Alaska Power Administration (APA) initiated a reconnais-
sance of hydroelectric potentials for the majority of native villages in
western Alaska which currently depend on their electric power generation
provided by the Alaska Village Electric Cooperative,(AVEC). The purpose
was to identify small-scale hydropower sites that might provide either
full-time or seasonal energy to the villages, or verify that the vil-
lages have no hydroelectric potential within reasonable distance, Past
Alaska Power Administration's statewide inventories have concentrated on
larger (over 2,500 kW) powersites, and no specific efforts had been made
to locate sites to serve these small villages. This is part of APA's
general investigation program of identifying hydropower as alternative
to diesel fuel generation for the "bush" area of Alaska,
The "bush" villages are widely scattered throughout Alaska but are
primarily located in the west. They generally range in size from about
50 to 700 people. Access to the village is by air or seasonal boats and
barges or snow machine. Fewer than a dozen are connected by a road
system, The village economy is based primarily on subsistence hunting
and fishing which results in many unemployed or only seasonally employed
people. Average family income is about $12,000 annually, with a dis-
proportionate large share coming through various public assistance
programs according to the 1978 Alaska Division of Economic Enterprises
report. This figure needs to reflect higher Alaskan living costs and
decreased purchasing power of the dollar in Alaska. The cost of living
in Alaska varies from 30 to 100 percent higher than the U.S, average,
Food prices in a regional trade center such as Bethel reached 200 per-
cent of Seattle prices in 1977. Outlying villages pay an additional
markup for air freight on food and other goods flown in which can
increase prices to 300 percent of Seattle prices,
All the Alaska remote villages are dependent upon diesel fuel for their
power supplies and for home heating. Wood, where available, is used to
some extent for home heating. Except for the middle Yukon River area
and Upper Kobuk River area, villages do not have ready access to wood
supplies. Because of the remoteness of the villages, all oil supplies
are brought in only once a year. Present costs of oil .delivered range
upward to $2.50 a gallon (summer of 1979) This cost of fuel plus
service has resulted in power costs to individuals in excess of 404 per
kWh for villages served by AVEC with further price increases sure to
follow recent OPEC price increases. Twenty-eight cents per kWh is
directly attributable to generation costs and of that, 170 are directly
fuel costs. The remainder of the cost is for depreciation, interest,
insurance, operation, maintenance, management, and operation and main-
tenance of distribution systems. These costs compare to about 3C per
kWh for residents in the Anchorage area that enjoy low-cost gas sup-
plies, and 5C per kWh for Juneau residents supplied primarily from the
Snettisham hydroelectric project.
1
The electric power loads in the villages are small, generally ranging
from 50 kW to 1,o00 kW. Existing loads and installed capacities for the
villages are found in appendix C. These high costs of electric service
as mentioned above have resulted in most villages using only minimal
amounts of electricity. The rapid increase'in electric rates means that
the objective of an improved and equitable quality of life and increased
economic opportunity can not be met unless methods to reduce costs are
found.
The village power costs are to a point that continued viability of
service is seriously threatened. If adequate electric service is not
made available at affordable costs, the villages have no chance of
developing their economic self-sufficiency.
The approach taken to analyze the hydro potentials was to examine exist-
ing maps of the village areas and determine if any streams with hydro-
electric potentials are within reasonable distance of the villages.
Streamflows were estimated and combined with a potential plan derived
from the map and rough cost estimates were made. These costs were then
compared to diesel costs ranging up to $3.50 per gallon. If this par-
ticular development did not seem to be economical compared to this cost
of diesel, under various assumptions the site was written off. Sites
that appeared to have economic viability were then examined on a week-
long airplane tour by Alaska Power Administration engineers, Don Shira
and Don Gotschall and AVEC engineer, Jerry Larson. The following is a
list of the AVEC villages:
Alakanuk
Ambler
Anvik
Chevak
Eek
Elim
Emmonak
Fortuna Ledge
Gambell
Goodnews Bay
Hooper Bay
Huslia
Lower Kalskag
Kaltag
Kasigluk
Kivalina
Kiana
Mekoryuk
Koyuk
Mt. Village
Minto
Noatak
New Stuyahok
Nulato
Noorvik
Old Harbor
Nunapitchuk
Pitkas Point
Pilot Station
Quinhagak
St. Mary's (Andreafsky)
St. Michael's
Savoonga
Scammon Bay
Selawik
Shageluk
Shaktoolik
Shismaref
Shungnak
Stebbins
Togiak
Toksook Bay
Tununak
Upper Kalskag
Wales
Forty-one of the 48 AVEC villages were visited. Gamble and Savoonga on
St. Lawrence Island were not visited because it required an extra full
day and charter of a twin -engine aircraft. Because of the very flat
2
terrain and the associated unlikely hydroelectric potential around
Emmonak and Alakanuk, their sites were not visited. Minto is in central
Alaska, considerably out of the flight path, and was not visited, Old
Harbor on Kodiak Island is part of a preliminary feasibility study of
Kodiak Island hydro potentials presently being conducted by Alaska Power
Administration,
The following chapters detail the method of analysis, cost estimates,
results of the findings, and recommendations for further studies.
3
PART II. CONCLUSIONS AND RECOMMENDATIONS
CONCLUSIONS:
It was found that generally there is little hydroelectric potential in
the area investigated. Because of topography, climate and hydrology the
resource is much less than found along the Gulf Coast and Southeast
Alaska.
The office studies that were made of the hydro potentials near 48 AVEC
villages indicated that 15 had an economic chance for development. In
August 1979, APA and AVEC engineers made a field examination of 41 of
the village sites to verify office study results. The field examination
determined that nine of the villages had hydro sites favorable for
further study. They are: Scammon Bay, Elim, Goodnews, Togiak, Kaltag,
Grayling, Shungnak, Kiana, and Ambler. A summary of the investigation
costs for each of these villages are listed in table 1. These costs are
considered minimum to satisfy FERC requirements for a minor hydroelec-
tric project license.
The study indicates there are no economical storage sites, except pos-
sibly in the Kobuk River Basin. This is partly due to small loads which
limit the length of transmission lines that can be afforded, but pri-
marily the topography is unfavorable for water storage projects.
The study identified other potential optional energy sources such as:
(1) mind sites near coastal villages and (2) coal deposits near the
village of Grayling. It also identified transmission interconnection
possibilities in the Kobuk River valley.
RECOMMENDATIONS:
1. It is recommended that further investigations be made of the above
mentioned nine hydro sites to determine engineering and economic feasi-
bility. These studies should be of sufficient detail to satisfy minimum
licensing requirements outlined by the Federal Energy Regulatory
Commission.
2. Agencies such as the Corps of Engineers and the State of Alaska
should be contacted early -on to determine capability to conduct further
studies of these nine sites. The Corps has been apprised of preliminary
results of this investigation.
3. First priority funds and efforts should be devoted to early devel-
opment of the Scammon Bay and Elim sites due to the strong chance of
good year-round flows. Second priority should be on the Togiak and
Goodnews sites. The possibility of winter freeze-up on these streams
needs to be identified. The third priority would be the streams in the
Kobuk region. There are several potentials in this area and the streams
could have year-round flows. The fourth priority would be for the sites
at Kaltag and Grayling. These sites have good potential; however, the
streams are of a larger and flatter characteristic than those of the
4
TABLE 1
INVESTIGATION COSTS
Small Hydro
Inventory
of Villages Served by
AVEC
SCANMON
OLD
WORK ITEM
SHUNGNAK
BAY
TOGIAK
GRAYLING
KALTAG
AMBLER
KIANA
ELIM
GOODNEWS
HARBOR
Run -of -River
Storage Plan
Stream Gaging
$ 8,930
$ 4,970
S 3,320
$ 5,600
$ 4,500
$ 9,660
$ 8,930
$ 8,930
$4,700
$ 1,160
$15,000
Surveying &
Mapping
9,180
5,690
6,300
10,750
10,600
10,910
10,310
18,640
7,360
4,290
7,400
Sail & Geology
Examination
1,620
1,750
1,880
1,800
1,460
4,140
1,620
3,940
1,850
1,350
1,200
Fish & Wildlife
Studies
1,950
1,360
1,300
1,250
1,050
1,950
1,950
1,950
1,200
790
1,000
Project Design &
Cost Estimates
6,000
6,000
1,000
6,000
6,000
6,000
6,000
12,000
6,000
6,000
6,000
Subtotals
$27,680
$19,750
$18,800
$25,400
$23,610
$32,000
$28,810
$45,450
$21,110
$12,580
Contingencies 20%
& Inflation 1OS
8,300
5,930
5,640
7,600
7,080
9,800
8,640
13,640
6,330
4,070
TOTAL (Rounded)
$36,000
$26,000
$25,000
$35,000
$35,000
$45,000
$40,000
$60,000
$28,000
$20,000
$31,000
sites in the first three priorities. Streams of this type can be
expected to be more costly to develop than the smaller, steep gradient
streams.
4. Wind power alternatives should be investigated for the coastal and
other selected western Alaska villages which do not have hydropower
alternatives.
5. The potential for coal development at the village of Grayling
should be investigated further based on data discovered in this study.
6. The possibility of expansion of
transmission system to include tying
operations, should be investigated.
the planned Shungnak-Kobuk SWGR
in Ambler and the local mining
7. Previous estimates by APA on the Old Harbor site did not appear
feasible. However, surveys conducted during the summer of 1979 indi-
cated a perched lake having sufficient size and outflow to warrant
further investigation. APA will proceed with these studies during 19 M
PART III. GENERAL DISCUSSION OF HYDRO TECHNOLOGY
Introduction
This section is intended to be a basic discussion of the conditions and
engineering features required to develop an economical small hydroelec-
tric project, such as the size and types required for the AVEC villages,
It also discusses various types of small hydro installations that would
be adaptable to village conditions; the process OF sizing turbine/gener-
ator sets, and economic. analysis, The type of project applicable to
most of the villages is the stream diversion project with a run -of -river
water supply. Projects requiring dams and water storage encounter a
whole new group of problems including significantly higher costs, earth
work in permafrost areas, and increased engineering to insure stability
of structures in an arctic environment,
Background
Hydroelectric power has been generated in the United States for nearly a
century, The first U.S". hydroelectric powerplant went into operation at
Appleton, Wisconsin, in 1882 with a generation capacity of 200 kW, The
trend was for the development of larger and larger powerplants, thus
small hydro development was essentially ignored.
Today, small-scale hydroelectric power generation has become desirable
for four reasons: (1) rapidly increasing costs of fossil fuels, (2) in-
creasing costs of alternative thermal generating plants, (3) environ-
mental impacts of large dams and the extensive water impoundments asso-
ciated with such projects, and (4) the need to develop renewable energy
resources to conserve scarce fossil fuels.
Small-scale hydroelectric power development offers many advantages as an
alternate energy source, They are relatively nonpolluting and are
dependent on renewable resources; the facilities are small and can blend
in with the natural environment; the effects upon the natural stream
ecology are minor compared to conventional large hydroelectric facili-
ties and may, in fact, enhance the streams by maintaining water depth
sufficient to support aquatic life,
Present Small Hydro Technology
There are two basic categories of turbines utilized for hydroelectric
generation. These are the impulse turbine and reaction turbine. The
impulse turbine derives its power from the action of the moving water
striking a surface, thus imparting motion to the surface. The total
drop in pressure takes place in one or more stationary nozzles and there
is no change in pressure of the fluid as it flows through the rotating
wheel. The reaction turbine derives its power from the reaction occurr-
ing when the direction of the moving water is changed. The major por-
tion of the pressure drop takes place in the rotating wheel. Since the
entire circumference of the reaction turbine is in action, its rotor
need not be as large as that of an impulse wheel for the same power,
7
Another means of comparison is to say the impulse turbine draws power
from the velocity of the moving water while the reaction turbine depends
on the mass or weight of the moving water.
In the impulse turbine category there are the Pelton wheel and the
crossflow turbine with the Pelton wheel being more numerous. The Pelton
wheel uses one or more nozzles to direct a jet of water to a series of
cups mounted on the circumference of the wheel. Since they operate at
best efficiency at high heads, they are not normally used at heads of
less than 50 feet. The crossflow turbine, on the other hand, directs a
rectangular -shaped stream of water through a ring of blades on a barrel -
shaped rotor, first from outside to inside and then, after crossing the
interior of the. runner, from inside to outside again. These turbines
have a wide range of operating heads and may be used for applications
involving heads as low as 10 feet,
The reaction turbine category covers many types of turbines and in-
cludes: (1) Francis, (2) Propeller, (3) Kaplan, (4) Tube, (5) Bulb, and
(6) Rim. For low flow applications the Francis or open -type Francis for
low head would be most suitable. This turbine routes water to the
runner through a series of guide vanes with contracting passages. These
vanes are adjustable so that the quantity and direction of flow can be
controlled. Flow through the Francis runner is at first inward in the
radial direction, gradually changing to axial. This turbine also has a
wide range of operating heads with the open -type operating at heads as
low as 10 feet.
While it is possible to operate turbines at low heads, it must be real-
ized that there must be adequate flows to attain any usable amount of
power. A turbine operating Sunder a head of 100 feet and a flow of
15 cubic feet per second (ft /s) can produce about 100 kilowatts (kW)
while _f turbine operating under a head of 10 feet requires a flow of
150 ft /s to produce the same 100 kW of power. The power available at a
specific site is governed by the following equation:
P = Q h e
I1.8
where P is power in kilowatts, Q is flow in ft3Is, h is head in feet, e
is the efficiency of the unit expressed as a percentage, and 11.8 is a
factor to convert from foot-pounds to kilowatts of power. Doubling the
flow or the head will result in twice as much power while doubling both
flow and head results in four times as much power. The following table
indicates the power available at various values of Q and h. Efficiency
is assumed at 80 percent for all calculations.
Power (kW) - Rounded
11
300
41
102
203
508
1,017
2,034
6,012
E
100
14
34
68
170
339
678
2,034
A
50
7
17
34
85
170
339
1,017
D
10
1.4
3.4
7
17
34
68
203
(ft.)
2
5
10
Flow
25
(ft 3/s)
500
100
300
C]
As the table indicates, streams with low flows would not supply enough
energy to meet the needs of a village unless the head was quite high.
However, these streams could be developed to meet the needs of individ-
ual customers.
The question of utilizing the larger rivers in certain areas has also
been posed by persons familiar with the use of "fish wheels" which are
dependent on the energy in these rivers for their operation. Since
these "fish wheels" are powered by the velocity of the river, the use of
the equation V /2g can be used to show how much velocity is needeto
equal the power available from a given head. In this equation V is
equal to the velocity squared of the river and 2g is two times the
gravitational force or 64.4. If we want to find the velocity needed to
equal 50 feet of head we realize that we would need a velocity of over
55 feet per second or nearly 40 miles per hour. From this it can be
seen that the power utilized by the "fish wheels" is very small.
Another important item to consider is the length of the penstock re-
quired to obtain the necessary head. As pipe length increases there is
a corresponding increase in headloss due to frictioi between the Blowing
water and the pipe wall. Using the flows of 15 ft /s and 150 ft /s, as
mentioned above, and using a figure of 10 percent as the maximum allow-
able headloss, the followixyg occurs: (1) when the pipe length is
100 fee3t, a flow of 15 ft /s requires a 12-inch diameter pipe and
150 ft /s flow requires a 48-inch3 pipe; (2) when the pipe length is
increased to 1,000 feet, the 15 ft /s flow requires a 20-inch diameter
pipe and the 150 ft /s flow requires a 74-inch pipe. This shows that
increasing the pipe length can rapidly increase project costs to the
point of becoming economically unfeasible. A typical small hydro diver-
sion is shown on figure 2.
Sizing Generation Units
Normally the power demand and energy use are utilized to design the
correct size unit for a specific area. However, in the case of most
small hydro applications, the flows and/or head are not sufficient to
supply the entire power demand, but rather are used to replace part of
the generation furnished by conventional generation units. Using the
average flow of the stream will give the approximate power available
from the stream. However, if there are great fluctuations in the
streamflow, this would not be a dependable method of projecting avail-
able power.
Other factors also influence the amount of energy which will be used.
Since energy use does not equal the full output of a generator at all
times, a value called plant factor is derived. This is the average
energy use, during a given period, divided by the energy which would be
available if the plant was operating at full capacity during this entire
period. A value of 30 percent would be typical for a small hydro in-
stallation. Thus, a 100-kid plant operating at 30 percent plant factor
would generate:
(100 kW) x (8,760 hours/year) x (30%) = 262,800 kWh/year
E
Transm
to
UNITED STATES DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
Alaska Villaqe Electric Cooperative
hydropower Inventory
Typical Diversion
Figure 2
10
If there are certain periods when the streamflow is considerably higher
than the average flow, it may be feasible to provide storage or to size
the unit at a higher output to make use of these high flows which would
otherwise be lost in a run -of -stream plant. If storage is not provided,
it would be necessary for these higher flows to coincide with a period
when the energy use is high enough to warrant the additional capacity.
Since turbines and generators lose efficiency when operated below the
rated output of the units, it is sometimes advisable to install a second
smaller unit to use during periods of low energy demands.
Economic Analyses
There are many ways to look at the costs associated with constructing a
small hydro project. If the project is being built to displace diesel
generation, the maximum amount which should be spent for the project
would be based on the actual energy use and the cost of producing the
power by the present plant. In the case of the 100-kW plant above, the
annual energy is 262,800 kWh. If the cost of producing this energy is
50,/kWh, then the maximum allowable expenditure would be $13,140 per
year. Using an interest rate of 7 percent and a project life of
20 years, the maximum total expenditure would be:
$13,140 x 10.594 = $139,000
where 10.594 is the present worth factor.
However, this does not consider the fact that fossil fuel costs are
increasing at a rate greater than the inflation rate and would thus be
on the conservative side of the actual allowable cost for the project.
Another method would be to analyze the cost of producing the energy.
This is done by reducing the estimated project cost to an annual equiv-
alent and dividing this by the projected energy sales to arrive at a
cost per kWh. This can then be compared with costs of alternative
methods of electrical generation to determine the most economically
feasible method of generation. If the 100-kW unit above had a total
cost of $250,000, life of 20 years, and financed at an interest rate of
7 percent, the cost per kWh would be:
($250,000) x 0.09439)/262,800 kWh = $0.09/kWh
where "0.09439" is the capital recovery factor.
It should be realized when analyzing the cost per kWh that this is only
the energy production cost and would not include such items as distribu-
tion, operation and maintenance, and electric system management costs.
The analyses of some typical hydro sites are compared below. These are
based on a project life of 20 years, 7 percent interest on project
money, and 30 percent plant factor for all sites. A project life of
20 years and a plant factor of 30 percent are representative of a typi-
cal small hydro unit. The 7 percent interest was selected only as a
means of providing a comparison between other variables and does not
indicate the actual interest rate which may be applicable for a specific
project. These figures are rough estimates for comparison purposes
only.
COMPARISONS OF VARIOUS HYDRO SCHEMES
Alternative
Example Sites
Site 1
Site 2
Site 3
Site 4
Flow (ft3/s)
15
15
150
15
Head (ft)
100
100
10
100
Penstock (ft)
1,000
10,000
1,000
1,000
Power (kW)
95
95
90
95
Energy (kWh)
250,000
250,000
235,000
250,000
Transmission Line
(mi}7s) 1
1
1
10
Construction Cost
($)— 390,000
2,800,000
820,000
930,000
Annual Cost ($)
37,000
263,000
77,000
88,000
Cost per kWh ($)
0,15
1.05
0.33
0.35
These comparisons indicate that the most attractive site to develop
would be the low -flow, high head site located close to the demand,
Attempting to develop low head sites results in extremely high costs due
to the large hydraulic features required to handle the higher flows.
Also attempting to develop sites not close to the demand results in a
high project cost due to the associated long transmission line costs.
An additional factor to consider is whether the project has sufficient
flow during the winter months. If the flow is not adequate to meet
demands during low runoff periods, some type of storage may need to be
provided thus greatly increasing project costs. It is very important to
realize that unlike a diesel generation project, the cost of a hydro-
electric project is not affected most by the generating unit itself, but
rather by the civil works associated with the project. The generating
unit is only about 10 percent of the project cost while the civil works
are associated with the majority of the remaining costs,
Cold Weather Factors
One of the major problems of utilizing small hydro sites in .Alaska is
dealing with the effect that the extremely cold temperatures have on the
operation of the project. Not only does the cold weather affect the
operation by reducing or even eliminating streamflow at certain times,
it also poses icing problems for the operation of the plant. This is
not an insurmountable problem as there are various methods for avoiding
these problems through the use of arctic pipe (insulated pipe) for use
in penstocks, intake pipes located at sufficient water depth to avoid
freezing, and frequent monitoring of plant operation to avoid severe
problems
1/ Unit costs are shown in appendix A.
12
Another problem associated with streams having year—round flow is the
probability that the water is in a supercooled state, The U.S. Public
Health Service has experienced icing problems in some of their water
supply lines and overcame the problem by heating the pipe. This is one
method of overcoming icing problems; however, it should be realized that
there could be serious icing problems which would probably eliminate the
winter operation of some streams.
Summary
Because of the renewed interest in small hydroelectric projects the
number of manufacturers supplying these units has greatly increased and
a unit can be found to match nearly any combination of flow and head.
However, the unique conditions existing in Alaska, i.e., lack of winter
flows, supercooled streamflow, and icing problems, will usually deter—
mine whether a project is economically feasible or not. If some form of
storage has to be built to furnish winter flows, the high cost of con—
struction could increase the cost of energy to a point where the project
would not be economically feasible.
The use of the larger rivers in the region as an energy resource is
precluded due to the high cost of civil construction needed to make use
of the low head flows for the small energy demand of the villages.
Those sites having heads of 50 feet and above and located close to the
village would have the greatest chance of being feasible providing
adequate streamflow exists.
13
PART IV. STUDY METHODOLOGY
The study process consisted of (1) an office examination; (2) field
investigations; (3) refinement of costs following field investigations;
and (4) preparation of additional investigation costs and analyses
required. This screening process generally followed the procedures as
outlined below:
The U.S.G.S, maps of each village area were analyzed using the following
basic criteria:
a. Is the topography sufficiently steep near the villages to
develop the necessary head?
b. Is the drainage area of sufficient size to likely provide
sufficient water for feasible development?
C. Is a pipeline of no more than 10,000 feet required?
d. Is the site located within 20 miles from the village?
e. Would storage dam be required?
Hydropower projects in the 50-kW to 1,000-kW size range were the prime
sizes considered to match village needs. Neither household size pro-
jects nor mainstem river projects were analyzed: Small units that could
serve only a single household were not considered appropriate to meet
village utility use. Projects on main river systems were considered to
be too costly.
The pipeline and transmission line lengths are rough limitations. If
these lengths are exceeded, the cost of either feature approaches the
total allowable cost of a 100-kW feasible project when compared to
existing diesel costs.
Office studies located very few powersites where storage could be devel-
oped due to the rather flat terrain and topography featuring broad
valleys. Maps were examined closely and the few sites labeled for
further examination in the field: Storage dams in remote arctic areas
pose logistic and construction cost problems. The technical aspects of
dams in permafrost regions have been met in Alaska and several foreign
countries, but not without some special engineering and an attentative
maintenance program.
Potential water runoff from precipitation was estimated by measuring the
drainage area and multiplying by an average runoff per square mile. A
major problem associated with hydroelectric investigation in bush Alaska
is the lack of hydrologic records. For the initial project screening,
an average annual runoff of one-half cubic .foot per second per square
mile on a year-round basis was assumed based on Yukon River measured
averages.
14
Further checks were made to analyze project feasibility using energy
from summer flow only and using twice the estimated flow on a year-round
basis to calculate energy in case local conditions were significantly
different from the average.
Most of the streams that have been gaged are the larger streams such as
the Yukon and Noatak. Flow characteristics of small Arctic watersheds
of 5 to 20 square miles are not known, but most are suspected to freeze
up completely in the winter. Some of the streams are also suspected to
be fed by springs and have groundwater flows.
A brief check of U.S. Geologic Survey literature and personnel in Alaska
confirmed the lack of data on the Specific streams involved in this
study. However, the U.S.G.S. currently has a research program underway
in Arctic Alaska that involves spot measurements of summer and low
winter flows of some of the small watersheds involved in this study or
near the study area towns. The 'flow assumptions used in this study
agree with preliminary findings of the U.S.G.S, work.
Cost estimates were made to determine which villages had feasible sites
and which site near a village was best when there were more than one
site. Costs for the following major items were estimated in the initial
screening:
diversion dam powerplant
pipeline transmission line
Access roads were added in later estimates. Interest during construc-
tion was assumed to be for one year only and was not included for this
level of estimate.
Unit costs and background data sources are included in appendix A.
Power production estimates used the gross head measured from U.S.G.S.
maps and reduced for pipeline friction losses.
The economic analysis step assumed that the basic cost for energy would
be repaid from 4 months of operation during the summer when the power -
plant would run at an equivalent of 30 percent of full -speed capacity.
The 30-percent plant factor is based on AVEC historic data. Costs of
energy were also calculated assuming the water flow might be available
for 12 months of the year, and twice the estimated flow, for both
4 months and 12 months. This was assumed to account for any possiblil-
ity of overlooking a feasible project. For several cases, the cost of
the energy was also estimated assuming the features would cost only half
as much should conditions for construction turn out to be ideal. The
actual operating time will most likely fall somewhere between the 4 and
12 month operation.
The basic economic criteria for feasibility was the comparison of costs
for the hydro to the cost of replacing the fuel used for diesel genera-
tion. Allowable capital expenditures were calculated for the amount of
money that could be spent on a hydro per kilowatt to be equal to burning
15
diesel fuel and produce electricity at 174, 24C, and 50t per kilowatt-
hour. Financing was assumed for each one of these rates at 2 percent,
5 percent, and 9 percent,
The results are shown in appendix A.
Out of the 48 villages initially screened by APA, only 15 appeared to
have a reasonable chance for hydro development,
Field Investigation
Two engineers from Alaska Power Administration, Don Shira and Don
Gotschall, and one engineer from AVEC, Jerry Larsen, flew to the sites
to verify the office studies. The 15 sites were examined closely from
the air during the week of August 6, 1979. For those sites that looked
promising, ground examinations were made. Usually the engineers would
land and seek out a village mayor or an elder who was familiar with
streamflows in the area. In several cases, the engineers were taken to
the stream in a pickup or a boat to estimate the streamflow on the site.
Local people were interviewed to determine the streamflow characteris-
tics, such as what time of the year does the stream flood, how many
times larger is it during flood stage than when we looked at it, how low
does it get in the winter, and does it run in the winter under the ice
or does it even freeze over in the winter. From these interviews, rough
approximations were made of the annual streamflow and a better estimate
of the winter streamflow was obtained. After streams were examined on
the ground, they were again inspected from the air for correlation with
streamflows in other project areas. Through this process, nine of the
15 sites appeared to warrant further investigation.
Local residents were questioned about which streams contained fish and
further observations were made from the air. This resulted in reconsid-
ering a few streams as hydro potentials.
Refinement of Cost Estimates
After returning from the field observations, costs of the power poten-
tials were adjusted and recalculated. Road costs were added to provide
construction and operation access for the sites that need vehicle
access. Revised streamflows were incorporated into energy estimates.
The revised calculation sheets are included in appendix A.
Based on the field observations and revised costs, 9 of the 15 sites
appear to merit further investigation.
For these best nine sites, tables and graphs were made to estimate the
amount of fuel savings and approximate the periods of the year that
hydro would be available. The results are presented in appendix B.
The estimated fuel cost savings assume streamflows where field observa-
tions and hard data is not available. Monthly electric load distribu-
tions were from AVEC. Details and assumptions are presented in the
introduction to appendix B.
16
It should also be noted that the possibility
investigated during this phase of the study.
Atlas," published by the .Alaska Department of
sulted to ascertain the presence of fish in
Findings indicated no fish problems for those
the best potential sites.
Additional Investigations Needed
of fisheries impacts was
The "Alaska Fisheries
Fish and Game, was. con -
those streams studies.
streams associated with
Additional investigations categories were identified and costs estimated
for the nine sites meriting further study. The items that should be
studied in more detail include:
Streamflow characteristics
Surveying and mapping of the site
Soil and geologic examinations
Fish and wildlife
Project design and cost estimates
Proper scoping of these studies should provide all the basic information
to determine feasibility and prepare a Federal Energy Regulatory Commis-
sion minor power project license. Estimated cost for studying all nine
sites was $300,000.
A more complete description of the studies and the costs are presented
in appendix D.
17
PART V. INDIVIDUAL VILLAGE HYDROELECTRIC POTENTIAL
This part presents findings on the hydroelectric potential near each of
the 48 villages served by AVEC in 1978. Map studies were made of these
sites in the office. Ground and/or aerial inspections were carried out
on 41 sites, The other seven sites were not visited for the following
reasons: Because of the very flat terrain and the associated unlikely
hydroelectric potential around Emmonak and Alakanuk, their sites were
not visited, Old Harbor was visited earlier as part of APA's ongoing
hydropower studies on Kodiak Island; however, a report of Old Harbor's
hydro potential is included. Minto was not 'visited because of the low
precipitation in the area, flat terrain, and it was considerably off the
flight path. Gamble and Savoonga were not visited primarily because of
weather conditions in August 1978, and the necessity to charter a twin —
engine aircraft.
Sites not currently being served by AVEC which also received aerial
inspection for nearby hydropower potentials were Nondalton, Iliamna,
Newhalen, Deering, and Buckland.
Nine of the sites were confirmed by field examination to have good power
potential based on observed streamflows, and topography. For these
sites, maps have been prepared identifying potential project features,
preliminary power potential estimated based on available data and con—
struction costs estimated. The other six sites thought to have power
potential were found to have lower water flow or less head available
than anticipated in office studies. The results of these studies are
presented in similar detail to the sites having power potential.
The remainder of the sites inspected did not appear to have hydropower
potential. For these sites, pictures are presented to show the terrain
along with captions explaining some of the situations.
A couple areas may warrant further study. There are reports of a stream
on St, Lawrence Island which doesn't freeze over. Existing maps do not
show enough detail to confirm or deny a hydropower potential exists.
The area around Mountain Village, St, Mary's, and the lower Andreafsky
River may have an opportunity for development of a storage project.
Twice the area was aerial inspected with the conclusion that more
inspection and better hydrologic data would be needed to locate a spe—
cific site.
The description of the power potential for the best 'nine sites and Old
Harbor follow, The sites are:
Ambler Kiana
Elim Scammon Bay
Goodnews Bay Shungnak
Grayling Togiak
Kaltag
11
AMBLER
The power potentials in the Ambler area were examined by Alaska Power
Administration and AVEC engineers August 11, 1979. Office studies indi-
cated kade Creek might have a power potential, and this was confirmed
through aeria examination
The Jade Creek power potential, 9 miles northwest of town, could be
developed by diverting Jade Creek through a penstock 5,000 feet long to
develop a 200-foot drop and produce power amounting to roughly 600 to
1,200 kilowatts. The power potential depends on streamflow character-
istics which are not fully known at the present. The stream was esti-
mated to be flowing 100 cubic feet per second when observed August 11,
1979. Closer examination may reveal feasible storage sites in the
canyon which could firm up power during winter periods. There is also
potential use for using the firm energy supply as part of an Ambler-
Shungnak-Kobuk intertie.
During the aerial examination, a small wind generating machine (approxi-
mately 1.5 kW) was noticed 1/2 mile outside of town. Apparently, the
wind generator serves several residences. The wind data from the exist-
ing machine should be analyzed to determine if wind generation is a
feasible supplement to existing diesel.
19
�� >>
w
,yp : JADE MOUNTAINS ,
Diversion Dam
C'°e
UNITED STATES DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
Alaska Village Electric Cooperative
Hydropower Inventory
AMBLER
Pipeline
AMBLER RIVER (A-4 & A-5), ALASKA
Powerplant
36 31
13
24
e
7
Scale in miles
O 1 2 3
/ i \
i
Transmission Line
36 3] 32
1 d�
eru
04
20
AMBLER
HYDROELECTRIC DATA SHEET
VILLAGE LOCATION — 130 miles East of Kotzebue
STREAM — Jade Creek '(full potential developed)
DRAINAGE AREA — 7 sq. mi.-
POPULATION — 275
EXISTING GENERATION — Diesel
Installed Capacity —
420
Number of Units —
3
Peak Demand,1978 (kW).—
70
Energy Used,1978 (kWh) —
244000
Estimated Peak Demand,1979 (kW)
— 100
POTENTIAL HYDROELECTRIC PROJECT FEATURES
Flow
Head
Plant
Penstock
Penstock
Trans_
Output
(cfs)
(ft)
Factor(%)
Length(ft)
Dia.(in)
Line(mi)
(kW)
100
200
30
5000
48
10.0
1225
COST COMPARISONS UNDER VARIOUS PLANS
Flow
Power
Energy
Cost
Cost
Cost
Basic Assumption
(cfs)
(kW)
(kWh)
($)
($/kW)
($/kWh)
-------------------------------------------------------------
Year—Round Operation
100
1225
3219300
4519000
3700
15
Summer Operation
100
1225
1073100
4519000
3700
.46
Double Streamflow
Year —Round Operation
200
2475
6504300
6862000
2800
.12
Double Streamflow
Summer Operation
200
2475
2168100
6882000
2800
.35
,°
21
AMBLER
HYDROELECTRIC DATA SHEET
VILLAGE LOCATION — 130 miles East of Kotzebue
STREAM — Jade Creek
DRAINAGE AREA — 7 sq. mi.
POPULATION — 275
EXISTING GENERATION — Diesel
Installed Capacity — 420
Number of Units — 3
Peak Demand,1978 (kW) — 70
Energy Used.1978 (kWh) — 244000
Estimated Peak Demand,1979 (kW) — 100
POTENTIAL HYDROELECTRIC PROJECT FEATURES
Flow
Head
Plant
Penstock
Penstock
Trans.
Output
(cfs)
(ft)
Factor(%)
Length(ft)
Dia.(in)
Line(mi)
(kW)
--------------------------------------------------------------
30
200
30
5000
30
10.0
--
370
COST COMPARISONS UNDER VARIOUS PLANS
Flow
Power
Energy
Cost
Cost
Cost
Basic Assumption
(cfs)
(kW)
(kWh)
O
($/kW)
($/kWh)
Year —Round Operation
30
370
972360
2689000
7300
.30
Summer Operation
30
370
324120
2689000
7300
.91
➢ouble Streamflow
Year —Round Operation
60
740
1944720
3564000
4800
.20
Double Streamflow
Summer Operation
60
740
648240
3564000
4800
.60
22
Ambler on the bank of the Kobuk River with the Jade Mountains in the
background.
View of Ambler showing the confluence of the Kobuk River and Ambler
River. The Cosmos Mountain in the background is near Shungnak,
23
Jade Creek northwest of Ambler looking upstream, Note the potential dam
sites and the trail paralleling the stream.
Upper portion of Jade Creek drainage area where the river leaves the
Jade Mountains., The top of the mountains are obscured by the clouds,
24
A three -bladed wind generator serves residents just upstream on the
Ambler River north of Ambler.
25
ELIM
The hydropower potentials in the Elim area were examined by Alaska Power
Administration and AVEC engineers August 9, 1979. Office studies indi-
cated the best site would be Iron Creek, 4 miles east of town. However,
aerial examination and visits with local residents confirm Peterson
Creek near Mt. Kwiniuk has a better power potential.,
Two Elim residents with local knowledge were interviewed concerning
stream characteristics, year-round streamflow, and local conditions.
They were Hans Jamewouk, who is in charge of all AVEC construction in
the Nome area, and Andrew Daniels, president of the Elim Native Corpora-
tion, It was their opinion that Peterson Creek, 4 1/2 miles southwest
of town on the eastern side of Mt. Kwiniuk, would be the best power
potential in the area. The stream is steep, spring fed, and apparently
runs year round. From aerial inspection, it appears 200 to 250 feet of
head could be developed from an estimated flow of 10 cubic feet per
second for a power production of 125 kilowatts, A 5-mile transmission
line would be needed to deliver power to town as shown on the accompany-
ing map.
Data on other streams near Elim was obtained by visiting with the local
residents and by aerial inspection. The stream in town flows year round
and was measured at 10 cubic feet per second. There are no feasible
locations on this stream to develop head using either a storage dam or
diversions, Iron Creek, 4 miles east of town, was estimated flowing at
about 50 cubic feet per second. However, the stream is very flat and
appears that it would be difficult to develop for hydropower. Also,
salmon spawn in the mouth of the stream. Another stream 3 miles north-
east of Elim was estimated to flow one-fourth the volume of Iron Creek;
however, it had appreciably less flow. Because of its small drainage
area, this stream does not appear to be a hydro potential. Quiktalik
Creek, 1 1/2 miles southwest of Elim, flows all year round with roughly
two-thirds the flow of Iron Creek. However, from aerial observations
and the pictures, it appears it would be difficult to develop head in
the flat drainage basin. Walla Walla Creek, 8 miles southwest of town,
had salmon spawning in the mouth of the stream when it was examined. It
also has a flat stream gradient which would make developing head diffi-
cult.
Power requirements in Elim are increasing and there is a possibility
that the nearby town of Moses Point, 10 miles northeast of Elim, could
be tied in. A road is presently under construction to Moses Point, with
completion expected in roughly two years. Expected loads in the near
future for Elim include a new school, estimated to use 18 kilowatts, and
new homes, with an estimated requirement of 35 kilowatts. The 1979 to
1980 winter load is estimated by AVEC to be in the neighborhood of
114 kilowatts. The potential 125-kilowatt Peterson Creek hydro develop-
ment could supply a significant portion of this requirement.
26
v?+.- UNITED STATES DEPARTMENT OF ENERGY
-, ALASKA POWER ADMINISTRATION
Alaska Village Electric Cooperative
hydropower Inventory
y
tw w�is
�.usrt\
ELTJ
SOLOMON (C-1), ALASKA
Scale in miles
0 1 2 3
27
ELIM
HYDROELECTRIC DATA SHEET
VILLAGE LOCATION — 100 miles East of Nome
STREAM — Peterson Creek
DRAINAGE AREA — 2 sq. mi.
POPULATION — 290
EXISTING GENERATION — Diesel
Installed Capacity — 256
Number of Units — 3
Peak Demand,1978 (kW) — 61
Energy Used,1978 (kWh) — 217000
Estimated Peak Demand,1979 (kW) — 139
POTENTIAL HYDROELECTRIC PROJECT FEATURES
Flow
Head
Plant
Penstock
Penstock
Trans.
Output
(cfs)
(ft)
Factor(%)
Length(ft)
Dia.(in)
Line(mi)
(kW)
—10 --
200
--- 30 ------
3500
--- 20
4_5125
COST COMPARISONS UNDER VARIOUS PLANS
Flow
Power
Energy
Cost
Cost
Cost
Basic Assumption
(cfs)
(kW)
(kWh)
(>
($/kW)
($/kWh)
Year —Round Operation
10
125
328500
979000
7800
.33
Summer Operation
10
125
109500
979000
7600
.98
Double Streamflow
Year —Round Operation
20
245
643860
1300000
5300
.22
Double Streamflow
Summer Operation
20
245
214620
1300000
5300
.67
m
The town of Elim,
Quiktalik Creek, one and one-half miles southwest of Elim, flows all
year round but has no apparent steep gradient or dam sites., Mt. Kwiniuk
is in the background. Transmission route to Peterson Creek site would
be along the Norton Bay coast,
29
Peterson Creek, four miles southwest of town, is spring fed and emerges
above the 500-foot level at the base of Mt. Kwiniuk and flows all year
round, according to local people.
Close-up of Peterson Creek as showing the potential powerplant site at
the high tide mark on Norton Bay.
30
GOODNEWS BAY
The Goodnews Bay power potential was examined by the Alaska Power Admin—
istration and AVEC engineers August 6, 1979. Office studies indicated
the best sites were the two streams to the east and west of Explorer
Mountain and this was confirmed by the flight examination. It appears a
power potential of roughly 85 kW could be developed, as shown on the
enclosed map, at a point on the stream southwest of Chawekat Mountain.
The flow on August 6 was estimated at 15 cubic feet per second after
several days. of rain. Another nearby stream tributary to Sphinx Creek
west of Explorer Mountain appeared to have equal hydro potential to the
other stream. It has similar gradient, possibly steeper, and has
slightly more flow. An alternative plan of development that appeared
feasible from the air would be to divert the stream that flows on the
west side of Explorer Mountain to the one that flows along the east side
of Explorer Mountain. A low diversion dam and an open canal along the
350—foot contour, roughly 1,500 feet long, could double power produc—
tion. The west stream is in a broad valley at this point; therefore,
only a low diversion dam would be required. Secondly a canal would be
located on the flat part of the saddle between the two streams and steep
side hill cuts could be avoided. This plan would require further inves—
tigation on the ground, including a survey to locate features and the
extent and size of the features.
The cost comparisons on the data sheet indicate energy costs in a range
of $0.39 to $1.92 per kWh with the possibility of reducing costs if the
plan to use both streams is feasible.
Careful investigation and selection of a simple plan would be needed to
make the project feasible. Special attention will be needed to locate
the steepest part of the slope for the minimum pipeline length and to
minimize the length of the transmission line. Consideration should be
given to laying the cable on the ground instead of using power poles. A
precedence for this type of construction is the AVEC Stebbins to
St. Michael line.
A power potential of 85 kW is close to the power need of the village.
The 1978 peak load was 60 kW; AVEC estimates an additional 40 kW will be
required by 1980 with the addition of the new school and health
facilities.
31
4_
x
&-^-DIVERSION DAM
b
*�' —pipeline
1
Pawerplant-J
�
� ;- -
24
_ 3: �J3
Transmission
Line -
W
M11100".
a
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UNITED STATES DEPARTMENT OF ENERGY
a / .
ALASKA POWER ADMINISTRATION
•
- :- rz
Alaska Village Electric Cooperative
I
G:n,inea':
Hydropower Inventory
,.. -
GOODNBWS BAY
GOODNEWS (A-7). ALASKA
ti 111 ..A1
/. ser.,x 95e0t
Scale in miles
32
0 1 2 3
GOODNEWS DAY
HYDROELECTRIC DATA SHEET
VILLAGE LOCATION — 115 miles West of Dillingham
STREAM — Stream South of Chawekat Mountain
DRAINAGE AREA — 5 sq. mi.
POPULATION — 250
EXISTING GENERATION — Diesel
Installed Capacity — 150
Number of Units — 2
Peak Demand,1978 (kW) — 60
Energy Used,1978 (kWh) — 198000
Estimated Peak Demand,1979 (kW) — 60
POTENTIAL HYDROELECTRIC PROJECT FEATURES
Flow
Head
Plant
Penstock
Penstock
Trans.
Output
(cfs)
(ft)
Factor(%)
Length(ft)
Dia.(in)
Line(mi)
(kW)
14
100
30
3500
24
5.0
85
COST COMPARISONS UNDER VARIOUS PLANS
Flow
Power
Energy
Cost
Cost
Cost
Basic Assumption
(cfs)
(kW)
(kWh)
O
($/kW)
($/kWh)
— ---------------------------------------------------------------
Year—Round Operation
14
85
2233SO
1301000
15300
.64
Summer Operation
14
85
74460
1301000
15300
1.92
Double Streamflow
Year —Round Operation
28
175
459900
1632000
9300
.39
Double Streamflow
Summer Operation
28
175
153300
1632000
9300
1.16
V1
Goodnews Bay. Potential hydropower site is directly behind the town. Goodnews
River in foreground.
1/
The stream could be diverted in the upper valley to a powerplant at the base of
Chawekat Mountain shown in the upper right part of the picture.
34
Chawekat Mountain is the tall mountain on the right. The north fork of
Sphinx Creek drains the valley west of Explorer and Chawekat Mountains
and joins the meandering Sphinx Creek off the left of the photo. The
point where the north fork of Sphinx Creek could be diverted to the creek
near Chawekat Mountain is in the upper valley and is not clear in this
photo.
35
GRAYLING
By letter dated April 9, 1979, the Grayling Air Taxi Service contacted
the Corps of 'Engineers requesting inclusion of Grayling in the Corps'
small hydroelectric investigation program, Since Alaska Power Adminis—
tration had studies scheduled for the Grayling site as part of the AVEC
hydropower inventory, the Corps asked APA to look at the power potential
at Grayling as part of a cooperative activity,
The Grayling Creek streamflow was measured in the village near the
Public Health Service water supply intake on August 9, 1979 at 200 cubic
feet per second. Streamflow characteristics were discussed with
Mr, Henry Dawson, He indicated the stream usually flooded for a -week to
10 days following breakup in May, and flows bank full, which would be
roughly four times the flow measured in August. The lowest flow occurs
in September, The stream appeared to be slightly higher than normal due
to recent rains, Mr. Dawson indicated there were no salmon in the
stream; however, grayling do go upstream as far as possible,
Mr. Dawson also indicated that a coal deposit underlies the village
roughly 20 feet deep. He recalled a University of Alaska study was made
but didn't have an exact reference. The village also appears to have
good wind potential for electric generation.
From field examinations and maps, the north fork of the Grayling River
appears to have a better power potential than the stream forks west and
southwest of the village. The maps show the steepest part of the north
fork of Grayling Creek is approximately 3 miles upstream from the
village.
At this point, the valley narrows to an estimated 600 to 1,000 feet,
There is an existing road up to a gravel pit near the site. Because the
stream is located in a flat broad valley, considerable effort will be
needed to develop an economic feasible plan,
36
I
:
Diversion Dam—i,*, '
f _ Pipeline ^-
Powerplant _
a
- - Transmission Line Z� '
♦I
- W
c
w
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•i S
UNITED STATES DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
Alaska Villaqe Electric Cooperative
-'"--", Hydropower Inventory
GRAYLING
?✓"°"�?�HOLY CROSS (D--S) ALASKA
t
Scale in miles
2
37 0 1 3
GRAYLING
HYDROELECTRIC DATA SHEET
VILLAGE LOCATION — 160 miles North of Bethel
STREAM — Grayling Creek
DRAINAGE AREA — 15 sq. mi.
POPULATION — 180
EXISTING GENERATION — Diesel
Installed Capacity — 175
Number of Units — 3
Peak Demand,1978 (kW) — 56
Energy Used,1978 (kWh) — 223000
Estimated Peak Demand,1979 (kW) — 74
POTENTIAL HYDROELECTRIC PROJECT FEATURES
Flow
Head
Plant
Penstock
Penstock
Trans.
Output
(cfs)
(ft)
Factor(%)
Length(ft)
Dia.(in)
Line(mi)
(kW)
---------------------------------------------------------------
75
50
30
6000
60
2.5
230
COST COMPARISONS UNDER VARIOUS PLANS
Flow
Power
Energy
Cost
Cost
Cost
Basic Assumption
(cfs)
(kW)
(kWh)
( )
($/kW)
($/kWh)
Year —Round Operation
75
230
604440
3265000
14200
.59
Summer Operation
75
230
201480
3265000
14200
1.77
Double Streamflow
Year —Round Operation
150
460
1208880
4476000
9700
.41
Double Streamflow
Summer Operation
150
460
402960
4476000
9700
1.22
a
Grayling. Grayling Creek drainage area is in the left background.
Grayling Creek. The stream flow was measured at the straight reach at the end of
the street in August 1979 at 200 cfs.
39
Mr. Henry Dawson discussing streamflow with Don Shira (on other side of pickup).
Potential damsite is in the valley to the left.
Aerial view of potential damsite upstream and left of the gravel pit at the end
of the road.
40
Upper portion Grayling Creek drainage area.
Closeup of Grayling Creek meandering in the stream valley.
41
KALTAG
The Kaltag power potential was examined by Alaska Power Administration
and AVEC engineers August 9, 1979. Office studies indicated potential
powersites directly northeast and west of the village. From examining
the sites from the air, it appeared the best site is on the stream about
5 miles west of the village. The Rodo River, about 16 miles southwest
of town, may have potential, but it is farther from town and needs more
investigation to confirm an exact location.
The mayor of Kaltag, Mr. Franklin Madros, took the engineers in his
fishing boat to the mouth of the Kaltag River on the Yukon River. The
Kaltag River flow was measured upstream from the backwater influence of
the Yukon River. As can be seen in the photograph, the stream branched
into two parts at the mouth. The larger branch was flowing about
100 cubic feet per second and the smaller branch was flowing about
20 cubic feet per second.
Mr. Madros said that during the winter period, the flow dwindled to
roughly half the 120 cubic feet per second. During the spring floods,
the river flows bank full, roughly eight times the 120 cubic feet per
second, or about 1,000 cubic feet per second. The stream runs all year
as verified by the fact that people from Kaltag trap beaver all winter.
The tributary to the Kaltag River with the best power potential was
5 miles east of town. Flow was estimated from the air at about
25 cubic -foot -per -second. This appears to be reasonable when propor-
tioning the tributary drainage area to the total Kaltag River drainage
area. The tributary 5 miles west of town also appears to have several
dam and storage sites, many of which are 500 feet or less wide. Approx-
imately 100 feet of head could be developed at this tributary with
5,000-foot-long penstock to produce roughly 155 kilowatts.
The Kaltag River mainstem appears to be too wide and meandering to
develop head or provide a reasonable storage site. The tributary to the
Kaltag River, 3 1/2 miles west of town, appeared dry when observed. The
large tributary directly northwest of town is shown in the accompanying
photos as the meandering stream in a wide valley. Although the stream
had good flow, there doesn't appear to be any opportunity to develop
sufficient head drop in the wide flat valley.
The Rodo River, about 15 miles southwest of town, was estimated to have
a flow of 100 cubic feet per second. However, it also flows in a wide
meandering valley unsuitable for head development. See photo.
42
32 33 / 34 „33 1 r, � � 36 31 ( 82 �.
i I
! i
•� —� // _
A. '. 3 1, 12 { 7 A 3
It l
- EGRP 1Nltl-&tlSU;HI L�Uhtip RS...... .
1 1e 14 I 13 _ 18 1 17/ it
/
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70 ' 21 22 - 23 24 19 I 20 2:
79 7A 2p 3° 29 ( 21
Transmission Line
Diversion Dam-
4 i
32 �33 Z35�,36 32 1Pipeline 3
Powerplant
i ; I
,
1 i I
`a 9 UNITED STATES DEPARTMENT OF ENERGY
i
-- ALASKA POWER ADMINISTRATION
I '
j Alaska Village Electric Cooperative
alta9
Hydropower Inventory
17
16
i
KALTAG
..~20 21 .. .,. e- ,,., NULATO (B-(,). ALASKA
5xi�.
Scale in miles
43 0 1 2 3
KALTAG
HYDROELECTRIC DATA SHEET
VILLAGE LOCATION — 200 miles East of Nome
STREAM — Stream 4 mi. West of village
DRAINAGE AREA — 5 sq. mi.
POPULATION — 260
EXISTING GENERATION — Diesel
Installed Capacity —
155
Number of Units —
2
Peak Demand,1978 (kW) —
104
Energy Used,1978 (kWh) —
397000
Estimated Peak Demand,1979 (kW) —
107
POTENTIAL HYDROELECTRIC PROJECT FEATURES
Flow
Head
Plant
Penstock
Penstock
Trans.
Output
(cfs)
(ft)
Factor(%)
Length(ft)
Dia.(in)
Line(mi)
(kW)
25
-------------------------------------------------------------
100
30
5000
32
4.0
155
COST COMPARISONS UNDER VARIOUS PLANS
Flow
Power
Energy
Cost
Cost
Cost
Basic Assumption
(cfs)
(kW)
(kWh)
($)
($/kW)
($/kWh)
— ---------------------------------------------------------------
Year—Round Operation
25
155
407340
1798000
11600
.48
Summer Operation
25
155
135780
1798000
11600
1.45
Double Streamflow
Year —Round Operation
50
305
801540
2375000
7800
.32
Double Streamflow
Summer Operation
50
305
267180
2375000
7800
.97
44
The town of Kaltag. Looking downstream on the Yukon Rivera Grayling
River is in the foreground.
Kaltag River drainage area. The town of Kaltag is in the foreground
side of the island in the Yukon River.
45
AVEC Engineer Jerry Larsen beside the Kaltag River channel flowing
100 cubic feet per second.
The channel of the Kaltag River which is flowing 20 cubic feet
per second.
46
Rodo River looking up the Yukon River towards Kaltag, Note the stream
is flowing but the valley is very broad.
Street scene in Kaltag showing the satellite dish which supplies
telecommunications to the town.
47
The meandering tributary of the Kaltag River directly northeast of
town. This view is looking south, downstream on the Yukon River.
View looking upstream of the tributary of the Kaltag River directly
northeast of town. Note broad valleys.
M.
KIANA
The hydroelectric power potential near Kiana was examined by the Alaska
Power Administration and AVEC engineers August 11, 1979, Office studies
indicated the best sites were the Canyon Creek site, 8 miles northeast
of town, and the Portage Creek site, 7 miles south of town. Aerial
observations confirmed both sites appear to have potential, with the
Canyon Creek site being slightly larger and not having the additional
transmission line problem of crossing the Kobuk River,
Flow from Canyon Creek was estimated at 50 cubic feet per second in
August 1979. There appear to be several diversion sites on Canyon Creek
for developing 100 to 150 feet of head The first site would be located
at the mouth of the canyon; the alternative would be approximately
1 mile upstream from the mouth of the canyon. Farther upstream in
Canyon Creek, there appear to be several dam sites and flatter areas
which would make good reservoir sites. Closer examination of the Canyon
Creek profile will need to be made to locate an optimum power potential
considering the length of the transmission line, pipeline, and total
head that can be developed. When streamflow characteristics are col—
lected, a determination can be made as to whether or not storage will be
required to maintain winter power generation.
The Portage Creek site, 7 miles south of Kiana, has similar terrain with
a steep canyon flattening out in the upper part of the Hockley Hills.
The drainage area is slightly less than Canyon Creek, Dam sites in the
Portage Creek area may be easier to develop than the Canyon Creek site.
The Canyon Creek hydroelectric power potential was estimated at
430 kilowatts assuming 150—foot head and 50 cubic feet per second. The
Kiana 1979 peak was 149 kilowatts. Storage should be considered to
insure winter peak electric demands can be met,
49
J
f�
9
" -- Diversion Dam
Powerplant �.,♦ GI;, ,
Pipeline
i
I c
Transmission Line
4
UNITED STATES DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
Alaska Village Electric Cooperative
Hydropower Inventory
F/
A NA
KIANA
axc.�secrJ.lvs" SELAWIK (D-3). ALASKA
N6645--W 16000/15 %30
Scale in mites
MMM
50 0 1 2 3
KIANA
HYDROELECTRIC DATA SHEET
VILLAGE LOCATION — 60 miles East of Kotzebue
STREAM — Canyon Creek
DRAINAGE AREA — 10 sq. mi.
POPULATION — 330
EXISTING GENERATION — Diesel
Installed Capacity — 650
Number of Units — 3
Peak Demand,1978 (kW) — 149
Energy Used,1978 (kWh) — 624000
Estimated Peak Demand,1979 (kW) — 170
POTENTIAL_ HYDROELECTRIC PROJECT FEATURES
Flow Head Plant Penstock Penstock Trans. Output
(cfs) (ft) Factor(%) Length(ft) Dia.(in) Line(mi) (kW)
----------------------------------
50 150 30 6000 40 9.0 460
COST COMPARISONS UNDER VARIOUS PLANS
Flow
Power
Energy
Cost
Cost
Cost
Basic Assumption
(cfs)
(kW)
(kWh)
(3)
($/kW)
($/kWh)
Year —Round Operation
50
460
1208880
3066000
6700
.28
Summer Operation
50
460
402960
3066000
6700
.93
Double Streamflow
Year —Round Operation
100
930
2444040
4331000
4700
.19
Double Streamflow
Summer Operation
100
930
614680
4331000
4700
.52
51
KIANA (Reduced flow)
HYDROELECTRIC DATA SHEET
VILLAGE LOCATION — 60 miles East of Kotzebue
STREAM — Canyon Creek
DRAINAGE AREA — 10 sq. mi.
POPULATION — 330
EXISTING GENERATION — Diesel
Installed Capacity —
650
Number of Units —
3
Peak Demand,1978 (kW) —
149
Energy Used,197e (kWh) —
624000
Estimated Peak Demand,1979.(kW)
— 170
POTENTIAL HYDROELECTRIC PROJECT FEATURES
Flow
Head
Plant
Penstock
Penstock
Trans.
Output
(cfs)
(ft)
Factor(%)
Length(ft)
Dia.(in)
Line(mi)
(kW)
25
150
30
6000
32
9.0
235
COST COMPARISONS UNDER VARIOUS PLANS
Flow
Power
Energy
Cost
Cost
Cost
Basic Assumption
(cfs)
(kW)
(kWh)
($)
($/kW)
($/kWh)
------------------------------------------------
-------
Year—Round Operation
25
235
617580
2404000
10200
.43
Summer Operation
25
235
205860
2404000
10200
1.28
Double Streamflow
Year —Round Operation
50
460
1208880
3066000
6700
.28
Double Streamflow
Summer Operation
50
460
402960
3066000
6700
.83
52
The town of Kiana on the bank of the Kobuk River where the
Squirrel River intersects it.
Canyon Creek seven miles notheast of Kiana looking upstream. A
plan of development could involve diversion at the mouth of the
canyon or diversion and/or storage upstream in the canyon.
53
Canyon Creek at the mouth of the canyon estimated to be flowing
at 50 cubic feet per second.
s
Looking downstream at rock outcrops for potential dam near the
mouth of the canyon.
54
Canyon Creek in the upper reaches of the drainage area. Note
the flatter terrain more suitable for storage.
41
Portage Creek seven miles southeast of Kiana. Rock outcrop
form abutements for a potential dam site. There are several
narrow gorges similar to this in the lower reach of the canyon.
Portage Creek may have power potentials similar to Canyon Creek.
55
SCAMMON BAY
The Mayor of Scammon Bay, Homer Hunter, contacted the Corps of Engineers
in the spring of 1979 requesting inclusion of Scammon Bay in the Corps'
small hydroelectric investigation program. Since Alaska Power Adminis-
tration had studies scheduled for Scammon Bay as part of the AVEC hydro-
power inventory, the Corps asked APA to look at their power potential as
part of a cooperative activity.
The Scammon Bay power potential was examined by the Alaska Power Admin-
istration and AVEC engineers August 7, 1979. From correspondence and
interview with the Mayor, it was learned the spring that flows through
town runs the year round. Mr. Hunter indicated that lowest flows occur
in July and highest occur in the fall with the fall rains. It never
freezes, which was one of the reasons for originally selecting the
location of the village at this particular site. The map shows the top
of the saddle where the stream emerges is roughly 1,100 feet. This was
confirmed by flying over the site and checking it with the airplane's
altimeter. The stream emerges high on the slope and flows down a
rounded gully varying from 50 to 150 feet wide.
The stream was measured in town near the culvert site at 9 cubic feet
per second (see photo). From observations and village contacts, it
appears there are no fish in the stream above the very lowest part at
the far end of town. Fish do not travel up to the culvert.
The stream also serves the water supply system recently constructed by
the Public Health Service. The system has a submerged intake that feeds
a storage tank by gravity. From there a 4-inch-diameter plastic pipe
inside an insulated 12-inch-diameter corrugated metal pipe conveys the
water to a building, which is the central distribution point for the
town.
A new 6,500-square-foot high school was scheduled for construction in
the fall of 1979. The combined increased electric load from the new
water supply system and new high school was estimated by AVEC to in-
crease the 1979-80 peak demand to 89 kWh, from the early 1978 estimated
load of 54 kWh.
Two hydropower project plans were analyzed by APA. One would have a
300-foot head and the other a 500-foot head. The 300-foot head plan
would have 170 kW while the 500-foot head plan could develop 285 W.
Rough calculations indicated a 16-inch-diameter pipe would be required
in either case. This may allow for a staged project which could be
investigated later. Both projects result in approximately the same
power cost of roughly 8p per kWh assuming 50 percent plant factor.
The accompanying photographs show two possible locations for the power -
plant site. The upper site would be immediately above the water supply
intake. The lower site would be below the water supply intake just
above the culverts at the edge of town. Further design and plan analy-
sis should consider both locations. If the lower site is selected to
56
take advantage of the increased head, provisions need to be made so that
part of the water is allowed to flow past the power diversion for the
village water supply system intake.
Based on the initial calculations by Alaska Power Administration, this
site has the best potential of any of the AVEC villages and merits
further investigation. Investigation steps that should be undertaken
immediately would be establishment of a stream gage or staff gage to
better identify the streamflow characteristics. A survey profile and
cross-section of the streambed should be made to determine the size and
length of the pipeline required as well as the location of the possible
powerplant. A tabulation showing an estimated cost of investigations to
develop an economic and engineering feasibility report that would pro-
vide the basic data necessary for a Federal Energy Regulatory Commission
minor project license is included in the appendix.
57
Powerplant 1•
' mod►, Yi pe ne: lif
' Diversion Dana / .. - - .. •.
J _
tv A
� � i 'ram sau'•w'' '
�J UNITED STATES DEPARTMENT OF ENERGY
AIASKA POWER ADMINISTRATION
Alaska Villaqe Electric Cooperative
TTydropower Inventory
SCANMON BAY
AU K
�j l ';°t • . // -,,,, HOOPER BAY (DN.,
ALA3KA
t�,//// � / a \ A•:`. // a n., 14 5—n16 5 rJ 5, 1225
1952
Scale in miles
0 t 2 3
SCAMMON BAY
HYDROELECTRIC DATA SHEET
VILLAGE LOCATION — 140 miles Northwest of Bethel
STREAM — Spring —fed stream S. of village
DRAINAGE AREA — 2 sq. mi.
POPULATION — 193
EXISTING GENERATION — Diesel
Installed Capacity — 150
Number of Units — 3
Peak Demand,1978 (kW) — 78
Energy Used,1978 (kWh) — 214500
Estimated Peak Demand,1979 (kW) — 89
POTENTIAL HYDROELECTRIC PROJECT FEATURES
Flow
Head
Plant
Penstock
Penstock
Trans.
Output
(cfs)
(ft)
Factor(%)
Length(ft)
Dia.(in)
Line(mi)
(kW)
------------------------------------------------------------
9
300
50
2300
16
.4
170
COST OF POTENTIAL PROJECT
Flow
Power
Energy
Cost
Cost
Cost
Basic Assumption
(cfs)
(kW)
(kWh)
($)
($/kW)
($/kWh)
----------------------------------------------------------------------
Year—Round Operation
9
170
744600
544000
3200
.OS
59
SCAMMON BAY
HYDROELECTRIC DATA SHEET
VILLAGE LOCATION — 140 Northwest
STREAM — Spring —fed stream S. of
DRAINAGE AREA — 2 sq. mi.
POPULATION — 193
EXISTING GENERATION — Diesel
Installed Capacity —
Number of Units —
Peak Demand,1978 (kW) —
Energy •Used, 1978 (kWh)
-
of Bethel
village
Estimated Peak Demand,1979 (kW) —
150
3
78
214500
69
POTENTIAL HYDROELECTRIC PROJECT FEATURES
Flow
Head
Plant
Penstock
Penstock
Trans.
Output
(cfs)
(ft)
Factor(%)
Length(ft)
Dia.(in)
Line(mi)
(kW)
9
500
50
4200
16
4
285
COST OF POTENTIAL PROJECT
Flow
Power
Energy
Cost
Cost
Cost
Basic Assumption
(cfs)
(kW)
(kWh)
($)
($/kW)
($/kWh)
`fear —Round Operation
9
285
1248300
928000
3300
.08
Village of. Scammon Day
Potential diversion point for
A spring supplied
stream flows through
Scammon Ray year round.
The Public Health Service
constructed water supply
line zigzags up the hill
to the water storage tank
61
io
Afti
�{� Iy�,, �•...� � 1.f�t. iir fl•. . �t.y. ` '.�' .. % �." . �� �� T �G'r. it •-.�y�.J,Y.�
X. •..SCJIM.,r r F""�'�. '.', _ yl... • L � . ti `i - ...G'
lot
r.
le /
.� .. �• . r ram, " - � .i
10
IF
Public Health Service constructed 4 inch diameter water supply line foam
insulated inside a 12 inch diameter corrugated metal pipe.
The water supply intake
is submerged in the stream
bed. A powerplant site could
be just upstream from the
submerged intake.
63
400
�:'"����''`.•.. ':--`�'-��"' •. �"fir
The power potential in the Shungnak area was examined by the Alaska
Power Administration and AVEC engineers August 11, 1979. Office studies
had suggested a power potential might exist on Cosmos Creek and this was
confirmed through aerial examination. The potential powersite is rough-
ly 7 miles north of Shungnak. It appears 150 to 200 feet of head could
be developed. The estimated flow of 100 cubic feet per second with
200 feet of head could produce about 1,235 kilowatts of power. Stream -
flow characteristics need to be established to confirm how many months
of the year this power potential would be available. During the flight
there were several other streams that appeared to have potential in the
canyon and foothills of the Cosmos Mountains. One of these, Camp Creek,
appeared to have, good power potential and should be investigated fur-
ther. There is an existing road serving the mines in the area. Cosmos
Creek is accessible by this road from Kobuk or the mining camp just
north of Kobuk.
The field examination identified the possibility of an electrical inter -
tie between Shungnak, Kobuk, and Ambler. Currently, Kobuk and Shungnak
are to be interconnected by a single -wire ground return transmission
line, on a demonstration basis. The design and construction of this
line is being sponsored by the State Division of Energy and Power Devel-
opment. A possible interconnection with the mine and Ambler needs to be
investigated to determine the viability of a small regional electrical
intertie system. Any economical excess energy from Ambler could pos-
sibly be marketed on the intertie system. Very little data on elec-
trical needs of the mine is available at the current time.
Another power potential looked at in the Kobuk-Ambler-Shungnak area was
the Kogoluktuk River. The river is fairly large by arctic standards and
was flowing several hundred cubic feet per second in August. About
7 miles northeast of Kobuk, the river goes through a narrow canyon in a
much wider old river valley. The canyon appears to be 50 to 100 feet
deep from visual examination and from U.S. Geological Survey map quad-
rangle sheet Shungnak D-2. Additional head might be obtained by using a
diversion and long conduit to take advantage of the falls downstream.
The firm potential of the Kogoluktuk River was estimated at 4,200 kilo-
watts by Alaska Power Administration during the 1966 statewide inventory
of hydropower sites. The powerplant would have an installed capacity of
8,400 kilowatts. A concrete arch dam 205 feet high with a crest length
of 800 feet was considered necessary to provide 100 percent streamflow
regulation. This power potential is considered too large for the pres-
ent need of the small towns and mine, but could be a long range
possibility.
65
PowerPlanC
TrausFds. ion I.i.nc.
y C li'
Ci
'"- - • f ._; - - UNITED STATES DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
z• j Alaska Villaqe Electric Cooperative
Hydropower Inventory
24 19 CSHUNi GNAK
1 I
aixce ioemm SHUNGNAK (D-3). ALASKA
hMvtS-W15rroQ; i5Y30
IyyI ScaleIR tildes
66 0 1 2 3
5HUNGNAK
HYDROELECTRIC DATA SHEET
VILLAGE LOCATION — 150 miles East of Kotzebue
STREAM — Cosmos Creek
DRAINAGE AREA — 25 sq. mi.
POPULATION — 198
EXISTING GENERATION — Diesel
Installed Capacity — 805
Number of Units — 5
Peak Demand,1978 (kW) — 96
Energy Used,1978 (kWh) — 371000
Estimated Peak Demand,1979 (kW) — 96
POTENTIAL HYDROELECTRIC PROJECT FEATURES
Flow
Head
Plant
Penstock
Penstock
Trans.
Output
(c:fs)
(ft)
Factor(%)
Length(ft)
Dia.(in)
Line(mi)
(kW)
100
200
30
7000
52
9.0
1235
COST COMPARISONS UNDER VARIOUS
PLANS
Flow
Power
Energy
Cost
Cost
Cost
Basic Assumption
(cfs)
(kW)
(kWh)
($)
(3/kW)
($/kWh)
-------------------------------------------------------------
Year —Round Operation
100
1235
3245560
5058000
4100
—
.17
Summer Operation
100
1235
1081860
5058000
4100
.51
Double Streamflow
Year —Round Operation
200
2470
6491160
7669000
3100
.13
Double Streamflow
Summer Operation
200
2470
2163720
7669000
3100
.39
67
The town of Shungnak looking north. Cosmos Creek is off the photo to
the left of the mountain, obscured by the clouds. There is a road at
the base of the mountain that crosses Cosmos Creek to the left. The
transmission line route would be across the flat terrain behind town.
Typical view of the canyon and valley of Cosmos Creek.
M.-
Kogoluktuk River looking upstream, 13 miles northeast of Shungnak. The
river comes through a narrow canyon and flows over a series of low
falls.
Kogoluktuk River looking downstream at the falls below the canyon.
69
TOGIAK
The Togiak power potential was examined by Alaska Power Administration
and AVEC engineers August 6, 1979, Office studies concentrated on two
small streams 2 1/2 miles west and northwest of town thought to have
power potential. Field examination proved the drainage areas and flows
were too small to make them a significant power potential
The aerial examination identified another stream, the Kurtluk River,
4 miles west of town, as the best power potential in the area. It was
flowing 10 cubic feet per second. The lower 2-mile reach of the stream
flows through rock cuts and has a series of low waterfalls which are not
evident from the map. Power estimates, based on 10 cubic feet per
second and 50-foot drop, are 30 kW, The 30 kW would meet only a small
part of the 1978 demand for Togiak, which was 216 W. The estimated
cost of this development would range between $0,85 and $4.26 per kWh.
Any further investigations should initially examine the winter flow rate
of Kurtluk River and survey the lower 2 miles of the river to locate the
steepest portion and the minimum length pipeline. Serious effort should
be made to locate a drop higher than 50 feet for a pipeline length less
than the 3,500 feet used in these calculations. There may be an oppor-
tunity to reduce the cost to one-third of the estimate if a year-round
continuous operation powerplant could be developed to meet a greater
portion of Togiak's needs,
Further investigation should also include examination of streams south-
west of Togiak within a range of about 10 miles to determine if they
have better power potential than the Kurtluk River, Rain and fog ham-
pered observations of that area during the August 1979 trip,
70
I i
I
j
14 � 1=
i
. I
I
I
I
I ,tiT -:ice
V
Q .
i
i
''� • ;?f. Tugiak
Transmission Line 13 ,
„ 1:: 1 _,
Diversion Dam '
1x�UNITED STATES DEPARTMENT OF ENERGY
�-Pipeline ALASKA POWER ADMINISTRATION
..1111LL��" Alaska Village Electric Cooperative
Hydropower Inventory
Powerplant
TOGIAK
T 0 GOODNEWS (A-4), ALASKA
Scale in miles
71 O 1 2 3
TOGIAK
HYDROELECTRIC DATA SHEET
VILLAGE LOCATION — 70 miles West of Dillingham
STREAM — Kurtluk River
DRAINAGE AREA — 20 sq. mi.
POPULATION — 450
EXISTING GENERATION — Diesel
Installed Capacity —
550
Number of Units —
3
Peak Demand,1978 (kW) —
216
Energy Used,1978 (kWh) —
640000
Estimated Peak Demand,1979 (kW)
— 226
POTENTIAL HYDROELECTRIC PROJECT FEATURES
Flow Head Plant Penstock Penstock Trans. Output
(cfs) (ft) Factor(%) Length(ft) Dia.(in) Line(mi) (kW)
------------------------------------------------------------------
10 50 30 3500 26 4.0 30
COST COMPARISONS UNDER VARIOUS PLANS
Flow
Power
Energy
Cost
Cost
Cost
Basic Assumption
----------------------------------------------------------------------
(cfs)
(kW)
(kWh)
O
($/kW)
($/kWh)
----------------------------------------------------------------------
Year—Round Operation
10
30
76840
1031000
34400
1.42
Summer Operation
10
30
262SO
1031000
34400
4.26
Double Streamflow
Year —Round Operation
20
60
1576BO
1229000
20500
.85
Double Streamflow
Summer Operation
20
60
52560
1229000
20500
2.55
72
Town of Togiak on Togiak Bay.
Hills west of Togiak. Note small drainage basin in the hills and the flat terrain.
A better hydropower potential is behind the first row of hills.
73
OLD HARBOR
The Alaska Power Administration initiated investigations of the hydro-
power potential in the vicinity of Old Harbor in May 1978. The first
plan (plan 1) evaluated is not considered to be feasible at this time.
A second plan (plan 2) is currently under investigation with results of
preliminary office studies due in the early spring of 1980. If war-
ranted, a feasibility analysis based on field investigation could be
completed in early 1981. Both plans are described in the following
discussion,
Potential Site 1
The identified powersite is about 3 miles northwest of the village and
would divert water at an elevation of 500 feet attaining a head of about
340 feet, The maximum average monthly flow in the stream occurs in June
and was estimated at about 14 cubic feet per second (without field
data). This would produce about 1,150 kilowatts if fully utilized.
Total energy potential of about 4 million kilowatthours was estimated
for the site. Since the energy demand at Old Harbor is only 2 million
kilowatthours per year, an alternate plan utilizing only half the
streamflow was also investigated. Runoff distribution was correlated
with 1976 streamflow records for the nearby Upper Thumb River.
Cost estimates were based on structures including a small earthfill
diversion dam, buried pipe for a transbasin diversion across a ridge,
penstock, powerplant, transmission line, and switchyard. The pipe
excavation through the ridge top was estimated to be as much as 50 feet
deep and 700 feet long.
Buried light -weight 36-inch-diameter pipe would extend about 1,200 feet
from the diversion dam along the hillside and through the ridge top cut
to the penstock headworks. The 30-inch, 4,000-foot-long penstock would
descend along a sloping sidehill to the powerplant. About 9,700 feet of
transmission line would extend from the powerplant to the village.
A 600-kilowatt powerplant could produce an estimated 1.8 million kilo-
watts of usable energy annually, or 90 percent of the assumed demand.
In late 1978, topographic surveys were performed by a private surveyor.
Also, the U.S.G.S. began obtaining periodic streamflow measurements,
which continued through 1979.
Specific estimates have not been reworked based on field data pending
reduction of stream gage data. However, in general, a larger diversion
dam and deeper ridge top excavation would be required than originally
estimated, which would substantially increase costs. Preliminary
streamflows appear to be greater than estimated. Because of the expen-
sive features required for development of this site, it is not con-
sidered feasible at the present time.
74
Villages Studied - No Economical Hydro Potential
These six sites were part of those believed to have some hydro potential
following the initial office screening. However, these sites were
eliminated from the list of potential sites following the field investi-
gations for various reasons. These reasons are discussed in the follow-
ing pages on the individual sites:
The sites are:
Kalskag/Lower Kalskag
Mekoryuk
New Stuyahok
Tanunak
Toksook Bay
Wales
77
KALSKAG/LOWER KALSKAG
From the office studies, the hills behind Kalskag appeared steep enough
to merit a field examination. Since Lower Kalskag is 2 miles downstream
from Kalskag, both villages are discussed together. The small streams
shown immediately northwest of Kalskag appeared dry upon inspection in
August 1979. The stream shown on the enclosed map as a power potential
had water standing in some places but did not appear to be flowing.
Several other tributaries in the hills around Kalskag were examined and
most had very low flow or no flow. As shown in the accompanying pic-
tures, the typical stream valleys are very broad, which would require
large dams to provide storage and make the projects infeasible.
The conclusions are that even though there are hills near Kalskag, the
streamflows are too low to adequately supply a feasible power project.
i
= UNITED STAIES DEPARTMENT OF ENERGY
i
ALASKA POWER ADMINISTRATION
Alaska Village Electric Cooperative
I
Hydropower Inventory
.. KALSKAG AND LOWER KALSKAG
u-
( RUSSIAN MISSION (C-4a ALASKA
N619U-*1 bwrS/ bXzi
o Scale in miles
g a y z s
,
E.
a
7:
Y .s.
Fowerplant
Transmission Line
�4.
1
v ,a,
79
LOWER KALSKAG
HYDROELECTRIC DATA SHEET
VILLAGE LOCATION — 70 miles Northeast of Bethel
STREAM — Stream 2 mi. north of village
DRAINAGE AREA — 3 sq. mi.
POPULATION — 220
EXISTING GENERATION — Diesel
Installed Capacity —
335
Number of Units —
3
Peak Demand,1978 (kW) —
96
Energy Used,1978 (kWh) —
366000
Estimated Peak Demand,1979 (kW)
— 132
POTENTIAL HYDROELECTRIC PROJECT FEATURES
Flow Head Plant Penstock Penstock Trans. Output
(cfs) (ft) Factor(%) Length(ft) Dia.(in) Line(mi) (kW)
2 10 03 9000 14 3. 5 15
COST COMPARISONS UNDER VARIOUS PLANS
Flow
Power
Energy
Cost
Cost
Cost
Basic Assumption
(cfs)
(kW)
(kWh)
{)
($/kW)
($/kWh)
Year —Round Operation
2
15
39420
1218000
31200
3.37
Summer Operation
2
15
13140
1219000
81200
10.12
Double Streamflow
Year —Round Operation
4
25
65700
1471000
58800
2.45
Double Streamflow
Summer Operation
4
25
21900
1471000
58800
7.35
Kalskag on the bank of the Kuskokwim River 2 miles upstream from Lower
Kalskag, (No pictures of Lower Kalskag,)
91
This stream 3 miles northeast of Kalskag assumed to have power potential
was found to have water standing in some spots, but not flowing. The
broad valley typical of streams in this area would require large, ex—
pensive dams to develop storage,
EN
MEKORYUK
Office studies indicated hydropower potentials might exist on three
streams in the Mekoryuk area. The site was visited August 7, 1979 and
the streams were found to be either too flat or flows too small to
support a feasible hydropower development.
The most promising stream observed was the stream southeast of Mekoryuk,
which flows past the Daprakmiut summer camp. A possible plan of devel-
opment is shown on the attached map. Because of the 8,000-foot-long
pipeline required to develop head, the cost of the project would be too
high to develop a feasible hydroelectric project. The enclosed summary
sheet indicates that the cost would be between $1 and $4.80 per kilo-
watthour.
The stream west of the Ingrijoak Hills was found to have a flow of only
1 to 2 cubic feet per second, and even though it has elevations in the
drainage area where up to 100 feet of head could be developed, the power
potential is too small and would be too costly to be feasible.
The flat stream gradient of the Mekoryuk drainage area was found to be
so flat that 2 miles or more of pipeline would be required to develop
100 feet of head. It does not appear to be a feasible hydroelectric
potential.
The most likely possible site for a dam that could provide stream regu-
lation and storage is on the same stream as the preferred project,
roughly 2 miles upstream from Daprakmiut. A 75-foot-high dam built
between the 25-foot and 100-foot contour levels would be 1,000 feet wide
at the crest, according to the accompanying map. A dam at this location
would require roughly 600,000 cubic yards of fill plus excavation for a
spillway. The site is shown on the accompanying photos. Preliminary
estimates of the cost of the dam would be roughly twice the cost of the
diversion project. The dam plan would develop less head than the diver-
sion plan and have less power production even with storage.
An additional problem indicated by the Alaska Fisheries Atlas, volume 1,
published by the State of Alaska, Department of Fish and Game, indicates
that there are chum and pink salmon using the stream which would affect
the storage scheme.
The conclusions are that the power potentials in the Mekoryuk area are
not economically feasible.
9W
UNITED STATES DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
Alaska Villaqe Electric Cooperative
i
Hydropower Inventory
MEKORYUK
NUNIVAK ISLAND (B-4), ALASKA
4 p • �.' / t16015—WI66n75/15X225
z ° 0
c •° - / Scale in miles
3
ro
L /r,
1
S t
Transmission Line
� t
3 L" A
'POTENTIAL DAM SITE
Powerplant
' .7 vim / I - I F ..-` '•�\
Id'O' PipelineIt
Divers ion Dam
MEKORYUK
HYDROELECTRIC. DATA SHEET
VILLAGE LOCATION'— 150 miles West of Bethel
STREAM — Stream through Daprakmiut
DRAINAGE AREA — 50 sq. mi.
POPULATION — 165
EXISTING GENERATION — Diesel
Installed Capacity — 275
Number of Units — 3
Peak Demand,197S (kW) — 80
Energy Used,197S (kWh) — 278000
Estimated Peak Demand,1979 (kW) — SO
POTENTIAL HYDROELECTRIC PROJECT FEATURES
Flow Head Plant Penstock Penstock Trans. Output
(cfs) (ft) Factor(%) Length(ft) Dia.(in) Line(mi) (kW)
10 100 30 5000 26 S.O 65
COST COMPARISONS UNDER VARIOUS PLANS
Flow
Power
Energy
Cost
Cost
Cost
Basic Assumption
(cfs)
(kW)
(kWh)
($)
(,I/kW)
($/kWh)
— --------------------------------------------------------
Year—Round Operation
10
65
170820
2502000
38600
1.61
Summer Operation
10
65
56940
2508000
38600
4.33
Double Streamflow
Year —Round Operation
20
125
328500
3070000
24600
1.02
Double Streamflow
Summer Operation
20
125
109500
3070000
24600
3.07
m
--- Diversion DamJ
�., r
•,,? `.-E Fipaline
P owerplant,
riansmission Line
JJ
It
I
tit ii C �/ t fa : ' • I � � ��Ci�J 'V' .I ,
%t UNITED STATES DEPARTMENT OF ENERGY
J ALASKA POWER ADMINISTRATION
• Alaska village Electric Cooperative
_g Hydropower inventory
NEW STUYAHOK
33 7 1
- am•+KA•;uunnrs DILLING1(B--4). ALAS1\A
mmu5 -nis7e,.s ..,
Scale in miles
90 0 1 2 3
Spring outcropping high on the hill, southeast of the Ugchirnak
Mountain, It appears to run underground part of the way down the hill,
97
Lower reach of the spring looking toward Tanunak.
M.
The small spring stream is in the foreground. Musk oxen are grazing on
the hillside.
m
TOKSOOK BAY
Office studies indicated the area near Toksook Bay and Tanunak was worth
field examination to verify suspected power potentials in the area. The
towns are only 6 miles apart and the whale area was examined for hydro
potentials that might serve either or both towns.
Flight examinations confirmed the Alakuchak River, east of Toksook Bay,
was very flat as indicated by the maps and did not have potential for
developing head for hydropower, The Tanunak River that runs into the
Bay at the town of Tanunak also proved to be too flat to develop
hydropower.
The most likely potential appeared to be the hills north of Toksook Bay
and east of Tanunak Bay, Aerial examination indicates there is a spring
flowing out of the southeast side of Ugchirnak Mountain at roughly the
750—foot elevation. The stream appeared to go underground and re—emerge
further on down the slope. Flow was estimated at 2 cubic feet per
second. The accompanying cost estimate and power evaluations indicated
that the power would cost $0.64 to $1.91 per kilowatthour, depending
upon whether the flow was available year round or only in the summers:
Based on this data, there does not appear to be any feasible power
potentials within reasonable transmission distance to the Toksook Bay
and Tanunak village areas.
100
UNITED STATES DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
Alaska Villaqe Electric Cooperative
FIydropoo:er Inventory
} ,
TO&SOOK BAY
I NUNIVAK fSLAND (C-I), ALASKA
N"ICA0 'N16'(0115x235
Scale in miles
0 1 2 3
}r,
J �-
i Diversion Dam
I
I
Pipeline
i_
Powerplant
i
1
k�
` r • .31 .A
el
I /
Pransmission Line
KANGIRLVAR
i .LL♦
BAY
a
f.
Jr
WALES
Office studies indicated the power potential outlined on the accompany-
ing map near Wales was worth examining further in the field: Alaska
Power Administration and Alaska Village Electric Cooperative engineers
examined the site August 10, 1979, and found that streamflow estimates
had been entirely overestimated in the office. The stream shown on the
map for potential was flowing barely enough to wet the streambed and
would likely be frozen most of the year. In any case, the streamflow
quantities appear to be too low to make the stream a significant hydro-
power potential,
The AVEC powerplant operator, Rolland Alexander, showed us the spring
behind town that has been the traditional water supply for Wales:
Although the spring flows year round down a rather steep hillside, it
was measured in August 1979 to be approximately 9 inches wide and
2 1/2 inches deep. Again, this is an adequate PHS supplemental water
supply but hardly a hydro potential that could serve the town.
Conclusions are that there are no feasible hydropower potentials near
Wales. If further studies are to be carried out, the power potential
near Tin City and Lost River should be examined. A literature search of
the power potentials envisioned for the town of Lost River may have
application for the village of Wales and possibly the mining community
at Tin City.
104
L
%. •,, irYd w7
i
A a
i
Powerplant
Transmission Line
{ - rirel;ne
Diversion Dam ,
9 /
Cape P,1' a of W3tes'
I
Cava Moon 1C�trt
x c �
UNITED STATES DEPARTMENT OF ENERGY
` AL.ASKA POWER ADMINISTRATION
Alaska Village Electric Cooperative
uydropower Inventory
ausKa WALES
TELLER (C 7), ALASKA
N6530—WIC9/I1(•5x30
Scale in miles
0 105 1 2
WALES
HYDROELECTRIC DATA SHEET
VILLAGE LOCATION — 110 miles Northwest of Nome
STREAM — Village Creek
DRAINAGE AREA — 4 sq. mi.
POPULATION — 130
EXISTING GENERATION — Diesel
Installed Capacity — 245
Number of Units — 3
Peak Demand,1978 (kW) — 42
Energy Used,1978 (kWh) — 142000
Estimated Peak Demand,1979 (kW) — 52
POTENTIAL HYDROELECTRIC PROJECT FEATURES
Flow Head Plant Penstock Penstock Trans. Output
(cfs) (ft) Factor(%) Length(ft) Dia.(in) Line(mi) (kW)
----------- ----- -------------------
2 200 30 4000 10 1.0 25
COST COMPARISONS UNDER VARIOUS PLANS
Flow
Power
Energy
Cost
Cost
Cost
Basic Assumption
(cfs)
(kW)
(kWh)
($)
($/kW)
($/kWh)
Year —Round Operation
2
25
65700
448000
17900
.75
Summer Operation
2
25
21900
448000
17900
2.24
Double Streamflow
Year —Round Operation
4
50
131400
600000
12000
.50
Double Streamflow
Summer Operation
4
50
43800
600000
12000
1.51
106
The town of Wales at the base of Cape Mountain,
W
The northern end of Cape Mountain, showing the airport and new road to
the Public Health Service water supply in the foreground. The village
of Wales is off the road to the right,
107
Looking upstream, Village Creek, one mile north of Wales. The flow,
even after recent rains in August 1979, barely covered the rocks in the
streambed,
Tin City mining complex, 5 miles southeast of Wales,
�IM
Sizable stream near Lost River, 30 miles southeast of Wales, which may
have power potential but would require a long transmission line.
109
Villages without Hydropower Potential
Map examination of many of the AVEC sites showed early that there were
no hydroelectric potentials within 10 to 20 miles, and most times much
farther. The sites, general terrain, and water supply situations are
discussed separately by area in this part of the report.
The sites are grouped by areas:
Yukon—Kuskokwim Delta areas
Lower Yukon River area
Norton Sound area
Kotzebue Sound area
Sites not examined,
110
Yukon—Kuskokwim Delta Area
Both of the necessary conditions of head and continuous water supply for
a successful hydroelectric project are missing in the Yukon—Kuskokwim
Delta area. The whole area is characterized by large areas of flat
lands marked with lakes and marshes in patterns which are remnants of
old stream channels, ocean beaches, or permafrost action. There are no
high hills with waterfalls. The area doesn't have canyons and valleys
to form dam and reservoir sites Much of the water flowing through the
area is in the mainstem of the large rivers, which are too large to
control for village use,
Pictures of individual villages that follow show the village and the
surrounding terrain, which doesn't appear to have hydroelectric poten—
tial. All the sites were examined on the latest U.S. Geological Survey
maps and visited to verify there were no hills or other surprises that
didn't show up on the map.
The villages in this area are:
Alakanuk (no picture) Hooper Bay
Eek Kasigluk
Emmonak (no picture) Nunapitchuk
Chevak Quinhagak
ill
Eek near the mouth of the Eek River on Kuskokwim Bay, 40 miles south of
Bethel. As the picture shows, there are no hills or other terrain
features within many miles of Eek that could develop a hydroelectric
project.
Alakanuk and Emmonak are 170 miles northwest of Bethel at the mouth of
the Yukon River, The terrain is very flat and there is no likelihood of
pcwer potentials in the area, (We have no pictures of these towns),
112
Chevak is 150 miles northwest of Bethel on the Ningikfak River, The
closest hydro potential would be in the Askinuk Mountains, roughly
20 miles across potholes and permafrost. The expense of a transmission
line does not make hydropower look promising for Chevak, even if a hydro
potential similar to the one at Scammon Bay could be located in the
mountains. Wind generation may be a possibility for the village of
Chevak,
113
Hooper Bay, 160 miles northwest of Bethel on the flats of the Yukon
River delta. The closest hills with a hydroelectric potential would be
the Askinuk Mountains 25 miles by land composed of mostly lakes and
potholes. An electric transmission line from Hooper Bay to the mountains
would be difficult to construct and expensive. Also, another hydroelec-
tric potential similar to the spring that flows all year round off the
high mountain behind Scammon Bay would need to be located. Even if
another hydro potential could be located, the expense and technical
construction problems of the transmission line does not make the hydro
project look promising. Wind power right at Hooper Bay without any
transmission lines may look more promising.
The Ekasluktuli River in the
Askinuk Mountains flows past
Cape Romanzof military site.
The stream may have a hydro
potential if it flows all
year round. No data on year-
round flow is available to
the authors at this time.
Transmission line distance
to Hooper Bay would be 25
rough miles.
114
Nunapitchuk located 30 miles northwest of Bethel. From inspection and
the picture, there are no hydroelectric potentials within reasonable
transmission distance of town.
Kasigluk is 30 miles northwest of Bethel. As can be seen in the pic—
ture, there are no hills or potential streams for diversion as hydro
projects within reasonable transmission distance of the town,
115
The Kanektok River flows through Quinhagok. There are no hills within
many miles of Quinhagok to develop head for a hydroelectric project,
m
The village of Quinhagok, 70 miles south of Bethel on Kuskokwim Bay.
116
Lower Yukon River Area
Most of the town on the banks of the lower Yukon River are on hills or
have hills nearby, However, the rainfall of 10 to 20 inches per year is
not large enough to maintain flows year round, or in most cases during
the whole summer.
The area around Mountain Village and St. Marys was examined from maps in
the office and flown over twice in an effort to find a hydro site, The
Andreafsky River has a large year-round flow, but no obvious storage
sites or economical diversion sites could be located. This area has the
largest concentration of power demand of anywhere in the AVEC system,
Further examination for hydropower sites, the possibility of intercon-
necting several towns, and the wind power potential should be examined
for this area,
The pictures that follow show the villages, some of which have hills for
hydro, but inadequate water supplies. Villages in this area are:
Anvik
Holy Cross
Huslia (on the Koyukuk River,
a tributary to Yukon River)
Marshall (Fortuna Lodge)
Mountain Village
Nulato
Pilot Station
Pitkas Point/St, Marys
117
The village of Anvik on the bank of the Anvik River where it joins the
Yukon River, As shown in the picture, there are no hills with streams
to provide a hydroelectric potential for the village,
118
Looking upstream on the Yukon River at the village of Holy Cross,
A drainage area in the Holy Cross hills southwest of Holy Cross, The
stream did not appear to have an established streambed and water stood
in pockets along the broad valley,
119
Another drainage basin in the Holy Cross hills southwest of the village
had a stream a few inches wide that flowed into a slough at the base of
the mountain. The hills do not seem to have an adequate water supply or
height to support a hydro potential that could serve Holy Cross.
120
Huslia is on the bank of the Koyukuk River, a tributary to the Yukon
River, There are no hills with streams that have water supply for a
hydroelectric potential within reasonable transmission line distance of
Huslia,
121
Marshall (Fortuna Ledge) on the bank of the Yukon River, showing the
flat, rolling hills behind the village. No streams were found in the
hills that had an adequate water supply to provide a hydroelectric
potential.
122
Mountain Village on the bank of the lower Yukon River.
Typical view of the drainage areas behind Mountain Village which are
broad, flat, and have no streams flowing that could produce hydroelec-
tric power potential,
123
The village of Nulato on the bank of the Yukon River, The drainage area
of the Nulato River behind town is very flat.
View of the meandering Nulato River where it enters the Yukon River.
The small drainage areas on the hillsides in the background are not
large enough to provide an adequate water supply for a hydro site,
primarily due to the low rainfall in the area.
124
Pilot Station on the bank of the Yukon River, showing the drainage area
behind town.
The drainage area behind Pilot Station, looking toward the village. The
low trees and shrubs have overgrown the streambed and there doesn't
appear to be any flow in the stream valley.
125
The village of Pitkas Point on the bank of the Yukon River, showing the
drainage area behind town. The road goes to the landing strip which
serves both Pitkas Point and St. Marys. There are reports of a small
hydro project here that provides light for a house and cannery.
The Andreafsky River flows through a wide valley between gentle rolling
hills in the Pitkas Point and St. Mary's area. The side tributaries
to the river also have gentle slopes and no storage or diversion type
hydroelectric potentials were located.
126
St. Mary's on the bank of the Andreafsky River where it joins the Yukon
River, The low, rounded hills in the drainage area behind St. Mary did
not have any flowing streams in them August 1979.
128
The hills around Shageluk were examined carefully to locate any flowing
streams that might be hydroelectric power water supplies. No flowing
streams were found on the hillsides.
A view of Shageluk on the bank of the Innoko River, a tributary to the
Yukon River.
129
NORTON SOUND AREA
The villages along the coast of Norton Sound that were
ically get 20 inches or less precipitation annually,
pictures show the low relief ._-rain near the villages
with the low water runoff, of ininates the two basic
successful hydropower development,
Villages shown are:
Koyuk St Michael
Shaktoolik Stebbins
inspected typ—
The following
which, coupled
necessities for
130
Koyuk is located at the mouth of the Koyuk River on Norton Sound
130 miles east of Nome.
The stream behind Koyuk that enters the Koyuk River 2 miles east of town
has less than 5 cubic feet per second flow August 1979, too little to
supply a significant amount of the village needs. The hills behind town
are rounded and no storage sites could be located,
131
Shaktoolik is 120 miles east of Nome on Norton Sound, Nearest hills are
10 to 15 miles, Possible hydropower site on Shaktoolik River, but there
are samlon in the river and there were many fish camps all along the
river,
St. Michael is 120 miles southeast of Nome on .Norton Sound, No hydro-
power sites were found nearby,
132
Stebbins Village is 110 miles southeast of Nome. No hydropower sites
were located nearby,
133
KOTZEBUE SOUND AREA
The Kotzebue Sound area receives only about 10 inches of rainfall
annually. This is the dryest area inspected for hydropower in this
study. Again the villages are located in areas without mountains nearby
or streams with enough drop to develop hydropower. The villages and
surrounding terrain are shown in the following pictures,.
Kivalina Selawik
Noatak Shishmaref
Noorvik
Buckland (potential AVEC village)
Deering (potential AVEC village)
134
Kivalina is on the end of a spit at the edge of the Arctic Ocean,
80 miles northwest of Kotzebue.
The topography behind the village of Kivalina is flat permafrost low-
lands of the Kivalina River delta. No hydroelectric potentials were
located in the distant rounded hills.
135
Roatak on the bank of the Noatak River, 50 miles north of Kotzebue, is
surrounded by flat lowlands and has no hydro potential nearby.
The village of Noorvik is located on the Kobuk River delta and is sur-
rounded by sloughs and channels meandering towards the main river. The
low rounded hills in the distant background have small drainage areas
and generally low water supply, neither of which are conducive to good
hydroelectric projects,
136
Shishmaref is located on an island on the north side of the Seward
Peninsula next to the Chukchi Sea on the Arctic Ocean. There are no
hills with hydroelectric potential within many miles of the village as
shown on the photograph.
-�1
The village of Selewik is located in the delta of the Selewik River.
There are no hills with hydro potential within reasonable transmission
line distance of Selewik.
137
Deering, located 60 miles south of Kotzebue across Kotzebue Sound, does
not appear to have any hydroelectric potentials nearby. Electric de-
mands are increasing significantly for Deering and they are considering
AVEC management of their power system.
Buckland, 100 miles southeast of Kotzebue, is also considering the
Alaska Village Cooperative power system. Power demands are increasing
as evidenced by the new school, communications system, and houses shown
in this picture. A few sod houses along the river bank still perform in
the winter climate quite well.
138
Sites Not Examined
Three sites studied in the office, but not examined in the field were
Minto, Gamble, and Savoonga. Minto was not visited because of the low
precipitation in the area, flat terrain, and it was considerably off the
flight path. Gamble and Savoonga were not visited primarily because of
weather conditions in August 1978, and the necessity to charter a twin -
engine aircraft. There are reports of a stream located between Gamble
and Savoonga that flows year-round, but the available head needed to
develop power could not be confirmed from office studies of existing
maps.
139
UVINDRID
Project Cost Calculation Sheets
Project Cost Calculations
Following the field examinations, some basic assumptions were formulated
to estimate the associated project costs These cost assumptions are
based on July 1979 Alaska costs and are to be considered as approximate
only.
Unit costs for power plants were estimated at $900 per kilowatt based on
recent experience and manufacturers' costs. The diversion structure to
divert the water into the pipeline was estimated at $10,000 lump sum.
Pipelines were estimated as steel at a cost of $2 per pound based on
recent experience in Alaska. Transmission lines were in the 7 to 15 kV
range and single phase in most cases. A cost. of $40,000 per mile was
used in estimating. Roads were assigned a cost of $25,000 per mile for
those sites needing access roads. Twenty-five percent contingencies
were added to all the above costs.
Interest during construction was assumed to be for one year and was not
included for this level of estimate. The 7 percent interest rate was
selected only as a means of providing a comparison between other vari-
--,:
abies and does not indicate the actual iniereei. caLC wuiui way 'uc nyyi+"'
cable for a specific project.
INDEX OF VILLAGES
NAME PAGE
Ambler A-1 to A-8
Elim
A-9 to A-12
Goodnews Bay
A-13
to
A-16
Grayling
A-17
to
A-20
Kaltag
A-21
to
A-24
Kiana
A-25
to
A-32
Lower Kalskag
A-33
to
A-36
Mekoryuk
A-37
to
A-40
New Stuyahok
A-41
to
A-44
Shungnak
A-45
to
A-49
Tanunak
A-49
to
A-52
Toksook Bay
A-53
to
A-56
Wales
A-57
to
A-60
Scammon Bay
A-61
to
A-62
Togiak
A-63
to
A-66
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - AMBLER (Meet present demand)
FLOW (CFS) - 30
HEAD (FT) - 200
PIPELENGTH (FT) - 5000
TRANSMISSION LINE LENGTH (MILES) - 10
ROAD LENGTH (MILES) - 10
CALCULATED VALUES
PIPESIZE (IN) - 30
HEADLOSS (FT) - 19.3445
PIPE COST ($/FT) - 160
MAXIMUM POWER (KW) - 370
ENERGY at 30% P.F. (kWh) - 972360
CONSTRUCTION COSTS
POWER PLANT - 370 KW X $900/KW =
Year -Round Operation
DIVERSION STRUCTURE _
PIPELINE - 5000 FT X $ 160/FT =
TRANSMISSION LINE - 10 MILES X $ 40000/MILE _
ROAD - 10 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. )
$ 333,000
$ 10,000
$ 800,000
$ 400,000
$ 250,000
$ 0
ee�aratat����3rat
$ 1,793,000
$ 448,000
ate##ar#at�at�at#
$ 2,241,000
$ 448,000
i?i$ 2,6e9,000 <<<
$ 254,000
$ 40, 000
$ 7,300
$ .30
*********mot*MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($0. 18/KWH)
$ 2,846,040
$ 2, 168, 940
$ 1, 558, 410
$1. 68/GAL. ($0. 24/KWH)
$ 31816,180
$ 2,908.200
$ 2,130,090
$3. 50/GAL_ ($0. 50/KWH)
$ 7,949,820
$ 6, 058, 3SO
$ 4,437,780
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 8/79
A- 1
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - AMBLER (Meet present demand)
FLOW (CFS) - 30
HEAD (FT) - 200
PIPELENGTH (FT) - 5000
TRANSMISSION LINE LENGTH (MILES) - 10
ROAD LENGTH (MILES) - 10
CALCULATED VALUES
PIPESIZE (IN) - 30
HEADLOSS (FT) - 19.3445
PIPE COST ($/FT) - 160
MAXIMUM POWER (KW) - 370
ENERGY at 30% P. F. (kWh) - 324120
Summer Operation Only
CONSTRUCTION COSTS
POWER PLANT - 370 KW X $900/KW =
DIVERSION STRUCTURE _
PIPELINE - 5000 FT X $ 160/FT =
TRANSMISSION LINE - 10 MILES X $ 40000/MILE _
ROAD - 10 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P.F.)
$ 333,000
$ 10,000
$ e0o, 000
$ 400,000
$ 250,000
�arat���#�t�ar#et
$ 1,793,000
$ 448,000
$ 2,241,000
$ 448,000
>>>$ 2,689,000 «<
$ 254,000
% 40,000
$ 7,300
$ .91
#####*######MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST RATE
FUEL COST
2%
57
q'/.
$1. 25/GAL. ($0. 18/KWH)
$ 948,680
$ 722, 980
$ 529,470
$1. 68/GAL. ($O. 24/KWH)
$ 1,272,060
$ 969,400
$ 710,030
$3. 50/GAL. ($0. 50/KWH)
$ 2,649,940
$ 2,019,460
$ 1,479,260
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 8/79
A-2
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - AMBLER (Meet present demand)
FLOW (CFS) - 60
HEAD (FT) - 200
PIPELENGTH (FT) - 5000
TRANSMISSION LINE LENGTH (MILES) - 10
ROAD LENGTH (MILES) - 10
CALCULATED VALUES
PIPESIZE (IN) - 40
HEADLOSS (FT) - 17.6326
PIPE COST ($/FT) - 210
MAXIMUM POWER (KW) - 740
ENERGY at 30% P. F. (kWh) - 1. 94472E6
Double Flom, Year -Round
CONSTRUCTION COSTS
POWER PLANT - 740 KW X $900/KW =
DIVERSION STRUCTURE _
PIPELINE - 5000 FT X $ 210/FT =
TRANSMISSION LINE - 10 MILES X $ 40000/MILE _
ROAD - 10 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. ) .
$ 666,000
$ 10,000
$ 11050,000
1 400,000
$ 250,000
$ 0
$ 2,376.000
$ 594,000
***#atetet�-ttar�at
$ 2,970,000
$ 594,000
>>>$ 3, 564, 000 CSC
$ 336,000
$ 53.000
$ 4,800
$ .20
************MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($0. 18/KWH)
$ 5,692,080
$ 4,337,880
$ 3,176,820
$1. 68/GAL. ($0. 24/KWH)
$ 7,632,360
$ 5,816,400
$ 4,260,180
$3. 50/GAL. ($0. 50/KWH)
$15, 899, 640
$12, 116, 760
$ 8,975,560
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 8/79
A-3
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - AMBLER (Meet present demand)
FLOW (CFS) - 60
HEAD (FT) - 200
PIPELENGTH (FT) - 5000
TRANSMISSION LINE LENGTH (MILES) - 10
ROAD LENGTH (MILES) - 10
CALCULATED VALUES
PIPESIZE (IN) - 40
HEADLDSS (FT) - 17.6326
PIPE COST ($/FT) - 210
MAXIMUM POWER (KW) - 740
ENERGY at 30% P.F. (kWh) - 648240
Double Flow, Summer Only
CONSTRUCTION COSTS
POWER PLANT - 740 KW X $900/KW =
DIVERSION STRUCTURE =
PIPELINE - 5000 FT X $ 210/FT =
TRANSMISSION LINE - 10 MILES X $ 40000/MILE _
ROAD - 10 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL 0&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. )
$ 666,000
$ 10,000
$ 11050,000
$ 400,000
$ 250,000
$ 0
$ 2,376.000
$ 594,000
tt�� it-uaratn-a3t�ar
$ 2,970,000
$ 594,000
-tt-atat�# #-ttar-��atat
>>>$ 3,564,000 <<<
336,000
$ 53,000
4,800
$ .60
************MAXIMUM EXPENDITURES FOR FUEL REPLACEMENT************
INTEREST RATE
FUEL COST 2% 5% 9%
$1. 25/GAL. ($0. 18/KWH) $ 1,897,360 $ 1,445,960 $ 1,056,940
$1. 68/GAL. ($0. 24/KWH) $ 2,544,120 $ 1,93G,800 $ 1,420,060
$3. 50/GAL. ($O. 50/KWH) $ 5, 299, 880 $ 4,038,920 $ 2,958,520
NOTES: Plant,.Factor of 30% used
All figures are to be considered rough estimates
APA 8/79
A-4
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
�##�t����et������at�tatat�t+teat#e�ateatatit�atat��ea�areatat#�tateate�+t#e ��e#steer##at��atat�at�t� ttet
PLANT SITE — AMBLER (Maximum potential)
FLOW (CFS) — 100
HEAD (FT) — 200
PIPELENGTH (FT) — 5000
TRANSMISSION LINE LENGTH (MILES) — 10
ROAD LENGTH (MILES) — 10
CALCULATED VALUES
PIPESIZE (IN) — 48
HEADLOSS (FT) — 19.0476
PIPE COST ($/FT) — 250
MAXIMUM POWER (KW) — 1225
ENERGY at 3OX P. F. (kWh) — 3. 2193E6
CONSTRUCTION COSTS
POWER PLANT — 1225 KW X $900/KW =
Year —Round Operation
DIVERSION STRUCTURE
PIPELINE — 5000 FT X $ 250/FT =
TRANSMISSION LINE — 10 MILES X $ 40000/MILE _
ROAD — 10 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL 0&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 3O% P.F.)
$ 1,103,000
$ 10,000
$ 1,250,000
$ 400,000
$ 250,000
$ 0
at �atatitat-�tatatatat-x
3,013,000
$ 753,000
$ 3,766,000
$ 753,000
itatatatatatatat-tt-�tatat
»>$ 4,519,000 <<<
$ 427,000
$ 68,000
$ 3,700
$ . 15
************MAXIMUM ***MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($0. 18/KWH)
$ 9,422,700
$ 7,180,950
$ 5,258,925
$1. 68/GAL. ($0. 24/KWH)
$12, 634, 650
$ 9,628,500.
$ 7,052,325
$3. 50/GAL. ($0. 50/KWH)
$26, 320, 350
$20, 058, 150
$14, 692, 650
NOTES
Plant Factor of 30% used
All figures are to be considered rough estimates
APA 8/79
rw
U.S. DEPARTMENT OF ,ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - AMBLER (Maximum potential)
FLOW (CFS) - 100
HEAD (FT) - 200
PIPELENGTH (FT) - 5000
TRANSMISSION LINE LENGTH (MILES) - 10
ROAD LENGTH (MILES) - 10
CALCULATED VALUES
PIPESIZE (IN) - 48
HEADLOSS (FT) - 19.0476
PIPE COST ($/FT) - 250
MAXIMUM POWER (KW) - 1225
ENERGY at 30% P.F. (kWh) - 1. 0731E6
Summer Operation Only
CONSTRUCTION COSTS
POWER PLANT - 1225 KW X $900/KW =
DIVERSION STRUCTURE _
PIPELINE - 5000 FT X $ 250/FT =
TRANSMISSION LINE - 10 MILES X $ 40000/MILE _
ROAD - 10 MILES X $ 25000/MILE
MISCELLANEOUS COSTS =
BASE: COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. )
$ 1,103,000
$ 10,000
$ 1,250,000
$ 400,000
$ 250,000
$ 0
$ 3,013,000
$ 753,000
************
$ 3,766,000
$ 753,000
************
>>>$ 4,519,000 <CC
$ 427,000
$ 62,000
$ 3,700
$ .46
************MAXIMUM EXPENDITURES_ FOR FUEL REPLACEMENT************
INTEREST RATE
FUEL COST 2% 5% 9%
$1. 25/GAL. ($O. 18/KWH) $ 3,140,900 $ 2,393,6510 $ 1,752,975
$1. 68/GAL. ($0. 24/KWH) $ 4,211,550 $ 3,209,500 $ 2,350,775
$3. 50/GAL. ($0. 50/KWH) $ 8,773,450 $ 6,686,050 $ 4,897,550
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
fW0M1--1+1'I
A-6
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - AMBLER (Maximum potential) Double Flow, Year -Round
FLOW (CFS) - 200
HEAD (FT) - 200
PIPELENGTH (FT) - 5000
TRANSMISSION LINE LENGTH (MILES) - 10
ROAD LENGTH (MILES) - 10
CALCULATED VALUES
PIPESIZE (IN) - 64
HEADLOSS (FT) - 17
PIPE COST ($/FT) -
MAXIMUM POWER (KW)
ENERGY at 30% P. F.
3619
340
2475
(kWh) - 6. 5043E6
CONSTRUCTION COSTS
POWER PLANT - 2475 KW X $900/KW =
DIVERSION STRUCTURE =
PIPELINE - 5000 FT X $ 340/FT =
TRANSMISSION LINE - 10 MILES X $
ROAD - 10 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
40000/MILE =
$ 2,228,000
$ 10,000
$ 1,700,000
$ 400,000
$ 250,000
$ 0
$ 4,588,000
$ 1,147,000
$ 5,735,000
$ 1,447,000
xarar-�rar#��at���
»>$ 6, 882, 000 «<
ANNUAL COST (20 yrs. at 7%
interest)
$
650,000
ANNUAL O&M COST
$
103,000
INSTALLED COST PER KILOWATT
$
2,800
COST PER kWh ( 30% P. F. )
$
.12
star**********MAXIMUM EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST RATE
FUEL COST
2'/.
5%
9%
$1. 25/GAL. ($0. 18/KWH)
$19, 037, 700
$14, 508, 450
$10, 625, 175
$1. 68/GAL_ ($0. 24/KWH)
$25, 527, 150
$19, 453, 500
$14, 248, 575
$3. 50/GAL. ($O. 50/KWH)
$53, 177, 650
$40, 525, 650
$29, 685, 150
NOTES
Plant Factor of 30% used
All figures are to be considered rough estimates
A-7
APA 8/79
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE — AMBLER (Maximum potential)
FLOW (CFS) — 200
HEAD (FT) — 200
PIPELENGTH (FT) — 5000
TRANSMISSION LINE LENGTH (MILES) — 10
ROAD LENGTH (MILES) — 10
CALCULATED VALUES
PIPESIZE (IN) — 64
HEADLOSS (FT) — 17,3619
PIPE COST ($/FT) — 340
MAXIMUM POWER (KW) — 2475
ENERGY at 30% P. F. (kWh) — 2. 1681E6
Double Flow, Summer Only
CONSTRUCTION COSTS
POWER PA -ANT — 2475 KW X $900/KW
DIVERSION STRUCTURE _
PIPELINE — 5000 FT X $ 340/FT =
TRANSMISSION LINE — 10 MILES X $ 40000/MILE _
ROAD — 10 MILES X $ 25000/MILE
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. )
$ 2,222,000
$ 10,000
$ 1,700,000
$ 400,000
$ 250,000
$ 0
e#�##jtar��at�at
$ 4, 588, 000
$ 1,147.000
#met-�r#at�t :u-ex-n
$ 5,735,000
$ 1,147,000
»$ 6,892,000 <C<
$ 650,000
$ 103,000
$ 2, BOO
$ .35
at#eee*******MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($O. 18/KWH)
$ 6,345,900
$ 4,836,150
$ 3,541,725
$1. 68/GAL. ($0. 24/KWH )
$ 8,509,050
$ 6,484,500
$ 4,749,525
$3. 50/GAL. ($O. 50/KWH)
$17, 725, 950
$13, 508, 550
$ 9,295,050
NOTES: Plant Factor of 30% used
All figures are to be - considered rough estimates
APA 8/79
on
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - ELIM Year -Round Operation
FLOW (CFS) - 10
HEAD (FT) - 200
PIPELENGTH (FT) - 3500
TRANSMISSION LINE LENGTH\(MILES) - 4.5
ROAD LENGTH (MILES) - O
CALCULATED VALUES
PIPESIZE (IN) - 20
HEADLOSS (FT) - 12.2454
PIPE COST ($/FT) - 100
MAXIMUM POWER (KW) - 125
ENERGY at 30% P.F. (kWh) - 328500
CONSTRUCTION COSTS
POWER PLANT - 125 KW X $900/KW =
DIVERSION STRUCTURE =
PIPELINE - 3500 FT X $ 100/FT =
TRANSMISSION LINE - 4.5 MILES X $ 40000/MILE
ROAD - 0 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. )
$
113,000
$
10,000
$
350,000
$
180,000
$
O
$
0
-met��ar�ar#�#mat
$
653,000
163,000
816,000
$
163,000
�#ar-xa#�is�#arar
>>>
979,000 <<<
$ 92,000
$ 15,000
$ 7,800
$ .33
*****ir******MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($0. 1S/KWH)
$ 961,500
$ 732,750
$ 536,625
$1. 68/GAL. ($0. 24/KWH)
$ 1,289,250
$ 982,500
$ 719,625
$3. 50/GAL. ($0. 50/KWH)
$ 2,685,750
$ 2,046,750
$ 1,499,250
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 8/79
A-9
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
arar ararar ararar arararararararar arar arararararararararararararararararararararararar �#�###� atarar#af ararar arararararararararararararar �
PLANT SITE — ELIM Summer Operation Only
FLOW (CFS) — 10
HEAD (FT) — 200
PIPELENGTH (FT) — 3500
TRANSMISSION LINE LENGTH (MILES) — 4.5
ROAD LENGTH (MILES) — O
CALCULATED VALUES
PIPESIZE (IN) — 20
HEADLOSS (FT) — 12.2454
PIPE COST ($/FT) — 100
MAXIMUM POWER (KW) — 125
ENERGY at 30% P.F. (kWh) — 109500
CONSTRUCTION COSTS
POWER PLANT — 125 KW X $900/KW
DIVERSION STRUCTURE =
PIPELINE — 3500 FT X $ 100/FT =
TRANSMISSION LINE — 4.5 MILES X $ 40000/MILE
AnDn - n MT1 cMILES v m 'J r+AAn ��.. TI r -
MISCELLANEOUS COSTS = _--
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P.F.)
$ 113,000
$
10,000
$
350,000
$
180,000
$
n_
$
O
�ararararatarararararar
$
653,000
$
163,000
ararararararar arararar+ar
$
816,000
$
163,000
arararararararararararar
»>$
979,000 <<<
$ 92,000
$ 15,000
$ 7,800
$ .98
****ararararar***MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST
RATE
FUEL CAST
2%
5%
9%
$1. 25/GAL. ($0. 18/KWH)
$ 320,500
$
244,250
$ 178,875
$1. 68/GAL. ($O. 24/KWH)
$ 429,750
$
327,500
$ 239,875
$3. 50/GAL. ($0. 50/KWH)
$ 895,250
s
682, 250
$ 499,750
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 8/79
M[i)
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
atat ee #atatat�atat#ate+tatatatatatae atatatatatat atatatatatatatatatatatatat atat ##�atat #atatatat atat atatatatatatat atat � �atatatatatatat
PLANT SITE — ELIM Double Flaw, Year —Round
FLOW (CFS) — 20
HEAD (FT) — 200
PIPELENGTH (FT) — 3500
TRANSMISSION LINE LENGTH (MILES) — 4.5
ROAD LENGTH (MILES) — O
CALCULATED VALUE
PIPESIZE (IN) — 24
HEADLOSS (FT) — 18.7043
PIPE COST ($/FT) — 130
MAXIMUM POWER (KW) — 245
ENERGY at 30% P.F. (kWh) — 643860
CONSTRUCTION COSTS
POWER PLANT — 245 KW X $900/KW =
DIVERSION STRUCTURE =
PIPELINE — 3500 FT X $ 130/FT
TRANSMISSION LINE — 4.5 MILES X
ROAD — O MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
$ 40000/MILE =
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P.F.)
$ 221,000
$ 10,000
$ 455,000
$ 180,000
$ O
$ 0
atatatatatatatatatatatat
$ 866,000
$ 217, 000
atatatatatatatatatatatat
$ 11083,000
$ 217,000
atatatat+tatatataE-uatat
>>>$ 11300.000 <<<
$ 123,000
$ 20,000
$ 5,300
$ _ 22
atatat#atatat****tMAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENTatatatatatatatatat***
INTEREST RATE
FUEL COST
2/
5%
9Z
$1. 25/GAL. ($O. 18/KWH)
$ 1, 884, 540
$ 1,436,190
$ 1,051,785
$1. 68/GAL. ($O. 24/KWH)
$ 2,526,930
$ 1,925.700
$ 1,410,465
$3. 50/GAL. ($0. 50/KWH)
$ 5, 264, 070
$ 4,011,630
$ 2,938,530
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 8/79
A-11
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
#�atet�# �etatititit�t#at�t�at�ti�atatatatatat� �#aret� ate ��ttatat�ttt # #�t� � ##��� �at��tet� �## a �#��r � #-xat#ate
PLANT SITE — ELIM Double Flow, Summer Only
FLOW (CFS) — 20
HEAD (FT) — 200
PIPELENGTH (FT) — 3500
TRANSMISSION LINE LENGTH (MILES) — 4.5
ROAD LENGTH (MILES) — O
CALCULATED VALUES
PIPESIZE (IN) — 24
HEADLOSS (FT) — 18.7043
PIPE COST ($/FT) — 130
MAXIMUM POWER (KW) — 245
ENERGY at 30% P.F. (kWh) — 214620
CONSTRUCTION COSTS
POWER PLANT — 245 KW X $900/KW =
DIVERSION STRUCTURE =
PIPELINE — 3500 FT X $ 130/FT
TRANSMISSION LINE — 4.5 MILES X $ 40000/MILE _
ROAD — 0 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL 0&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P.F.)
$ 221,000
$ 10,000
$ 455,000
$ 180,000
$ 0
$ 0
#atit�atetatetat� at�t
$ 866.000
$ 217,000
#ttat-�t-�tataratat�atat
$ 1,083,000
$ 217,000
3tattt�ataHtat�t�-�t�
>>>$ 1,300,000 «<
$ 123,000
$ 20,000
$ 5,200
Y, .67
************MAXIMUM EXPENDITURES FOR FUEL REPLACEMENT************
INTEREST RATE
FUEL COST
27
5%
9%
$1. 25/GAL. ($O. 18/KWH)
$ 628,180
$ 478,730
$ 350,595
$1. 68/GAL. ($O. 24/KWH)
$ 842,310
$ 641,900
$ 470,155
$3. 50/GAL. ($0. 50/KWH)
$ 1,754,690
$ 1,337,210
$ 979,510
NOTES: Plant Factor of 30% used
All figures ar.e..to be -considered rough estimates
`Al"w £9479
M
U.S. DEPARTMENT OP ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU,ALASKA
ESTIMATED HYDRO COSTS
��� eeeeeateeeeeeeeee eeeeateatateeeee+F�et+t��-mat #it+t�ar�ir� eater #atatat�t3t mar# mat# ##jt e�� at�at
PLANT SITE - GOODNEWS BAY
FLOW (CFS) - 14
HEAD (FT) - 100
PIPELENGTH (FT) - 3500
TRANSMISSION LINE LENGTH (MILES) - 5
ROAD LENGTH (MILES) - 5
CALCULATED VALUES
PIPESIZE (IN) - 24
HEADLOSS (FT) - 9.49791
PIPE COST ($/FT) - 130
MAXIMUM POWER (KW) - 85
ENERGY at 30% P. F. (kWh) 2233M
Year -Round Operation
POWER PLANT - 85 KW X $900/KW =
$
77,000
DIVERSION STRUCTURE _
$
10,000
PIPELINE - 3.500 FT X $ 130/FT =
$
455,000
TRANSMISSION LINE - 5 MILES X $ 40000/MILE
_ $
200,000
ROAD - 5 MILES X $ 25000/MILE _
$
125,000
MISCELLANEOUS COSTS =
$
0
eeeeeeeeeeee
BASE COST
$
867,000
CONTINGENCIES (25%)
$
217,000
eeeeeateeeeee
FIELD COST
$
1,084,000
OVERHEAD (20%)
$
217,000
eateateeeeeeee
CONSTRUCTION COST
»>$
1,301,000 <<<
ANNUAL COST (20 yrs. at 7% interest)
$
123,000
ANNUAL O&M COST
$
20,000
INSTALLED COST PER KILOWATT
$
15,300
COST PER kWh ( 30% P. F. )
$
.64
eeeeeeeeeee*MAXIMUM EXPENDITURES FOR FUEL
REPLACEMENTeeeeeeeeeeeat
INTEREST RATE
FUEL COST 2%
5%
9%
$1. 25/GAL ($0. 18/KWH) $ 653,820
$ 498,270
$ 364,905
$1.68/GAL. ($0.24/KWH) $ 876,690
$ 668,100
$ 489,345
$3. 50/GAL. ($0. 50/KWH) $ 1,826,310
$ 1,391,790
$ 1,019,490
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 8/79
A-13
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - GOODNEWS BAY
FLOW (CFS) - 14
HEAD (FT) - 100
PIPELENGTH (FT) - 3500
TRANSMISSION LINE LENGTH (MILES) - 5
ROAD LENGTH (MILES) - 5
CALCULATED VALUES
PIPESIZE (IN) - 24
HEADLOSS (FT) - 9.49791
PIPE COST ($/FT) - 130
MAXIMUM POWER (KW) - 85
ENERGY at 30% P.F. (kWh) - 74460
CONSTRUCTION COSTS
POWER PLANT - S5 KW X $900/KW =
DIVERSION STRUCTURE _
PIPELINE - 3500 FT X $ 130/FT =
TRANSMISSION LINE - 5 MILES X $
ROAD - 5 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
Summer Operation Only
40000/MILE _
$ 77,000
$ 10,000
$ 455,000
$ 200,000
$ 125,000
$ 0
$ 867,000
$ 217,000
$ 1,084,000
$ 217,000
>>>$ 11301,000 <<<
ANNUAL COST (20 yrs. at 7%
interest)
$
123,000
ANNUAL 0&M COST
$
20,000
INSTALLED COST PER KILOWATT
$
15,300
COST PER kWh ( 30% P. F. )
$
1. 92
************MAXIMUM EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST
RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($0. 18/KWH)
$ 217,940
$
166,090
$ 121,635
$1. 68/GAL. ($0. 24/KWH)
$ 292,230
$
222,700
$ 163,115
$3. 50/GAL. ($0. 50/KWH)
$ 608,770
$
463,930
$ 339,830
NOTES: Plant Factor of 30% used
All figures are to -be considered rough estimates
APA 8/79
A-14
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE — GOODNEWS BAY
FLOW (CFS) — 28
HEAD (FT) — 100
PIPELENGTH (FT) — 3500
TRANSMISSION LINE LENGTH (MILES) — 5
ROAD LENGTH (MILES) — 5
CALCULATED VALUES
PIPE5IZE (IN) — 32
HEADLOSS (FT) — 8.65736
PIPE COST ($/FT) — 170
MAXIMUM POWER (KW) — 175
ENERGY at 30% P.F. (kWh) — 459900
Double Flow, Year —Round
CONSTRUCTION COSTS
POWER PLANT — 175 KW X $900/KW =
DIVERSION STRUCTURE _
PIPELINE — 3500 FT X $ 170/FT =
TRANSMISSION LINE — 5 MILES X $ 40000/MILE _
ROAD — 5 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P.F.)
$ 158, 000
$ 10,000
$ 595,000
$ 200,000
$ 125,000
$ 0
atatatatatatatatae atatat
$ 11088, 000
$ 272,000
$ 1,360,000
$ 272,000
ataratatatatatatatat mat
>>>$ 1,632,000 <<<
$ 154,000
$ 24,000
$ 91300
$ 39
atatatatataaatata ***MAXIMUM
EXPENDITURES FOR FUEL REPLACEMENTatatatatatatatatat***
INTEREST
RATE
FUEL COST
2/
5%
9%
$1. 25/GAL. ($0. 18/KWH)
$ 1,346,100
$ 1,025,850
$ 751,275
$1. 68/GAL. ($0. 24/KWH)
$ 1,804,950
$ 1,375,500
$ 1,007,475
$3. 50/GAL. ($0. 50/KWH)
$ 3j760,050
$ 2,865,450
$ 2,098,950
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APR 8/79
"Dili
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE — GOODNEWS BAY
FLOW (CFS) — 28
HEAD (FT) — 100
PIPELENGTH (FT) — 3500
TRANSMISSION LINE LENGTH (MILES) — 5
ROAD LENGTH (MILES) — 5
CALCULATED VALUES
PIPESIZE (IN) — 32
HEADLOSS (FT) — 8.65736
PIPE COST ($/FT) — 170
MAXIMUM POWER (KW) — 175
ENERGY at 30% P_F. (kWh) — 153300
CONSTRUCTION COSTS
POWER PLANT — 175 KW X $900/KW =
DIVERSION STRUCTURE _
PIPELINE — 3500 FT X $ 170/FT =
TRANSMISSION LINE — 5 MILES X $ 40000/MILE
ROAD — 5 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (2O%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. )
Double Flow, Summer Only
$ 158,000
$ 10,000
$ 595,000
$ 200,000
$ 125,000
$ 0
$ 1, 088, 000
$ 272,000
$ 1,360,000
$ 272,000
��arar�aHr#tt�ar�
>>>$ 1,632,000 <<<
$ 154,000
$ 24,000
$ 91300
$ 1.16
************MAXIMUM EXPENDITURES FOR FUEL REPLACEMENT************
INTEREST
RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($0. 18/KWH)
$ 448, 700 $
341,950
$ 250,425
$1. 68/GAL. ($0. 24/KWH)
$ 601,650 $
458,500
$ 335,825
$3. 50/GAL. ($0. 50/KWH)
$ 1,253,350 $
955,150
$ 699,650
NOTES: Plant Factor of 30% used
All f cures are —to- be, gonsidered rough estimates
APA: 8/79...
FW1
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU. ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - GRAYLING (Grayling Cr.) Year -Round Operation
FLOW (CFS) - 75
HEAD (FT) - 50
PIPELENGTH (FT) - 6000
TRANSMISSION LINE LENGTH (MILES) - 2.5
ROAD LENGTH (MILES) - 0
CALCULATED VALUES
PIPESIZE (IN) - 60
HEADLOSS (FT) - 4.43382
PIPE COST ($/FT) - 310
MAXIMUM POWER (KW) - 230
ENERGY at 30% P.F. (kWh) - 604440
CONSTRUCTION COSTS
POWER PLANT - 230 KW X $900/KW =
DIVERSION STRUCTURE _
PIPELINE - 6000 FT X $ 310/FT =
TRANSMISSION LINE - 2.5 MILES X $ 40000/MILE _
ROAD - O MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. )
$ 207,000
$ 10,000
$ 1,860,000
$ 100,000
$ 0
$ 0
$ 2,177,000
$ 544,000
****#atatnaratn-x
$ 2,721,000
$ 544,000
>>>$ 3,265,000 L«.
$ 309,000
$ 49, 000
$ 14,200
$ 59
************MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST RATE
FUEL COST
27
5%
9%
$1. 25/GAL. ($O. 18/KWH)
$ 1,769,160
$ 1,348,260
$ 987,390
$1. 68/GAL. ($0. 24/KWH)
$ 2,372,220
$ 1,807,800
$ 1,324,110
$3. 50/GAL. ($O. 50/KWH)
$ 4, 941, 7SO
$ 3,766,020
$ 2,758,620
NOTES: Plant Factor of 30% used
All figures are to he considered rough' estimates_
- --- APA 9/79
A-17
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU,ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE — GRAYLING (Grayling Cr.)
FLOW (CFS) — 75
HEAD (FT) — 50
PIPELENGTH (FT) — 6000
TRANSMISSION LINE LENGTH (MILES) — 2.5
ROAD LENGTH (MILES) — 0
CALCULATED VALUES
PIPESIZE (IN) — 60
HEADLOSS (FT) — 4.43382
PIPE COST ($/FT) — 310
MAXIMUM POWER (KW) — 230
ENERGY at 30% P.F. (kWh) — 201480
CONSTRUCTION COSTS
POWER PLANT — 230 KW X $900/KW =
Summer Operation Only
DIVERSION STRUCTURE =
PIPELINE — 6000 FT X $ 310/FT =
TRANSMISSION LINE — 2.5 MILES X $ 40000/MILE _
ROAD — 0 MILES X # 25000/MILE
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. )
$ 207,000
$ 10,000
$ 1,860,000
$ 100,000
$ 0
$ 0
dt��tat�ar###tat
$ 2,177,000
$ 544,000
�3tat�t#at�arir#tat
$ 2,721,000
$ 544,000
atat�atatat ate-tt��t#
>>>$ 3,265,000 <<<
$ 308,000
$ 49,000
$ 14,200
$ 1.77
####*#******MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST RATE
FUEL COST
2%
5%
9%
$1.25/GAL. ($0.18/KWH)
$ 589,720
$ 449,420
$ 329,130
$1. 68/GAL. ($0. 24/KWH)
$ 790,740
$ 602,600
$ 441,370
$3. 50/GAL. ($0. 50/KWH)
$ 1, 647, 260
$ 1,255,340
$ 919,540
NOTES: Plant Factor of 30% used
All fi_ures are. to be considered rough estimates
APA` e/79
BOU
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU,ALASKA
ESTIMATED HYDRO COSTS
at � atatat atatatatatatat atatat ��#�atatatatatatatatatatatatatatat#star at �*atatat#�atat atatatatatat atatatatatat �#� # � atat atatat#�#
PLANT SITE — GRAYLING (Grayling Cr.) Double Flaw, Year —Round
FLOW (CFS) — 150
HEAD (FT) — 50
PIPELENGTH (FT) — 6000
TRANSMISSION LINE LENGTH (MILES) — 2.5
ROAD LENGTH (MILES) — 0
CALCULATED VALUES
PIPESIZE (IN) — 78
HEADLOSS (FT) — 4.57523
PIPE COST ($/FT) — 410
MAXIMUM POWER (KW) — 460
ENERGY at 30% P.F. (kWh) — 1.20888E6
CONSTRUCTION COSTS
POWER PLANT — 460 KW X $900/KW =
DIVERSION STRUCTURE =
PIPELINE — 6000 FT X $ 410/FT =
TRANSMISSION LINE = 2.5 MILES X
ROAD — O MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
$ 40000/MILE =
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. )
$ 414,000
$ 10,000
$ 2,460,000
$ 100,000
$ 0
$ 0
atatatatatatatatatatatat
$ 2,984,000
$ 746,000
atatatatatatatatatatatat
$ 3,730,000
$ 746,000
atatatatat#-x�atatatat
>$ 4, 476, 000 «<
$ 423,000
$ 67,000
$ 9,700
$ .41
atatatatatatatatat***MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENTatatatatatatatatat***
INTEREST RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($O. 18/KWH)
$ 3,53B,320
$ 2,696,520
$ 1,974,780
$1. 68/GAL. ($0. 24/KWH)
$ 4,744,440
$ 3,615,600
$ 2,648,220
$3. 50/GAL. ($0. 50/KWH)
$ 9,883,560
$ 7,532,040
$ 5,5171240
NOTES: Plant Factor of 30% used
All fisur-s._are--to be considered .rough estimates
APA 8/79
A-19
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
�##er-x#3r#ar-x�s-�s-##�t��at�atat-uar-�tet�at�tetaratat#��ru-��+t�-at�t�retat-z-mat--tat#��aeat���ar n-etatat#-natatat�at
PLANT SITE - GRAYLING (Grayling Cr.)
FLOW (CFS) - 150
HEAD (FT) - 50
PIPELENGTH (FT) - 6000
TRANSMISSION LINE LENGTH (MILES) - 2.5
ROAD LENGTH (MILES) - 0
CALCULATED VALUES
PIPESIZE (IN) - 78
HEADLOSS (FT) - 4.57523
PIPE COST ($/FT) - 410
MAXIMUM POWER.(KW) - 460
ENERGY at 30% P.F. (kWh) - 402960
CONSTRUCTION COSTS
POWER PLANT - 460 KW X $900/KW =
DIVERSION STRUCTURE =
PIPELINE - 6000 FT X $ 410/FT =
TRANSMISSION LINE - 2.5 MILES X
ROAD - 0 MILES X $ 25000/MILE
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
Double Flow, Summer Only
$ 40000/MILE =
$ 414,000
$ 10,000
$ 2,460,000
$ 100,000
$ 0
$ 0
atat 3t�tat�t-�taa-tF at-tr#
$ 2,984,000
$ 746,000
$ 3,730,000
$ 746,000
»>$ 4,476,000 «<
ANNUAL COST (20 yrs. at 7%
interest)
$
423,000
ANNUAL 0&M COST
$
67,000
INSTALLED COST PER KILOWATT
$
9,700
COST PER kWh ( 30% P. F. )
$
1.22
************MAXIMUM EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($0. 18/KWH)
$ 1,179,440
$ 898,840
$ 658, 260
$1. 66/GAL. ($0. 24/KWH)
$ 1,581,480
$ 1,205,200
$ 882, 740
$3. 50✓GAL. ( $O. 50/KWH )
$ 3,294,520
$ 2,510,680
$ 1,839,080
NOTES: Plant Factor of 30% used
A11 figur,e5.are---to-be considered rough estimates
_.. - ...
APA $/79
A-20
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU. ALASKA
ESTIMATED HYDRO COSTS
�e��#et���ir�tt�atteattt+f�###atatat#�natar�t#�earttarat��at#�ar�-n �#et�at���jtar����at;r#���at�at�t#�
PLANT SITE — KALTAG
FLOW (CFS) — 25
HEAD (FT) — 100
PIPELENGTH (FT) — 5000
TRANSMISSION LINE LENGTH (MILES) — 4
ROAD LENGTH (MILES) — 1.5
CALCULATED VALUES
PIPESIZE (IN) — 32
HEADLOSS (FT) — 9.97179
PIPE COST ($/FT) — 170
MAXIMUM POWER (KW) — 155
ENERGY at 30% P. F. (kWh) — 407340
Year —Round Operation
CONSTRUCTION COSTS
POWER PLANT — 155 KW X $900/KW =
DIVERSION STRUCTURE
PIPELINE — 5000 FT X $ 170/FT =
TRANSMISSION LINE — 4 MILES X $ 40000/MILE _
ROAD — 1.5 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. )
$ 140,000
$ 10,000
$ 850,000
$ 160,000
$ 313.000
$ 0
$ 11199,000
$ 300.000
acatat��#�ar�#at#
$ 1,498,000
$ 300. 000
>>>$ 1,798,000 <<<
$ 170,000
$ 27,000
$ 11,600
$ .48
************MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($O. 16/KWH)
$ 1,192,260
$ 908,610
$ 665,415
$1. 68/GAL. ($0. 24/KWH)
$ 1,598,670
$ 1,218,300
$ 892, 335
$3. 50/GAL. ($0. 50/KWH)
$ 3,330,330
$ 2,537,970
$ 1,859,070
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 8/79
A-21
U_ S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU,ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - KALTAG
FLOW (CFS) - 25
HEAD (FT) - 100
PIPELENGTH (FT) - 5000
TRANSMISSION LINE LENGTH (MILES) - 4
ROAD LENGTH (MILES) - 1.5
CALCULATED VALUES
PIPESIZE (IN) - 32
HEADLOSS (FT) - 9.97179
PIPE COST ($/FT) - 170
MAXIMUM POWER (KW) - 155
ENERGY at 30% P. F. (kWh) - 135780
CONSTRUCTION COSTS
POWER PLANT - 155 KW X $900/KW =
DIVERSION STRUCTURE =
PIPELINE - 5000 FT X $ 170/FT =
TRANSMISSION LINE - 4 MILES X $ 40000/MILE
ROAD - 1.5 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. )
Summer Operation Only
$ 140,000
$ 10,000
$ 850,000
$ 160,000
$ 38,000
$ 0
$ 11198,000
$ 300,000
$ 1,49S,000
$ 300,000
ec�tar���#��tt-ttat
>}7$ 1, 798, 000 <<<
$ 170,000
$ 27,000
$ 11,600
$ 1.45
**********##MAXIMUM EXPENDITURES FOR FUEL REPLACEMENT************
INTEREST
RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($O. 18/KWH)
$ 397,420 $
302,870
$ 221,805
$1. 68/GAL. ($0. 24/KWH)
$ - 532,890 $
406,100
$ 297, 445
$3. 50/GAL. ($0. 50/KWH)
$ 1, 110, 110 $
845.990
$ 619,690
NOTES
Plant Factor of 30% used
All figures are to be considered rough estimates
APA 8/79
A-22
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - KIANA (Canyon Cr.) Year -Round Operation
FLOW (CFS) - 50
HEAD (FT) - 150
PIPELENGTH (FT) - 6000
TRANSMISSION LINE LENGTH (MILES) - 9
ROAD LENGTH (MILES) - 0
CALCULATED VALUES
PIPESIZE (IN) - 40
HEADLOSS (FT) - 14.9642
PIPE COST ($/FT) - 210
MAXIMUM POWER (KW) - 460
ENERGY at 30% P. F. (kWh) - 1. 208e8E6
CONSTRUCTION COSTS
POWER PLANT - 460 KW X $900/KW =
DIVERSION STRUCTURE _
PIPELINE - 6000 FT X $ 210/FT =
TRANSMISSION LINE - 9 MILES X $ 40000/MILE
ROAD - 0 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL 0&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. )
$ 414,000
$ 10,000
$ 1,260,000
$ 360,000
$ 0
$ O
aratat�at�t#�eratat
$ 2,044,000
$ 511,000
.tatat###at##�atat
$ 2,555,000
$ 511,000
atataratat�at�-xac �#
>>>$ 3,066,000 «<
$ 289,000
$ 46,000
$ 6,700
$ .28
*****t****##MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($0. 18/KWH)
$ 3. 538, 320
$ 2,696,520
$ 1,974,780
$1. 68/GAL. ($0. 24/KWH)
$ 4,744,440
$ 3,615,600
$ 2,648,220
$3. 50/GAL. ($0. 50/KWH)
$ 9,B83,560
$ 7,532,040
$ 5,517,240
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 2/79
A-25
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU,ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - KIANA (Canyon Cr.)
FLOW (CFS) - 50
HEAD (FT) - 150
PIPELENGTH (FT) - 6000
TRANSMISSION LINE LENGTH (MILES) - 9
ROAD LENGTH (MILES) - 0
CALCULATED VALUES
PIPESIZE (IN) - 40
HEADLOSS (FT) - 14.9642
PIPE COST ($/FT) - 210
MAXIMUM POWER (KW) - 460
ENERGY at 30% P.F. (kWh) - 402960
CONSTRUCTION COSTS
POWER PLANT - 460 KW X $900/KW =
DIVERSION STRUCTURE =
PIPELINE - 6000 FT X $ 210/FT =
TRANSMISSION LINE - 9 MILES X $
ROAD - 0 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
Summer Operation Only
40000/MILE =
$ 414,000
$ 10,000
$ 1,260,000
$ 360,000
$ 0'
$ 0
ar�ater#atat�ater #at
$ 2,044,000
$ 511,000
atatatar�t#et-ttitaratat
$ 2,555,000
$ 511,000
>>>$ 3,066,000 <<<
ANNUAL COST (20 yrs. at 7% interest) $ 289,000
ANNUAL O&M COST $ 46,000
INSTALLED COST PER KILOWATT $ 6,700
COST PER kWh ( 30% P. F. ) $ .63
############MAXIMUM EXPENDITURES FOR FUEL REPLACEMENT************
INTEREST RATE
FUEL COST 2% 1 5% 9%
$1. 25/GAL. ($O. 18/KWH) $ 1,179,440 $ 898,840 $ 658,260
$1. 68/GAL. ($0. 24/KWH) $ 1,581,480 $ 1,205,200 $ 882,740
$3. 50/GAL. ($0. 50/KWH) $ 3,294,520 $ 2,510,680 $ 1, 839, 080
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
-- APA 8/79
A-26
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
�ar� # #+ems �ir�jtat� �#e �ir���#ataratjt�at�#�atatar�3t�ttar �at�t#�et�#�t#�aat�# #atft�at# mar###��at-x�ar�
PLANT SITE — KIANA (Canyon Cr.)
FLOW (CFS) — 100
HEAD (FT) — 150
PIPELENGTH (FT) — 6000
TRANSMISSION LINE LENGTH (MILES) — 9
ROAD LENGTH (MILES) — 0
CALCULATED VALUES
PIPESIZE (IN) — 54
HEADLOSS (FT) — 12.8343
PIPE COST ($/FT) — 280
MAXIMUM POWER (KW) — 930
ENERGY at 30% P. F. (kWh) — 2. 44404E6
CONSTRUCTION COSTS
POWER PLANT — 930 KW X $900/KW =
Double Flow, Year —Round
DIVERSION STRUCTURE _
PIPELINE — 6000 FT X $ 28O/FT =
TRANSMISSION LINE — 9 MILES X $ 40000/MILE _
ROAD — O MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. )
$ 237,000
$ 10,000
$ 1,680,000
$ 360,000
$ 0
$ 2,887,000
$ 722,000
$ 3, 609, 000
$ 722,000
�ararer#aret�##ate
4,331,000 <<<
$ 409,000
$ 65,000
$ 4,700
$ . 19
************MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($0. 18/KWH)
$ 7,153,560
$ 5,451,660
$ 3,992,490
$1. 68/GAL. ($0. 24/KWH)
$ 9,592,020
$ 7, 309, 800
$ 5,354,010
$3. 50/GAL. ($0. 50/KWH)
$19196I, 980
$15, 227, 820
$11, 154, 420
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 8/79'
A-27
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
�#�•z ar a•�•�t+rat#��-�t��e•3rar�3t•�raterarer•prat-star•�r-narar�atararir•e#�r•x•xatit+ttt �at•n•ar�##atar3t�arar-x�•�r•e�at•�••a�3t+r
PLANT SITE — KIANA (Canyon Cr.) Double Flow, Summer Only
FLOW (CFS) — 100
HEAD (FT) — 150
PIPELENGTH (FT) — 6000
TRANSMISSION LINE LENGTH (MILES) — 9
ROAD LENGTH (MILES) — O
CALCULATED VALUES
PIPESIZE (IN) — 54
HEADLOSS (FT) — 12.8343
PIPE COST ($/FT) — 280
MAXIMUM POWER (KW) — 930
ENERGY at 30% P.F. (kWh) — S14660
POWER PLANT — 930 KW X $900/KW =
t
837,000
DIVERSION STRUCTURE _
$
10,000
PIPELINE — 6000 FT X $ 280/FT =
$
1,680,000
TRANSMISSION LINE — 9 MILES X $ 40000/MILE
_ $
360,000
ROAD — 0 MILES X $ 25000/MILE _
$
0
MISCELLANEOUS COSTS =
0
�••z••x�•xatatetar �atat
BASE COST
2,997,000
CONTINGENCIES (25%)
$
722,000
FIELD COST
$
3,609,000
OVERHEAD (20%)
$
722,000
CONSTRUCTION COST
»>$
4,331,000 «<
ANNUAL COST (20 yrs. at 7% interest)
$
409,000
ANNUAL O&M COST
$
65,000
INSTALLED COST PER KILOWATT
$
4,700
COST PER kWh ( 30% P. F. )
$
.58
************MAXIMUM EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST RATE
FUEL COST 2%
5%
9%
$1. 25/GAL. ($0. 18/KWH) $ 2,384,520
$ 1, 817, 220
$ 1,530,830
$1. 68/GAL. ($0. 24/KWH) $ 3,197,340
$ 2,436,600
$ 1,794.670
$3. 50/GAL. ($0. 50/KWH) $ 6,660,660
$ 5,075,940
$ 3,718,140
NOTES: Plant Factor of 30% used
All figurQs.are.-.to'be-consider.ed.rough estimates
O?
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - KIANA' (Reduced flow)
FLOW (CFS) - 25
HEAD (FT) - 150
PIPELENGTH (FT) - 6000
TRANSMISSION LINE LENGTH (MILES) - 9
ROAD LENGTH (MILES) - 0
CALCULATED VALUES
PIPESIZE ( IN) - 32
HEADLOSS (FT) - 11.9661
PIPE COST ($/FT) - 170
MAXIMUM POWER (KW) - 235
ENERGY at 30% P.F. (kWh) - 617580
CONSTRUCTION COSTS
POWER PLANT - 235 KW X'$900/KW =
Year -Round Operation
DIVERSION STRUCTURE _
PIPELINE - 6000 FT X $ 170/FT =
TRANSMISSION LINE - 9 MILES X $ 40000/MILE _
ROAD - 0 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 grs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. )
$ 212, 000
$ 10,000
$ 1,020,000
$ 360,000
$ 0
$ 1,602,000
$ 401,000
$ 2,003,000
$ 401,000
#,t�atit�ttt#-ttatatat
2, 404, 000 F�4
$ 227,000
$ 36,000
$ 10, 200
$ .43
#**###******MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($O. 18/KWH)
$ 1,807,620
$ 1,377,570
$ 1,006,355
$1. 68/GAL ($0. 24/KWH)
$ 2,423,790
$ 1,847,100
1,352,895
$3. 50/GAL. ($0. 50/KWH)
$ 5,049,210
$ 3,847,B90
$ 2, 818, 590
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 8/79
A-29
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU,ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - KIANA (Reduced flow)
FLOW (CFS) - 25
HEAD (FT) - 150
PIPELENGTH (FT) - 6000
TRANSMISSION LINE LENGTH (MILES) - 9
ROAD LENGTH (MILES) - 0
CALCULATED VALUES
PIPESIZE (IN) - 32
HEADLOSS (FT) - 11.9661
PIPE COST ($/FT) - 170
MAXIMUM POWER (KW) - 235
ENERGY at 30% P.F. (kWh) - 205660
r
Summer Operation Only
CONSTRUCTION COSTS
POWER PLANT - 235 KW X $900/KW =
DIVERSION STRUCTURE =
PIPELINE - 6000 FT X $ 170/FT =
TRANSMISSION LINE - 9 MILES X $ 40000/MILE _
ROAD - 0 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. )
$ 212,000
$ 10,000
$ 11020,000
$ 360,000
$ 0
$ 0
$ 1,602,000
$ 401,000
$ 2,003,000
$ 401,000
2, 404, 000 C<<
$ 227,000
$ 36, 000
$ 10,200
$ 1.28
############MAXIMUM EXPENDITURES FOR FUEL REPLACEMENT************
INTEREST
RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($0. 18/KWH)
$ 602,540 $
459,190
$ 336, 285
$1. 68/GAL. ($0. 24/KWH)
$ 807,930 $
615,700
$ 450,965
$3. 50/GAL. ($0. 50/KWH)
$ 1,683,070 $ 1,282,630
$ 939,530
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 8/79
A-30
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE — KIANA(Reduced flow)
FLOW (CFS) — 50
HEAD (FT) — 150
PIPELENGTH (FT) — 6000
TRANSMISSION LINE LENGTH (MILES) — 9
ROAD LENGTH (MILES) — 0
CALCULATED VALUES
PIPESIZE (IN) — 40
HEADLOSS (FT) — 14.9642
PIPE COST ($/FT) — 210
MAXIMUM POWER (KW) — 460
ENERGY at 30% P.F. (kWh) — 1.2088SE6
Double Flow, Year —Round
CONSTRUCTION COSTS
POWER PLANT — 460 KW X $900/KW =
DIVERSION STRUCTURE =
PIPELINE — 6000 FT X $ 210/FT =
TRANSMISSION LINE — 9 MILES X $ 40000/MILE _
ROAD — 0 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL 0&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. )
$ 414,000
$ 10,000
* 1,260,000
* 360,000
i 0
* 2,044,000
* 511,000
$ 2,555,000
$ 511,000
i??$ 3, 066, 000 CCC
$ 289,000
$ 46,000
$ 6,700
2 .29
######******MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($0. 18/KWH)
$ 3,538,320
$ 2,696,520
$ 1,974,730
$1. 68/GAL. ($0. 24/KWH)
$ 4,744,440
$ 3,615,600
$ 2,648,220
$3. 50/GAL. ($0. 50/KWH)
$ 9, 8S3, 560
$ 7,532,040
$ 5,517,240
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 8/79
Oslo
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU,ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - KIANA (Reduced flow)
FLOW (CFS) - 50
HEAD (FT) - 150
PIPELENGTH (FT) - 6000
TRANSMISSION LINE LENGTH (MILES) - 9
ROAD LENGTH (MILES) - 0
CALCULATED VALUES
Double Flow, Summer Only
PIPESIZE (IN) - 40
HEADLOSS (FT) - 14.9642
PIPE COST ($/FT) - 210
MAXIMUM POWER (KW) - 460
ENERGY at 30% P.F. (kWh) - 402960
CONSTRUCTION COSTS
POWER PLANT - 460 KW X $900/KW =
DIVERSION STRUCTURE _
PIPELINE - 6000 FT X $ 210/FT =
TRANSMISSION LINE - 9 MILES X $ 40000/MILE _
ROAD - 0 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P.F.)
$ 414, 000
$ 10,000
$ 1,260,000
$ 360,000
$ 0
$ 0
carat-tt#####�#jr
$ 2, 044, 000
$ 511,000
$ 2,555,000
$ 511,000
;$ 3, 066, 000
$ 289, 000
$ 46,000
$ 6,700
$ .83
#*####******MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($0. 18/KWH)
$ 1,179,440
$ 898, 840
$ 658,260
$1. 68/GAL. ($0. 24/KWH)
$ 1, 581, 480
$ 1,205,200
$ 582, 740
$3. 50/GAL. ($0. 50/KWH)
$ 3,294,520
$ 2,510,680
$ 1,339,080
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 9/79
A-32
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
��#��#�##�a�##�#�-#��##�#at���##�t-mat#��#���x##�����#tr##���,��#�•u-#��#�##�.�##�#
PLANT SITE - LOWER' KALSKAG Year -Round Operation
FLOW (CFS) - 2
HEAD (FT) - 100
PIPELENGTH (FT) - 8000
TRANSMISSION LINE LENGTH (MILES) - 3.5
ROAD LENGTH (MILES) - 3.5
CALCULATED VALUES
PIPESIZE (IN) - 14
HEADLOSS (FT) - 7.55043
PIPE COST ($/FT) - 70
MAXIMUM POWER (KW) - 15
ENERGY at 30% P.F. (kWh) - 39420
CONSTRUCTION COSTS
POWER PLANT - 15 KW X $900/KW =
DIVERSION STRUCTURE _
PIPELINE - 8000 FT X $ 70/FT =
TRANSMISSION LINE - 3.5 MILES X $ 40000/MILE _
ROAD - 3.5 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P.F.)
14,000
10,000
$ 560,000
$ 140,000
881000
0
$ 912,000
$ 202,000
$ 11015,000
$ 203,000
$ 115,000
$ 13,000
81, 200
3.37
*****u••tt•*****MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST
RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($0. 18/KWH)
$ 115,380
$
87,930
$ 64,395
$1. 68/GAL. ($0. 24/KWH)
$ 154,710
$
117,900
$ 86, 355
$3. 50/GAL. ($0. 50/KWH)
$ 322,290
$
245,610
$ 179,910
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 9/79
A-33
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU,ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - LOWER KALSKAG Summer Operation Only
FLOW (CFS) - 2
HEAD (FT) - 100
PIPELENGTH (FT) - 8000
TRANSMISSION LINE LENGTH (MILES) - 3.5
ROAD LENGTH (MILES) - 3.5
CALCULATED VALUES
PIPESIZE (IN) - 14
HEADLOSS (FT) - 7.55043
PIPE COST ($/FT) - 70
MAXIMUM POWER (KW) - 15
ENERGY at 30% P.F. (kWh) - 13140
CONSTRUCTION COSTS
POWER PLANT - 15 KW X $900/KW =
DIVERSION STRUCTURE =
PIPELINE - 8000 FT X $ 70/FT =
TRANSMISSION LINE - 3.5 MILES X $ 40000/MILE _
ROAD - 3.5 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P.F.)
$ 14,000
$ 10,000
$ 560,000
$ 140,000
$ Be, 000
$ 0
#•tt##aE###-xatat#
$ 812,000
$ 203,000
$ 1,015,000
$ 203,000
1 ri$ 1, 218, 000 v<
$ 115,000
$ 18, 000
$ 61,200
$ 10. 12
*****#####**MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST
RATE
FUEL COST
2%
5%
97
$1. 25/GAL. ($0. 13/KWH)
$ 38,460
$
29,310
$ 21,465
$1. 68/GAL. ($0. 24/KWH)
$ 51,570
$
39,300
$ 28, 785
$3. 50/GAL. ($0. 50/KWH)
$ 107,430
$
81,870
$ 59,970
NOTES: Plant Factor of 30% used
All figures are to he considered rough estimates
APA S/ 79
A-34
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU,ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - LOWER KALSKAG Double Flow, Year -Round
FLOW (CFS) - 4
HEAD (FT) - 100
PIPELENGTH (FT) - 8000
TRANSMISSION LINE LENGTH (MILES) - 3.5
ROAD LENGTH (MILES) - 3.5
CALCULATED VALUES
PIPESIZE (IN) - 18
HEADLOSS (FT) - 8.22471
PIPE COST ($/FT) - 90
MAXIMUM POWER (KW) - 25
ENERGY at 30% P. F. (kWh) - 65700
CONSTRUCTION COSTS
POWER PLANT - 25 KW X $900/KW =
DIVERSION STRUCTURE _
PIPELINE - 8000 FT X $ 90/FT =
TRANSMISSION LINE - 3.5 MILES X $ 40000/MILE _
ROAD - 3.5 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL 0&M COST
INSTALLED COST PER KILOWATT.
COST PER kWh ( 30% P. F. )
$ 23,000
$ 10,000
$ 720,000
$ 140,000
$ 89,000
3 0
$ 981,000
$ 245,000
$ 1,226,000
$ 245,000
$ 139,000
22,000
{8, 800
y 2.45
###########*MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT***-r#######*
INTEREST
RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($0. 18/KWH)
$ 192,300
$
146,550
$ 107,325
$1. 68/GAL. ($0. 24/KWH)
$ 257,350
$
196,500
$ 143,925
$3.50/GAL. ($0.50/KWH)
$ 537,150
$
409,350
$ 299,850
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 8/79
A-35
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU,ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE — LOWERKALSKAG
FLOW (CFS) — 4
HEAD (FT) — 100
PIPELENGTH (FT) — SO00
TRANSMISSION LINE LENGTH (MILES) — 3.5
ROAD LENGTH (MILES) — 3.5
CALCULATED VALUES
PIPESIZE (IN) — 18
HEADLOSS (FT) - 8.22471
PIPE COST ($/FT) — 90
MAXIMUM POWER (KW).— 25
ENERGY at 30% P.F. (kWh) — 21900
Double Flow, Summer Only
CONSTRUCTION COSTS
POWER PLANT — 25 KW X $900/KW =
DIVERSION STRUCTURE _
PIPELINE — 8000 FT X 'S 90/FT =
TRANSMISSION LINE — 3.5 MILES X $ 40000/MILE _
ROAD — 3.5 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL 0&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P.F.)
$ 23,000
$ 10,000
$ 720,000
$ 140,000
$ 881000
$ 0
#ae#�#atat tit#te#
$ 981, 000
$ 245,000
$ 1,226,000
$ 245,000
:.• 1,471,000 << .
$ 139,000
$ 22,000
$ 58, 800
$ 7.35
####*#******MAXIMUM EXPENDITURES FOR FUEL REPLACEMENT******-******
INTEREST
RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($O. 16/KWH)
$ 64,100 $
46,8510
S 35,775
$1. 68/GAL. ($0. 24/KWH)
$ 65,950 $
65, 500
471,975
$3. 50/GAL. ($0. 50/KWH)
$ 179,050 $
136,450
99,950
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 8/79
A-1h
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU,ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - MEKORYUK
FLOW (CFS) - 10
HEAD (FT) - 100
PIPELENGTH (FT) - 8000
TRANSMISSION LINE LENGTH (MILES) - 8
ROAD LENGTH (MILES) - 6.5
CALCULATED VALUES
PIPESIZE (IN) - 26
HEADLOSS (FT) - 7.73878
PIPE COST ($/FT) - 140
MAXIMUM POWER (KW) - 65
ENERGY at 30% P.F. (kWh) - 170820
Year -Round Operation
CONSTRUCTION COSTS
POWER PLANT - 65 KW X $900/KW =
DIVERSION STRUCTURE =
PIPELINE - S000 FT X $ 140/FT =
TRANSMISSION LINE - 8 MILES X $ 40000/MILE _
ROAD - 6.5 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (2 5%)
FIELD COST
OVERHEAD (RO%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL 0&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. )
$ 59,000
$ 10,000
$ 1, 120,000
$ 320,000
$ 163,000
$ 0
$ 1,672,000
$ 418, 000
$ 2,090,000
$ 418,000
"'$ 2, 508, 000 C<<_
$ 237,000
$ 39,000
$ 38, 600
$ 1. 61
************MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST RATE
FUEL COST
2%
5',:
9%
$1. 25/GAL. ($0. 18/KWH)
$ 499,980
$ 361,030
$ 279,045
$1.68/GAL. ($0.24/KWH)
$ 670,410
$ 510,900
$ 374,205
$3. 50/GAL. ($0. 50/KWH)
$ 1,396,590
$ 1,064,310
$ 779,610
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 8/79
A-37
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU,ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - MEKORYUK
FLOW (CFS) - 10
HEAD (FT) - 100
PIPELENGTH (FT) - 8000
TRANSMISSION LINE LENGTH (MILES)- G
ROAD LENGTH (MILES) - 6.5
CALCULATED VALUES•
PIPESIZE (IN) - 26
HEADLOSS (FT) - 7.73878
PIPE COST ($/FT) - 140
MAXIMUM POWER (KW) - 65
ENERGY at 30% P.F. (kWh) - 56940
Summer Operation Only
CONSTRUCTION COSTS
POWER PLANT - 65 KW X $900/KW =
DIVERSION STRUCTURE _
PIPELINE - 8000 FT X $ 140/FT =
TRANSMISSION LINE - 8 MILES X $ 40000/MILE _
ROAD - 6.5 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F.)
$ 59,000
$ 10,000
$ 1, 120,000
$ 320,000
$ 163,000
$ 0
$ 1,672,000
$ 418, 000
$ 2,0901 000
$ 412,000
>3=`$ 2, 508, 000 C<:
$ 237,000
$ 38,000
$ 38, 600
$ 4. 83
*****######*MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST
RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($O. IS/KWH )
$ 166,660
$
127,010
$ 93,015
$1. 66/GAL. ($0. 24/KWH )
$ 223,470
$
170,300
$ 124,735
$3. 50/GAL. ($0. 50/KWH)
$ 465,530
$
354,770
$ 259, S70
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 2/79
A-38
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - MEKORYUK
FLOW (CFS) - 20
HEAD (FT) - 100
PIPELENGTH (FT) - 8000
TRANSMISSION LINE LENGTH (MILES) - 8
ROAD LENGTH (MILES) - 6.5
CALCULATED VALUES
PIPESIZE (IN) - 34
HEADLOSS (FT) - 7.75804
PIPE COST ($/FT) - 180
MAXIMUM POWER (KW) - 125
ENERGY at 30% P.F. (kWh) - 328500
CONSTRUCTION COSTS
POWER PLANT - 125 KW X $900/KW =
DIVERSION STRUCTURE =
PIPELINE - 8000 FT X $ 180/FT =
TRANSMISSION LINE - 8 MILES X $
ROAD - 6.5 MILES X $ 25000/MILE
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
Double Flow, Year -Round
40000/MILE _
t 113,000
10,000
1, 440, 000
3 320,000
3 163,000
5 0
$ 2,046,000
$ 512,000
mat#��tarat#ar�it�
$ 2455e,000
$ 512,000
»> 3, 070, 000 < <<
ANNUAL COST (20
yrs. at 7%
interest)
$
290,000
ANNUAL O&M COST
$
46,000
INSTALLED COST
PER KILOWATT
$
24,600
COST PER kWh (
30% P.F.)
$
1.02
*###########MAXIMUM
EXPENDITURES
FOR FUEL
REPLACEMENT************
INTEREST RATE
FUEL COST
2%
m7
9'/.
$1. 25/GAL. ($0.
18/KWH)
$ 961,500
$ 732,750
$ 536,625
$1. 68/GAL. ($0.
24/KWH)
$ 1,2B9,250
$ 9824500
$ 719,625
$3. 50/GAL. ($0.
50/KWH)
$ 2,605,750
$ 2,046,750
$ 1,499,250
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 3/79
A-39
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU,ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE — MEKORYUK
FLOW (CFS) — 20
HEAD (FT) — 100
PIPELENGTH (FT) — 8000
TRANSMISSION LINE LENGTH (MILES) — 8
ROAD LENGTH (MILES) — 6.5
CALCULATED VALUES
PIPESIZE (IN) — 34
HEADLOSS (FT) — 7.75804
PIPE COST ($/FT) — 180
MAXIMUM POWER (KW) — 125
ENERGY at 30% P.F. (kWh) — 109500
Double Flow, Summer Only
CONSTRUCTION COSTS
P f71JEP OI �11VT — 1�5 m,�, X w9vvi ��n_
DIVERSION STRUCTURE _
PIPELINE — 6000 FT X $ ISO/FT =
TRANSMISSION LINE — 8 MILES X $ 40000/MILE _
ROAD — 6.5 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P.F.)
m ran nnn
$ y 10,000
$ 1, 440, 000
$ 320,000
$ 163,000
$ 0
$ 2,046,000
$ 512,000
$ 2, 558, 000
$ 512,000
�ttat�-tt-it-�##mat#
$ 3, 070, 000 <
$ 290,000
$ 46, 000
$ 24,600
$ 3.07
************MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST
RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($0. 18/KWH)
$ 320,500
$
244,250
$ 178,875
$1. 68/GAL. ($0. 24/KWH)
$ 429,750
$
327,500
$ 239,975
$3. 50/GAL. ($0. 50/KWH)
$ 895,250
$
682,250
$ 499,750
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 8,'79
A-40
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - NEW STUYAHOK Year -Round Operation
FLOW (CFS) - 18
HEAD (FT) - 50
PIPELENGTH (FT) - 5000
TRANSMISSION LINE LENGTH (MILES) - 2.5
ROAD LENGTH (MILES) - 2.5
CALCULATED VALUES
PIPESIZE (IN) - 34
HEADLOSS (FT) - 3.96911
PIPE COST ($/FT) - 180
MAXIMUM POWER (KW) - 55
ENERGY at 30% P.F. (kWh) - 144540
CONSTRUCTION COSTS
POWER PLANT - 55 KW X $900/KW =
DIVERSION STRUCTURE =
PIPELINE - 5000 FT X $ 180/FT =
TRANSMISSION LINE - 2.5 MILES X
ROAD - 2.5 MILES X $ 25000/MILE
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
$ 40000/MILE _
$ 501000
$ 10,000
$ 900,000
$ 100,000
$ 63,000
$ 0
$ 1,123,000
$ 281,000
$ 1,404,000
$ 2S1, 000
:,"'>$ 1, 685, 000 [<<_
ANNUAL COST (20
yrs. at 7%
interest)
$
159,000
ANNUAL O&M COST
$
25,000
INSTALLED COST
PER KILOWATT
$
30,600
COST PER kWh (
30% P. F. )
$
1.27
############MAXIMUM
EXPENDITURES
FOR FUEL
REPLACEMENT************
INTEREST
RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($0.
18/KWH)
$ 423,060
$
322,410
$ 236,115
$1. 68/GAL. ($0.
24/KWH)
$ 567,270
$
432,300
$ 316,635
$3. 50/GAL. ($0.
50/KWH)
$ 1,161,730
$
900,570
$ 659,670
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 8/79
A-41
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU,ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - NEW STUYAHOK Summer Operation Only
FLOW (CFS) - 18
HEAD (FT) - 50
PIPELENGTH (FT) - 5000
TRANSMISSION LINE LENGTH (MILES) - 2.5
ROAD LENGTH (MILES) - 2.5
CALCULATED VALUES
PIPESIZE (IN) - 34
HEADLOSS (FT) - 3.96911
PIPE COST ($/FT) - 180
MAXIMUM POWER (KW) - 55
ENERGY at 30% P.F. (kWh) - 48180
CONSTRUCTION COSTS
POWER PLANT - 55 KW X $900/KW =
DIVERSION STRUCTURE _
PIPELINE - 5000 FT X $ 180/FT =
TRANSMISSION LINE - 2.5 MILES X
ROAD - 2.5 MILES X $ 25000/MILE
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
$ 40000/MILE _
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P.F.)
$ 50,000
$ 10,000
$ 900,000
$ 100,000
$ 63,000
$ 0
�#�tttfat�#�#ttat
$ 11123,000
$ 281,000
-JE#ar it# it #-lEit #iF7t
$ 1,404,000
$ 231,000
> 1, 635, 000 C:
159,000
25,000
$ 30,600
$ 3.32
############MAXIMUM EXPENDITURES FOR FUEL REPLACEMENT************
INTEREST
RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($0. 18/KWH)
$ 141,020 $
107,470
$ 78,705
$1. 68/GAL. ($0. 24/KWH)
$ 189,090 $
144,100
$ 105,545
$3. 50/ GAL. ( $0. 50/KWH )
$ 393,910 $
300,190
$ 219,890
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 3/79
A-42
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - NEW STUYAHOK Double Flow, Year -Round
FLOW (CFS) - 36
HEAD (FT) - 50
PIPELENGTH (FT) - 5000
TRANSMISSION LINE LENGTH (MILES) - 2.5
ROAD LENGTH (MILES) - 2.5
CALCULATED VALUES
PIPESIZE (IN) - 44
HEADLOSS (FT) - 4.18773
PIPE COST ($/FT) - 230
MAXIMUM POWER (KW) - 110
ENERGY at 30% P.F. (kWh) - 289080
CONSTRUCTION COSTS
POWER PLANT - 110 KW X $900/KW =
DIVERSION STRUCTURE _
PIPELINE - 5000 FT X $ 230/FT =
TRANSMISSION LINE - 2.5 MILES X $ 40000/MILE _
ROAD - 2.5 MILES X $ 25000/MILE
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. )
$ 99,000
$ 10,000
$ 11 150,000
$ 1001000
$ 63,000
$ 1,422,000
$ 356,000
�-tt#�t-gat#jtar-�r�t at
$ 1,77e,000
$ 356,000
2, 134, 000 <<<
201,000
32,000
$ 19,400
$ . 81
####r#######MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST RATE
FUEL COST
2%
5%
17%
$1. 25/GAL. ($O. 18/KWH)
$ 946,120
$ 644,820
$ 472,230
$1. 68/GAL. ($0. 24/KWH)
$ 1,134,540
$ 864, 600
$ 633,270
$3. 50/GAL. ($0. 50/KWH)
$ 2,363,460
$ 1, 801, 140
$ 1, 319, 340
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 8/79
A-43
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU,ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - NEW STUYAHOK Double Flow, Summer Only
FLOW (CFS) - 36
HEAD (FT) - 50
PIPELENGTH (FT) - 5000
TRANSMISSION LINE LENGTH (MILES) - 2.5
ROAD LENGTH (MILES) - 2.5
CALCULATED VALUES
PIPESIZE (IN) - 44
HEADLOSS (FT) - 4,18773
PIPE COST ($/FT) - 230
MAXIMUM POWER (KW) - 110
ENERGY at 30% P.F. (kWh) - 96360
CONSTRUCTION COSTS
POWER PLANT - 110 KW X $900/KW =
DIVERSION STRUCTURE =
PIPELINE - 5000 FT X $ 230/FT =
TRANSMISSION LINE - 2.5 MILES X $ 40000/MILE
ROAD - 2.5 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. )
$ 99, 000
$ 10,000
$ 11150,000
$ 100,000
$ 63,000
$ 0
$ 1,422,000
$ 356,000
$ 1,77e,000
$ 356,000
i\>>$ 21134, 000 {{
$ 201, 000
$ 32,000
$ 19, 400
$ 2.42
######******MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST
RATE
FUEL COST
2%
5%
97
$1. 25/GAL. ($O. 18/KWH)
$ 282,040
$
214,940
$ 157,410
$1. 68/GAL. ($0. 24/KWH)
$ 378, 180
$
29S, 200
$ 211,090
$3. 50/GAL. ($0. 50/KWH)l
$ 787,320
$
600, 380
$ 439, 780
NOTES: Plant Factor of= 30% used
All figures are to be considered rough estimates
APA 8/79
A-44
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - SHUNGNAK
FLOW (CFS) - 100
HEAD (FT) - 200
PIPELENGTH (FT) - 7000
TRANSMISSION LINE LENGTH (MILES) - 9
ROAD LENGTH (MILES) - 0
CALCULATED VALUES
PIPESIZE (IN) - 52
HEADLOSS (FT) - 18.015
PIPE COST ($/FT) - 270
MAXIMUM POWER (KW) - 1235
ENERGY at 30% P.F. (kWh) - 3.24558E6
Year -Round Operation
CONSTRUCTION COSTS
POWER PLANT - 1235 KW X $900/KW
DIVERSION STRUCTURE =
PIPELINE - 7000 FT X $ 270/FT =
TRANSMISSION LINE - 9 MILES X $ 40000/MILE _
ROAD - O MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD .(20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P.F.)
$ 1,112,000
$ 10,000
$ 11390,000
$ 360,000
$ 0
$ 3,372,000
$ 843,000
$ 4,215,000
$ 843, 000
�#at#arat#-tt-��arat
>» 5, 058, 000 «<
$ 477,000
$ 7c, 000
$ 4,100
$ . 17
************MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST RATE
FUEL COST
2/.
5%
9%
$1. 25/GAL. ($0. 18/KWH)
$ 9,499,620
$ 7,239,570
$ 5,301,655
$1. 68/GAL. ($0. 24/KWH)
$12, 737, 790
$ 9,707,100
$ 7,109,S95
$3. 50/GAL. ($0. 50/KWH)
$26, 535, 210
$20, 221, 890
$14, 812, 590
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 8/79
A-45
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU.ALASKA
ESTIMATED HYDRO COSTS
�# ����#aratarar ararar arataratar ararataratarararararararararatar arararatararararatar #��;tar#� ataratarararatar �###� atarat at orator
PLANT SITE — SHUNGNAK
FLOW (CFS) — 100
HEAD (FT) — 200
PIPELENGTH (FT) — 7000
TRANSMISSION LINE LENGTH (MILES) — 9
ROAD LENGTH (MILES) — 0
CALCULATED VALUES
Summer Operation Only
PIPESIZE (IN) — 52
HEADLOSS (FT) — 18.015
PIPE COST ($/FT) — 270
MAXIMUM POWER (KW) — 1235
ENERGY at 30% P. F. (kWh) — 1. 08186E6
CONSTRUCTION COSTS
POWER PLANT — 1235 KW X $900/KW =
DIVERSION STRUCTURE _
PIPELINE — 7000 FT X $ 270/FT =
TRANSMISSION LINE — 9 MILES X $ 40000/MILE _
ROAD — O MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
$ 1,112.000
$ 10,000
$ 11890,000
$ 360,000
$ 0
$ 0
atarararararat aratatarat
$ 3,372,000
$ 843,000
#afar#ar atattrat-ttatar
$ 4,215,000
$ 843,000
arar atatataratatatat arat
>$ 5,058,000 t«
ANNUAL COST (20 yrs. at 7%
interest)
$
477,000
ANNUAL O&M COST
$
76,000
INSTALLED COST PER KILOWATT
$
4,100
COST PER kWh ( 30% P.F.)
$
.51
arararar#ataratat***MAXIMUM EXPENDITURES
FOR FUEL
REPLACEMENTaHraratatatatarar***
INTEREST RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($0. 18/KWH)
$ 3,166,540
$ 2,413,190
$ 1,767,285
$1. 68/GAL. ($0. 24/KWH)
$ 4,245,930
$ 3,235,700
$ 2,369,965
$3. 50/GAL. ($0. 50/KWH)
$ 9,845,070
$ 6,740,630
$ 4,937,530
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 8/79
A-46
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU,ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - SHUNGNAK
FLOW (CFS) - 200
HEAD (FT) - 200
PIPELENGTH (FT) - 7000
TRANSMISSION LINE LENGTH (MILES) - 9
ROAD LENGTH (MILES) - 0
CALCULATED VALUES
PIPESIZE (IN) - 68
Double Flow, Year -Round
HEADLOSS (FT) - 18.0598
PIPE COST ($/FT) - 360
MAXIMUM POWER (KW) - 2470
ENERGY at 30% P. F. (kWh) - 6. 49116E6
CONSTRUCTION COSTS
POWER PLANT - 2470 KW X $900/KW =
DIVERSION STRUCTURE _
PIPELINE - 7000 FT X $ 360/FT =
TRANSMISSION LINE - 9 MILES X $ 40000/MILE _
ROAD - O MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. )
$ 2,223.000
$ 10,000
$ 2,520,000
$ 360,000
$ 0
$ O
$ 5,113,000
$ 1,278,000
L 6, 391, 000
$ 1,278,000
at��#-x�Hr-eatar�ar
>3>.$ 7,669,000 <<<
$ 724,000
$ 115, 000
$ 31100
$ . 13
*afar******slat*MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($O. 18/KWH)
$18, 999, 240
$14, 479, 140
$10, 603, 710
$1. 68/GAL. ($0. 24/KWH)
$25, 475, 580
$19, 414, 200
$14, 219, 790
$3. 50/GAL. ($0. 50/KWH)
$53, 070, 420
$40, 443, 780
$29, 625, 180
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 8/79
A-47
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU,ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - SHUNGNAK
FLOW (CFS) - 200
HEAD (FT) - 200
PIPELENGTH (FT) - '7000
TRANSMISSION LINE LENGTH (MILES) - 9
ROAD LENGTH (MILES) - 0
CALCULATED VALUES
PIPESIZE (IN) - 68
HEADLOSS (FT) - 18.0598
PIPE COST ($/FT) - 360
MAXIMUM POWER (KW) - 2470
ENERGY at 30% P. F. (kWh) - 2. 16372E6
CONSTRUCTION COSTS
POWER PLANT - 2470
DIVERSION STRUCTURE
PIPELINE 7000 FT
TRANSMISSION LINE -
ROAD - 0 MILES X $
MISCELLANEOUS COSTS
Double Flow, Summer Only
KW X $900/KW =
X $ 36O/FT.=
9 MILES X $ 40000/MILE _
25000/MILE _
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 77 interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P.F.)
$ 2,223,000
$ 10,000
$ 2,520,000
$ 360,000
$ 0
$ O
#tt#etitiFargttr�t �t#
$ 5,113,000
$ 1,278,000
ear�rat##�t�at��#
$ 6. 391, 000
$ 1,27B4O00
#�atararatir�-�at�tat
>>>$ 7,669,000 f<{
$ 724,000
$ 115,000
$ 3,100
$ .39
************MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT****#ix-4ir****
INTEREST RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($O. 18/KWH)
$ 6, 333, 080
$ 4,826,380
$ 3,534)570
$1. 68/GAL. ($O. 24/KWH)
$ 8,491,860
$ 6,471,400
$ 4,739,930
$3. 50/GAL. ($0. 50/KWH)
$17, 690, 140
$13, 481, 260
$ 9,875,060
NOTES
Plant Factor of 30% used
All figures.are.to be considered rough estimates
A-48.
'APA 8/79
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
##################################################################}tat####
PLANT SITE - TANUNAK Year -Round Operation
FLOW (CFS) - 2
HEAD (FT) - 500
PIPELENGTH (FT) - 6000
TRANSMISSION LINE LENGTH (MILES) - 3.5
ROAD LENGTH (MILES) - 3.5
CALCULATED VALUES
PIPESIZE (IN) - 10
HEADLOSS (FT) - 29.4463
PIPE COST ($/FT) - 50
MAXIMUM POWER (KW) - 65
ENERGY at 30% P.F. (kWh) - 170820
CONSTRUCTION COSTS
POWER PLANT - 65 KW X $900/KW =
DIVERSION STRUCTURE =
PIPELINE 6000 FT X $ 50/FT
TRANSMISSION LINE - 3.5 MILES X $ 40000/MILE _
ROAD - 3.5 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. )
$
59,000
$
10,000
$
300,000
$
140,000
$
SS, 000
$
Q
############
$
597,000
$
149,000
############
$
746,000
$
149,000
############
»>$
S95, 000 <<<
$ 84,000
$ 13.000
$ 13, Goo
$ . 57
############MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST RATE
FUEL COST
2%
5%
9%
$1.25/GAL. ($0.18/KWH)
$ 499,980
$ 381,030
$ 279,045
$1. 68/GAL. ($0. 24/KWH)
$ 670,410
$ 510,900
$ 374,205
$3. 50/GAL. ($O. 50/KWH)
$ 1,396,590
$ 1,064,310
$ 779,610
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 8/79
A-49
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU,ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE — TANUNAK Summer Operation Only
FLOW (CFS) — 2
HEAD (FT) — 500
PIPELENGTH (FT) — 6000
TRANSMISSION LINE LENGTH (MILES) — 3.5
ROAD LENGTH (MILES) — 3.5
CALCULATED VALUES
PIPESIZE (IN) — 10
HEADLOSS (FT) — 29.4483
PIPE COST ($/FT) — 50
MAXIMUM POWER (KW) — 65
ENERGY at 30% P.F. (kWh) — 56940
CONSTRUCTION COSTS
POWER PLANT — 65 KW X $900/KW =
DIVERSION STRUCTURE =
PIPELINE — 6000 FT X $ 50/FT =
TRANSMISSION LINE — 3.5 MILES X
ROAD — 3.5 MILES X $ 25000/MILE
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
$ 40000/MILE _
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL 0&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. )
$ 59,000
$
10,000
$
300,000
$
140,000
$
88, 000
$
O
############
$
597,000
$
149,000
############
$
746,000
$
149,000
895,000 €<<
$ 84,000
$ 13,000
$ 13,800
$ 1.70
############MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST
RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($0. 18/KWH)
$ 166,660
$
127,010
$ 93,015
$1. 68/GAL. ($O. 24/KWH)
$ 223,470
$
170,300
$ 124,735
$3. 50/GAL. ($O. 50/KWH)
$ 465,530
$
354,770
$ 259,870
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 2/79
A-50
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE — TANUNAK Double Flow, Year —Round
FLOW (CFS) — 4
HEAD (FT) — 500
PIPELENGTH (FT) — 6000
TRANSMISSION LINE LENGTH (MILES) — 3.5
ROAD LENGTH (MILES) — 3.5
CALCULATED VALUES
PIPESIZE (IN) — 12
HEADLOSS (FT) — 44.981
PIPE COST ($/FT) — 60
MAXIMUM POWER (KW) — 125
ENERGY at 30% P.F. (kWh) — 328500
CONSTRUCTION COSTS
POWER PLANT — 125 KW X $900/KW =
DIVERSION STRUCTURE
PIPELINE — 6000 FT X $ 60/FT =
TRANSMISSION LINE — 3.5 MILES X
ROAD — 3.5 MILES X $ 25000/MILE
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
$ 40000/MILE _
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. )
$ 113,000
$ 10,000
$ 360,000
$ 140,000
$ 881000
$ 0
arararararararar�#arar
$ 711,000
$ 173,000
at-tat-tt at#-ttatat�#at
$ 889.000
$ 178,000
ararar �ar�at-tter�t#at
»7$ 1,067,000 <<<
$ 101,000
$ 16,000
$ (3,500
$ .36
arararararaHrata ***MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($0. 18/KWH)
$ 961,500
$ 732,750
$ 536,625
$1. 68/GAL_ ($0. 24/KWH)
$ 1,2a9,250
$ 982, 500
$ 719,625
$3. 50/GAL. ($0. 50/KWH)
$ 2,685,750
$ 2,046,750
$ 1,499.250
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 8/79
A-51
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
��#atatatetetatatitetar��t#+r�ret#at�er�#�#�ar���3tatitit#�t��ar�tar#�t3tat##at#�-tt�at#stet#afar##±rat�+t ��at�#
PLANT SITE — TANUNAK Double Flow, Summer Only
FLOW (CFS) — 4
HEAD (FT) — 500
PIPELENGTH (FT) — 6000
TRANSMISSION LINE LENGTH (MILES) — 3.5
ROAD LENGTH (MILES) — 3.5
CALCULATED VALUES
PIPESIZE (IN) — 12
HEADLOSS (FT) — 44.981
PIPE COST ($/FT) — 60
MAXIMUM POWER (KW) — 125
ENERGY at 30% P.F. (kWh) — 109500
CONSTRUCTION COSTS
POWER PLANT — 125 KW X $900/KW =
DIVERSION STRUCTURE
PIPELINE — 6000 FT X $ 60/FT =
TRANSMISSION LINE — 3.5 MILES X $ 40000/MILE
ROAD — 3.5 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. )
$ 113,000
$ 10,000
$ 360,000
$ 140,000
$ 881000
$ 0
aratatatat ararataratarat
$ 711,000
$ 175, 000
tt-uatatateratataratatar
$ 889,000
$ 179,000
aratar ataratarataratatat
»>$ 1,067,000 <<<
$ 101,000
$ 16,000
$ 8,500
$ 1.07
tratatatatatataHr***MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENTatar'.tatatatat****at
INTEREST
RATE
FUEL COST
2%
5%
9%
$1. 25/GAL- ($O. 18/KWH)
$ 320,500
$
244,250
$ 178,875
$1. 68/GAL. ($0. 24/KWH)
$ 429,750
$
327,500
$ 239,875
$3. 50/GAL. ($0. 50/KWH)
$ 895,250
$
682,250
$ 499, 750
NOTES
Plant Factor of 30% used
All fLjure,%.are to be considered rough estimates
RPA 8/79
A-52
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU,ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - TOKSOOK BAY Year -Round Operation
FLOW (CFS) - 2
HEAD (FT) - 500
PIPELENGTH (FT) - 6000
TRANSMISSION LINE LENGTH (MILES) - 4.5
ROAD LENGTH (MILES) - 4.5
CALCULATED VALUES
PIPESIZE (IN) - 10
HEADLOSS (FT) - 29.4483
PIPE COST ($/FT) - 50
MAXIMUM POWER (KW) - 65
ENERGY at 30% P.F. (kWh) - 170820
CONSTRUCTION COSTS
POWER PLANT - 65 KW X $900/KW =
DIVERSION STRUCTURE _
PIPELINE - 6000 FT X $ 50/FT =
TRANSMISSION LINE - 4.5 MILES X $ 40000/MILE _
ROAD - 4.5 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7/. interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. )
$
59.000
$
10,000
$
300,000
$
180,000
$
113,000
$
0
3
662,000
$
166,000
************
$
828,000
$
166,000
�tiHr-xxer�it��at tt-
?»$
994,000 «<
$ 944000
$ 15,000
$ 15,200
$ .64
************MAXIMUM EXPENDITURES FOR FUEL REPLACEMENT************
INTEREST RATE
FUEL COST 2% 5% 9%
$1. 25/GAL. ($O. 18/KWH) $ 499, 980 $ 381,030 $ 279, 045
$1. 68/GAL. ($O. 24/KWH) $ 670,410 $ 510,900 $ 374,205
$3. 50/GAL. ($0. 50/KWH) $ 1,396,590 $ 1,064,310 $ 779,610
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
ryyaUEL=y&Aa
A-53
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU,ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - TOKSOOK BAY Summer Operation Only
FLOW (CFS) - 2
HEAD (FT) - 500
PIPELENGTH (FT) - 6000
TRANSMISSION LINE LENGTH (MILES) - 4.5
ROAD LENGTH (MILES) - 4.5
CALCULATED VALUES
PIPESIZE (IN) 10
HEADLOSS (FT) - 29.4483
PIPE COST ($/FT) - 50
MAXIMUM POWER (KW) - 65
ENERGY at 30% P.F. (kWh) - 56940
CONSTRUCTION COSTS
POWER PLANT - 65 KW X $900/KW =
DIVERSION STRUCTURE =
PIPELINE - 6000 FT X $ 50/FT =
TRANSMISSION LINE - 4.5 MILES X $ 40000/MILE _
ROAD - 4.5 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P.F.)
$
59,000
$
10,000
$
300,000
$
180,000
$
113,000
$
0
$
662,000
$
166,000
at�at-�r#3t3r�-ar3raret
$
828, 000
$
166,000
************
iJJ$
994,000 <<<
$ 94, 000
$ 15,000
$ 15,300
$ 1.91
************MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST
RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($O. 18/KWH)
$ 166,660
$
127,010
$ 93,015
$1. 68/GAL. ($O. 24/KWH)
$ 223,470
$
170,300
$ 124,735
$3. 50/GAL. ($0. 50/KWH)
$ 465,530
$
354,770
$ 259, S70
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 9/79
A-54
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - TOKSOOK SAY Double Flow, Year -Round
FLOW (CFS) - 4
HEAD (FT) - 500
PIPELENGTH (FT) - 6000
TRANSMISSION LINE LENGTH (MILES) - 4.5
ROAD LENGTH (MILES) - 4.5
CALCULATED VALUES
PIPESIZE (IN) - 12
HEADLOSS (FT) - 4.4.991
PIPE COST ($/FT) - 60
MAXIMUM POWER (KW) - 125
ENERGY at 30% P. F. (kWh) - 328500
CONSTRUCTION COSTS
POWER PLANT.- 125 KW X $900/KW =
$
113,000
DIVERSION STRUCTURE _
$
10,000
PIPELINE - 6000 FT X $ 60/FT =
$
360,000
TRANSMISSION LINE - 4.5 MILES X $ 400001MILE _ $
180,000
ROAD - 4.5 MILES X $ 25000/MILE _
$
113,000
MISCELLANEOUS COSTS =
$
0
eatateatatat eatateat
SASE COST
$
776,000
CONTINGENCIES (25%)
$
194,000
eeateeatatatateee
FIELD COST
$
970, 000
OVERHEAD (20%)
$
194,000
eateateeeateeatat
CONSTRUCTION COST
>>>$
1,164,000 <<<
ANNUAL COST (20 yrs. at 71A interest)
$
110,000
ANNUAL 0&M COST
$
17,000
INSTALLED COST PER KILOWATT
$
9.300
COST PER kWh ( 30% P. F. )
$
. 39
************MAXIMUM EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST RATE
FUEL COST 2%
5%
9%
$1. 25/GAL. ($O. 1S/KWH) $ 961,500
$ 732,750
$ 536,625
$1. 68/GAL. ($0. 24/KWH) $ 1,2B9,250
$ 982,500
$ 719,625
$3. 50/GAL. ($0. 50/KWH) $ 2,685,750
$ 2,046,750
$ 1,499,250
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 2/79
A-55
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU,ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE — TOKSOOK BAY Double Flow, Summer Only
FLOW (CFS) — 4
HEAD (FT) — 500
PIPELENGTH (FT) — 6000
TRANSMISSION LINE LENGTH (MILES) — 4.5
ROAD LENGTH (MILES) — 4.5
CALCULATED VALUES
PIPESIZE (IN) — 12
HEADLOSS (FT) — 44.981
PIPE COST ($/FT) — 60
MAXIMUM POWER CKW) — 125
ENERGY at 307. P. F. (kWh) — 109500
CONSTRUCTION COSTS
POWER PLANT — 125 KW X $900/KW
$
113,000
DIVERSION STRUCTURE =
$
10,000
PIPELINE — 6000 FT X $ 60/FT =
$
360,000
TRANSMISSION LINE — 4.5 MILES X $ 40000/MILE _
$
180,000
ROAD — 4.5 MILES X $ 25000/MILE _
$
113,000
MISCELLANEOUS COSTS =
$
0
atata*atata*a* ata*ata*a*
BASE COST
$
776,000
CONTINGENCIES (25%)
$
194,000
��at�-�tatataf u-�tatat
FIELD COST
$
970,000
OVERHEAD (20%)
$
194,000
CONSTRUCTION COST
»>$
1,164,000 <<<
ANNUAL COST (20 yrs. at 7% interest)
$
110,000
ANNUAL O&M COST
$
17,000
INSTALLED COST PER KILOWATT
$
9,300
COST PER kWh ( 3("6 P. F. )
$
1.16
************MAXIMUM EXPENDITURES FOR FUEL REPLACEMENT-************
INTEREST
RATE
FUEL COST 2%
5%
9%
$1. 25/GAL. ($0. 18/KWH) $ 320,500 $
244,250
$ 178,875
$1. 68/GAL. ($O. 24/KWH) $ 429,750 $
327,500
$ 239,875
$3. 50/GAL. ($0. 50/KWH) $ 895, 250 $
602,250
$ 499,750
NOTES
Plant Factor of 30% used
All figures are to be considered rough estimates
APA S./79
A-Sf,
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
#�#�aEat���#��etjr�#atjt###earett��e�it+t+r#ate-ttar�eatatatarit�te e#aEattt�ee�#e��e��teat�eite��-�
PLANT SITE - WALES
FLOW (CFS) - 2
HEAD (FT) - 200
PIPELENGTH (FT) - 4000
TRANSMISSION LINE LENGTH (MILES) - 1
ROAD LENGTH (MILES) - 1
CALCULATED VALUES
PIPESIZE (IN) - 10
HEADLOSS (FT) - 19.6322
PIPE COST ($/FT) - 50
MAXIMUM POWER (KW) - 25
ENERGY at 307. P. F. (kWh) - 65700
Year -Round Operation
CONSTRUCTION COSTS
POWER PLANT - 25 KW X $900/KW =
DIVERSION STRUCTURE _
PIPELINE - 4000 FT X $ 50/FT =
TRANSMISSION LINE - 1 MILES X ,$ 40000/MILE _
ROAD - 1 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7/ interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P.F.)
$
23,000
$
10.000
$
$
200,000
40,000
$
25,000
$ 0
$ 298, 000
75,000
#atat��r#�t�-x-xaa�t
$ 373,000
$
75,000
#u-�tatat�arataratet*
>$ 448, 000 <<<
$ 42,000
$ 7,000
$ 17,900
$ .75
###ee##*##*#MAXIMUM EXPENDITURES FOR FUEL REPLACEMENT************
INTEREST
RATE
FUEL COST
2'/.
5%
9%
$1.25/GAL. ($0.18/KWH)
$ 192,300 $
146,550
$ 107,325
$1. 66/GAL. ($O. 24/KWH)
$ 257,850 $
196,500
$ 143,925
$3. 50/GAL. ($O. 50/KWH)
$ 537,150 $
409,350
$ 299,950
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 8/79
A-57
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
���t-ate ��e eeat ��tatar a� eatat#� u# a*it�t-xat#atititete a ���ar# �araratit# �# e�titatatat�-ttar�� tr #at # �et�# # # #
PLANT SITE — WALES
FLOW (CFS) — 2
HEAD (FT) — 200
PIPELENGTH (FT) — 4000
TRANSMISSION LINE LENGTH (MILES) — 1
ROAD LENGTH (MILES) — 1
CALCULATED VALUES
PIPESIZE (IN) — 10
HEADLOSS (FT) — 19.6322
PIPE COST ($/FT) — 50
MAXIMUM POWER (KW) — 25
ENERGY at 30% P. F. (kWh) — 21900
Summer Operation Only
CONSTRUCTION COSTS
POWER PLANT — 25 KW X $900/KW =
DIVERSION STRUCTURE _
PIPELINE — 4000 FT X $ 50/FT =
TRANSMISSION LINE — 1 MILES X $ 40000/MILE _
ROAD — 1 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. )
$
23,000
$
10,000
200,000
$
40,000
$
25,000
$
0
atataraearattt-at��tat3t
$
298,000
$
75,000
#�it�tarjtat�e�arat#
$
373,000
$
75,000
>>>$
448,000 «<
$ 42,000
$ 7,000
$ 17,900
$ 2.24
*****#***##*MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST
RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($O. 18/KWH)
$ 64,100
$
48, S50 $
35,775
$1. 68/GAL. ($0. 24/KWH)
$ 35,950
$
65,500 $
47,975
$3. 50/GAL. ($O. 50/KWH)
$ 179, O50
$
136,450 $
99,950
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 8/79
A-58
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAV,ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - WALES
FLOW (CFS) - 4
HEAD (FT) - 200
PIPELENGTH (FT) - 4000
TRANSMISSION LINE LENGTH (MILES)
ROAD LENGTH (MILES) - 1
CALCULATED VALUES
PIPESIZE (IN) - 14
HEADLOSS (FT) - 14.0896
PIPE COST ($/FT) - 70
MAXIMUM POWER (KW) - 50
ENERGY at 30% P.F. (kWh) - 131400
Double Flow, Year -Round
CONSTRUCTION COSTS
POWER PLANT - 50 KW X $900/KW =
DIVERSION STRUCTURE
PIPELINE - 4000 FT X $ 70/FT =
TRANSMISSION LINE - 1 MILES X $ 40000/MILE _
ROAD - 1 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. )
$
45,000
$
10,000
$
280, 000
$
40,000
$
25,000
$
0
��tatatatat� tt#irat#
$
400,000
$
100,000
at�tatatat�it�tt��at
$
500,000
$
100,000
77>$
600,000 C«
$ 57,000
$ 91000
$ 12,000
$ . 50
###*##******MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST
RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($0. 18/KWH)
$ 354, 600
$
293,100
$ 214,650
$1. 68/GAL. ($O. 24/KWH)
$ 515,700
$
393,000
$ 287,850
$3. 50/GAL. ($0. 50/KWH)
$ 1, 074, 300
$
818,700
$ 599,700
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 6/79
A-59
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
�itat�-s-x�atetit���##etar�r�at#�at�atat��t�tat� at#���it�itat���tatatat�at�����t*atatet# e���t��at�at�r#at##
PLANT SITE — WALES
FLOW (CFS) — 4
HEAD (FT) — 200
PIPELENGTH ('FT) — 4000
TRANSMISSION LINE LENGTH (MILES) — 1
ROAD LENGTH (MILES) — 1
CALCULATED VALUES
PIPESIZE (IN) — 14
HEADLOSS (FT) — 14.0896
PIPE COST ($/FT) — 70
MAXIMUM POWER (KW) — 50
ENERGY at 30% P.F. (kWh) — 43800
Double Flow, Summer Only
CONSTRUCTION COSTS
POWER PLANT — 50 KW X $900/KW =
DIVERSION STRUCTURE
PIPELINE — 4000 FT X $ 70/FT =
TRANSMISSION LINE — 1 MILES X $ 40000/MILE _
ROAD — 1 MILES X $ 25000/MILE
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (251A)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P.F.)
$
$
45,000
10,000
$
280, 000
$
$
40,000
25,000
$
0
�itner�rataratat��rat
$ 400,000
$
100,000
$ 500,000
$
100,000
»> 600,000 «<
$ 57,000
91000
$ 12,000
$ 1.51
************MAXIMUM EXPENDITURES FOR FUEL REPLACEMENT************
INTEREST
RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($O. 18/KWH)
$ 128,200 $
97,700
$ 71,550
$1. 68/GAL. ($0. 24/KWH)
$ 171,900 $
131,000
$ 95,950
$3. 50/GAL. ($0. 50/KWH)
$ 358,100 $
272,900
$ 1991900
NOTES: Plant Factor of 30% used
All figures —are t-u be- considered
rough estimates
APA 8/79
A-60
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU,ALASKA
ESTIMATED HYDRO COSTS
�# # � �atatatat # atatatatat �## � atatat atatatatatatatatatatatatatat atatatat#atatatat atatatat atatatatat � �ar�r��-at-tt#3tat3tat wit #-ttat
PLANT SITE - SCAMMON BAY
FLOW (CFS) - 9
HEAD (FT) - 300
PIPELENGTH (FT) - 2300
TRANSMISSION LINE LENGTH (MILES) - .375
ROAD LENGTH (MILES) - 0
CALCULATED VALUES
PIPESIZE (IN) - 16
HEADLOSS (FT) - 19.6586
PIPE COST ($/FT) - 80
MAXIMUM POWER (KW) - 170
ENERGY at 50% P. F. (kWh) - 744600
CONSTRUCTION COSTS
POWER PLANT - 170 KW X $900/KW =
DIVERSION STRUCTURE
PIPELINE - 2300 FT X $ SO/FT =
TRANSMISSION LINE - .375 MILES X $ 40000/MILE _
ROAD - O MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7/. interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 50% P. F. )
$
153,000
$
10,000
$
184,000
$
15,000
$
0
$
0
$
362,000
$
91,000
atatatatatatatatat#+tat
$
453,000
$
91,000
at at,t at at# # # atat at at
>>>$
544,000 <<<
$ 51,000
$ 81000
$ 3,200
$ .08
atatatatatatatata***MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENTatatatatatatatatat***
INTEREST RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($O. 16/KWH)
$ 2,179,400
$ 1,660,900
$ 1,216,350
$1. 68/GAL. ($0. 24/KWH)
$ 2,922,300
$ 2,227,000
$ 1,631,150
$3. 50/GAL. ($0. 50/KWH)
$ 6,087,700
$ 4,639,300
$ 3,39S,300
NOTES: Year -Round Plan of Operation
Plant Factor of 50% used
All figures -are to -be considered rough estimates
:..+ APA 8/79
A-61
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU,ALASKA
PLANT SITE - SCAMMON BAY
FLOW (CFS) - 9
HEAD (FT) - 500
PIPELENGTH (FT) - 4200
TRANSMISSION LINE LENGTH
ROAD LENGTH (MILES) - 0
CALCULATED VALUES
ESTIMATED HYDRO COSTS
(Higher Head)
(MILES) - .375
PIPESIZE (IN) - 16
HEADLOSS (FT) - 35.8983
PIPE COST ($/FT) - 80
MAXIMUM POWER (KW) - 2S5
ENERGY at 50% P.F. (kWh) - 1.2483E6
CONSTRUCTION COSTS
POWER PLANT - 265 KW X $900/KW =
DIVERSION STRUCTURE _
PIPELINE - 4200 FT X $ SO/FT =
TRANSMISSION LINE - .375 MILES X $ 40000/MILE _
ROAD - O MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 50% P.F.)
$
257,000
$
10,000
$
336,000
$
15,000
$
$
0
0
at#it#�at�#��tatit
$ 618, 000
$
155.000
$ 773,000
$
155,000
#atatatat3t3tit��#at
3??$ 928,000 <<<
$ 881000
$ 14,000
$ 3,300
$ .08
##**#****###MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT##*#####*###.
INTEREST RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ( $0. 16/KWH)
$ 3,653,700
$ 2,784,450
$ 2,039,175
$1. 66/GAL. ($O. 24/KWH)
$ 4,899,150
$ 3,733,500
$ 2,734,575
$3. 50/GAL. ($0. 50/KWH)
$10, 205, 850
$ 7,777,650
$ 5,697,150
NOTES: Year -Round Plan of Operation
Plant Factor of 50% used
All figures are to be considered
rough estimates
APA 8/79
A-62
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - TOGIAK
FLOW (CFS) - 10
HEAD (FT) - 50
PIPELENGTH (FT) - 3500
TRANSMISSION LINE LENGTH (MILES) - 4
ROAD LENGTH (MILES) - 0
CALCULATED -VALUES
PIPESIZE (IN) - 26
HEADLOSS (FT) - 3.38572
PIPE COST ($/FT) - 140
MAXIMUM POWER (KW) - 30
ENERGY at 30% P.F. (kWh) - 78840
Year -Round Operation
CONSTRUCTION COSTS
POWER PLANT - 30 KW X $900/KW =
DIVERSION STRUCTURE _
PIPELINE - 3500 FT X $ 140/FT =
TRANSMISSION LINE - 4 MILES X $ 40000/MILE _
ROAD - 0 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL 0&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. )
$ 27,000
$ 10,000
$ 490,000
$ 160,000
$ 0
$ O
############
$ 687,000
$ 172,000
$ 859,000
$ 172,000
1,031,000 <<<
$ 97,000
$ 15,000
$ 34,400
$ 1.42
############MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST
RATE
FUEL COST
2%
5%
9%
$1. 25/GAL. ($0. 18/KWH)
$ 230,760
$
175,860
$ 128,790
$1. 68/GAL. ($O. 24/KWH)
$ 309,420
$
235, 80O
$ 172,710
$3. 50/GAL ($O. 50/KWH)
$ 644,580
$
491,220
$ 359,820
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
GLZffl1Ti1d
A-63
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
PLANT SITE - TOGIAK
FLOW (CFS) - 10
HEAD (FT) - 50
PIPELENGTH (FT) - 3500
TRANSMISSION LINE LENGTH (MILES) - 4
ROAD LENGTH (MILES) - 0
CALCULATED VALUES
PIPESIZE (IN) - 26
HEADLOSS (FT) - 3.38572
PIPE COST ($/FT) - 140
MAXIMUM POWER (KW) - 30
ENERGY at 30% P. F. (kWh) - 26280
CONSTRUCTION COSTS
POWER PLANT - 30 KW X $900/KW =
DIVERSION STRUCTURE =
PIPELINE - 3500 FT X $ 140/FT =
TRANSMISSION LINE - 4 MILES X $ 40000/MILE
ROAD - 0 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. )
Summer Operation Only
$ 27,000
$ 10,000
$ 490,000
$ 160,000
$ 0
$ 0
�*�ir�r+tetiratiHt�
$ 687,000
$ 172,000
at#*�tatar#-ttar»ar
$ 859,000
$ 172,000
e��eat�at�jt�-sue
$ 97,000
$ 15,000
$ 34,400
$ 4.26
############MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT************
INTEREST
RATE
FUEL COST
27.
5%
9%
$1. 25/GAL. ($O. 18/KWH)
$ 76,920
$
58,620
$ 42,930
$1. 68/GAL. ($0. 24/KWH)
$ 103,140
$
78,600
$ 57,570
$3. 50/GAL. ($0. 50/KWH)
$ 214,860
$
163,740
$ 119,940
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 8/79
A-64
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
###�#####aratatararatatat��#�#arat##arat###########aratarat## #�ararat#atat #afar##+tatataratarat## # atat#at
PLANT SITE — TOGIAK
FLOW (CFS) — 20
HEAD (FT) — 50
PIPELENGTH (FT) — 3500
TRANSMISSION LINE LENGTH (MILES) — 4
ROAD LENGTH (MILES) — O
CALCULATED VALUES
PIPESIZE (IN) — 32
HEADLOSS (FT) — 4.56817
PIPE COST ($/FT) — 170
MAXIMUM POWER (KW) — 60
ENERGY at 30% P.F. (kWh) — 157680
CONSTRUCTION COSTS
POWER PLANT — 60 KW X $900/KW =
DIVERSION STRUCTURE _
PIPELINE — 3500 FT X $ 17O/FT =
TRANSMISSION LINE — 4 MILES X $
ROAD — 0 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS =
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
40000/MILE
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. )
Double Flow, Year —Round
$ 54,000
$ 10,000
$ 595, 000
$ 160,000
$ 0
$ 0
#star arat##aratatat#
$ 919,000
$ 205,000
#ataratarararatar ar##
$ 1,024,000
$ 205,000
ar ar aratatat atatat#arat
>>>$ 1,229,000 <<<
$ 116,000
$ 18,000
$ 20,500
$ .85
##ar#arawt##atar#MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENT#arararatatatatar***
INTEREST
RATE
FUEL COST
2%
5'%
9%.
$1. 25/GAL. ($0. 16/KWH)
$ 461.520
$
351,720
$ 257,580
$1. 68/GAL. ($0. 24/KWH)
$ 618,840
$
471,600
$ 345,420
$3. 50/GAL. ($0. 50/KWH)
$ 1,2B9,160
$
982,440
$ 719,640
NOTES: Plant Factor of 30% used
All figures are to be considered rough estimates
APA 8/79
A-65
U.S. DEPARTMENT OF ENERGY
ALASKA POWER ADMINISTRATION
JUNEAU, ALASKA
ESTIMATED HYDRO COSTS
�#parse##ar��tat#at#iterar�aarat##�#�ererettr## ##at�atat mat#at�at� �#�etatetar�#����� �at�uet�� arat� ��
PLANT SITE — TOGIAK
FLOW (CFS) — 20
HEAD (FT) — 50
PIPELENGTH (FT) — 3500
TRANSMISSION LINE LENGTH (MILES) — 4
ROAD LENGTH (MILES) — 0
CALCULATED VALUES
PIPESIZE (IN) — 32
HEADLOSS (FT) — 4.56817
PIPE COST ($/FT) — 170
MAXIMUM POWER (KW) — 60
ENERGY at 30% P. F. (kWh) — 52560
Double Flow, Summer Only
CONSTRUCTION COSTS
i_ POWER PLANT — 60 KW X $900/KW =
DIVERSION STRUCTURE _
PIPELINE — 3500 FT X $ 170/FT =
TRANSMISSION LINE — 4 MILES X $ 40000/MILE _
ROAD — 0 MILES X $ 25000/MILE _
MISCELLANEOUS COSTS
BASE COST
CONTINGENCIES (25%)
FIELD COST
OVERHEAD (20%)
CONSTRUCTION COST
ANNUAL COST (20 yrs. at 7% interest)
ANNUAL O&M COST
INSTALLED COST PER KILOWATT
COST PER kWh ( 30% P. F. )
$ 54,000
$ 10,000
$ 595,000
$ 160,000
$ O
$ 0
srsrararsrarararsr ar##
$ 919,000
$ 205,000
#-x�-eirarat�at�#�
$ 1,024.000
$ 205,000
-�-xaaear��jratatatat
>>>$ 1,229,000 «<
$ 116,000
$ 18,000
$ 20,500
$ 2- 55
arararsrsrararara ***MAXIMUM
EXPENDITURES FOR FUEL
REPLACEMENTararsrsrarararsrsr***
INTEREST
RATE
FUEL COST
27.
5%
9%
$1. 25/GAL. ($O. 18/KWH)
$ 153.840
$
117,240
$ 85,860
$1. 68/GAL. ($0. 24/KWH)
$ 206,280
$
157,200
$ 115,140
$3. 50/GAL. ($0. 50/KWH)
$ 429,720
$
327,480
$ 239, S80
NOTES: Plant Factor of 30% used
All figures are to be consideTe�d
rough1 estimates
_ •APts 8/79
A-66
APPENDIX B
Load/Streamflow Curves
Load/Streamflow Curves
Due to the lack of any accurate streamf low records for the sites under
investigation, an estimate of these flows was made based on several
factors. These included the flows of larger streams in the region which
had records, the flows of similar size streams in other regions experi-
encing the same climatic conditions, and the input of local people
familiar with the longterm flow patterns .of the streams in question.
The "Alaska Water Assessment," published in August 1976 by the U.S.
Geological Survey, was the main source for stream hydrology in the
regions studied.
Generally it was found that the streams had low winter flows of about 5
to 10 percent of the yearly mean with a peak flow occurring in June.
This peak' rapidly dropped off with a second peak of lesser magnitude
again occurring in the fall in a couple of the streams. The streams at
Scammon Bay and Elim did not experience the large decrease in winter
flows due to the existence of springs. Sincethese estimates are not
based on actual records for the individual sites, they may not be fully
representative of actual long-term conditions.
The monthly average demands during 1978 were plotted for the nine most
promising sites. These monthly demand figures were furnished by AVEC.
Also included on this plot was the monthly average potential hydroelec-
tric energy which could be available at these sites. From this plot it
can .easily be seen where deficiencies of energy would occur if the site
were to be developed. During these periods of hydroelectric energy
deficiencies it would be necessary to provide diesel generated electric
energy to meet the shortage.
The plots for the nine individual sites follow.
I
0
0
0
K
W
H
Cr0m
{
1
,
,
,
1
,
,
0-
AMBLER
MONTHLY LOAD DISTRIBUTION and HYDRO CAPABILITY CURVES
Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep
o - Energy Use (1978)
# - Hydro Potential
- Exceeds Scale
/ - Diesel Supplement Reqd.
Hydroelectric Potential
1000 kWh
Estimated
Hudro Power
Diesel
Energy Use
Available
Usable
Excess
Supplement
January
70
30
30
0
40
February
68
40
40
0
28
March
62
50
50
0
12
April
58
100
58
42
0
May
52
300
52
248
0
June
33
600
33
567
0
July
35
500
35
465
0
August
39
200
39
161
0
September
49
140
49
91
0
October
52
100
52
48
0
November
56
60
56
4
0
December
68
40
40
0
28
TOTAL
642
21160
534 (1 ) 1,626
108 (2 )
(1) - Equivalent
to
approximately
76,200
gallons of
diesel fuel
(2) - Equivalent
to
approximately
15,400
gallons of
diesel fuel
B-i
1
0
0
0
K
W
H
ELIM
MONTHLY LOAD DISTRIBUTION and HYDRO CAPABILITY CURVES
100
50
t0M
Oct Nov Dec Jan Feb
o — Energy Use (1976)
# — Hydro Potential
— Exceeds Scale
/ — Diesel Supplement Reqd.
,
Mar Apr May Jun Jul Aug Sep
Hydroelectric Potential
1000 kWh
Estimated
Hudro Power
Diesel
Energy Use
Available
Usable
Excess
Supplement
January
36
73
36
37
0
February
35
73
35
38
0
March
32
74
32
42
O
April
30
78
30
48
0
May
27
88
27
61
0
June
17
98
17
81
O
July
18
93
18
75
0
August
20
88
20
68
0
September
25
93
25
68
0
October
27
98
27
71
0
November
34
88
34
54
0
December
35
73
35
38
0
TOTAL
336
1,017
336(1) 681
0(2)
(1) — Equivalent
to
approximately
48,000
gallons of
diesel fuel
(2) — Equivalent
to
approximately
0
gallons of
diesel fuel
B-2
1
O
0
O
K
W
H
150-I
I
1
I
,
I
I
75
tg
GOODNEWS BAY
MONTHLY LOAD DISTRIBUTION and HYDRO CAPABILITY CURVES
Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep
o - Energy Use (1978)
* - Hydro Potential
- Exceeds Scale
/ - Diesel Supplement Reqd.
Hydroelectric Potential
1000 kWh
Estimated
Hudro Power
Diesel
Energy Use
Available
Usable
Excess
Supplement
January
34
5
5
0
29
February
33
6
6
O
27
March
28
10
10
0
18
April
25
20
20
O
5
May
23
50
23
27
0
June
19
135
19
116
0
July
18
80
18
62
0
August
20
40
20
20
0
September
26
20
20
0
6
October
28
10
10
0
18
November
30
8
8
0
22
December
32
6
6
0
26
TOTAL
316
390
165(1) 225
151(2)
(1) - Equivalent
to
approximately
23,500
gallons of
diesel fuel
(2) - Equivalent
to
approximately
21,500
gallons of
diesel fuel
B-3
1
0
0
0
K
W
H
200-
I
,
,
1
t
100-i
,
,
,
,
,
,
,
t=
GRAYLING
MONTHLY LOAD DISTRIBUTION and HYDRO CAPABILITY CURVES
r
Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep
o - Energy Use (1978)
# - Hydro Potential
^ - Exceeds Scale
/ - Diesel Supplement Reqd.
Hydroelectric Potential
1000 kWh
Estimated
Hudro Power
Diesel
Energy Use
Available
Usable
Excess
Supplement
January
29
90
29
61
0
February
25
100
25
75
0
March
24
150
24
126
0
April
23
200
23
177
0
May
22
900
22
878
0
June
21
1,200
21
1,179
0
July
23
325
23
302
0
August
23
183
23
160
0
September
26
160
26
134
0
October
30
140
30
110
0
November
31
120
31
89
0
December
32
90
32
58
0
TOTAL
309
3,650
309 (1 ) 3,349
0 (2 )
(1) - Equivalent
to
approximately
44,100
gallons of
diesel fuel
(2) - Equivalent
to
approximately
0
gallons of
diesel fuel
B-4
1
0
0
0
K
W
H
kes
W&M
Se
KALTAG
MONTHLY LOAD DISTRIBUTION and HYDRO CAPABILITY CURVES
Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep
o — Energy Use (1978)
# — Hydra Potential
— Exceeds Scale
/ — Diesel Supplement Reqd.
Hydroelectric Potential
1000 kWh
Estimated
Hudro Power
Diesel
Energy Use
Available
Usable
Excess
Supplement
January
59
60
59
1
0
February
44
80
44
36
0
March
45
125
45
80
0
April
52
175
52
123
0
May
50
850
50
800
0
June
49
1,000
49
951
0
July
40
300
40
260
0
August
42
122
42
80
0
September
50
100
50
50
O
October
57
85
57
28
0
November
59
70
59
11
0
December
61
60
60
-;0-7(l)
0
1
TOTAL
608
3,027
2,420
1 (2 )
(1) — Equivalent
to
approximately
86,700
gallons of
diesel fuel
(2) — Equivalent
to
approximately
100
gallons of
diesel fuel
B-5
KIANA
MONTHLY LOAD DISTRIBUTION and HYDRO CAPABILITY CURVES
500—I
1
1
1
0
0 ;
0 ;
K
W S
H
250-1
r
1
0—i
Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep
o — Energy Use (1978)
— Hydro Potential
" — Exceeds Scale
/ — Diesel Supplement Reqd.
Hydroelectric Potential
1000 kWh
Estimated
Hudro
Power
Diesel
Energy Use
Available
Usable
Excess
Supplement
January
150
10
10
0
140
February
146
15
15
0
131
March
133
20
20
0
113
April
125
25
25
0
100
May
112
200
112
88
0
June
71
500
71
429
0
July
75
300
75
225
0
August
83
200
63
117
0
September
104
100
100
0
4
October
112
60
60
0
52
November
142
30
30 -
0
112
December
146
20
20
0
126
TOTAL
1,399
1,430
621(1)
259
778(2)
(1) — Equivalent to approximately 98,700 gallons of diesel fuel
(2) — Equivalent to approximately 111,100 gallons of diesel fuel
1
0
0
0
K
W
H
150-;
75 -,
me=
SCAMMON BAY
MONTHLY LOAD DISTRIBUTION and HYDRO CAPABILITY CURVES
Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep
o - Energy Use (1978)
* - Hydro Potential
- Exceeds Scale
/ - Diesel Supplement Reqd.
Hydroelectric Potential
1000 kWh
Estimated
- Hydro Power
Diesel
Energy Use
Available
Usable
Excess
Supplement
January
29
98
29
69
0
February
29
98
29
69
0
March
27
101
27
74
0
April
25
105
25
80
0
May
24
lie
24
94
0
June
18
131
18
113
0
July
19
124
19
105
0
August
22
ill
22
89
0
September
24
120
24
96
0
October
27
131
27
104
0
November
28
118
28
90
0
December
29
98
29
69
0
TOTAL
301
1,353
301(1) 7 0-5 2
_
O(2)
(1) - Equivalent
to
approximately
43,000
gallons of
diesel fuel
i2)-=jivalent
to
approximately
0
gallons of
diesel fuel
m
1
0
0
0
K
W
H
SHUNGNAK
MONTHLY LOAD DISTRIBUTION and HYDRO CAPABILITY CURVES
200-1
I
,
1
I
100—:
/////
//////////
/////////////////////
//////////////////
0—i
///// //// ///// /f///
Oct Nov Dec Jan Feb Mar AprMay Jun Jul Aug Sep
o — Energy Use (1978)
# — Hydro Potential
^ — Exceeds Scale
/ — Diesel Supplement Reqd.
Hydroelectric Potential
1000 kWh
Estimated
Hudro Power
Diesel
Energy Use
Available
Usable
Excess
Supplement
January
96
5
5
0
91
February
93
7
7
0
86
March
85
10
10
0
75
April
80
50
50
0
30
May
72
100
72
28
0
June
45
200
45
155
0
July
48
150
48
102
0
August
53
100
53
47
0
September
67
40
40
0
27
October
72
20
20
0
52
November
91
10
10
0
81
December
93
7
7
0
86
TOTAL
B95
699
367(1) 332
528(2)
(1) — Equivalent
to
approximately
52,400
gallons of
diesel fuel
(2) — Equivalent to
approximately
75,400
gallons of
diesel fuel
a
1
0
0
0
K
W
H
TOG IAK
MONTHLY LOAD DISTRIBUTION and HYDRO CAPABILITY CURVES
100-1
50
D—i
Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep
o — Energy Use (1978)
* — Hydro Potential
— Exceeds Scale
/ — Diesel Supplement Reqd.
Hydroelectric Potential
1000 kWh
Estimated
Hudro
Power
Diesel
Energy Use
Available
Usable
Excess
Supplement
January
79
2
2
0
77
February
86
2
2
0
84
March
85
3
3
0
82
April
77
5
5
0
72
May
59
20
20
0
39
June
40
48
40
8
0
July
53
25
25
0
28
August
56
20
20
0
36
September
85
10
10
0
75
October
90
5
5
0
85
November
95
3
3
0
92
December
100
2
2
0
98
TOTAL
905
145
137(1)
B
768(2)
(1) — Equivalent to approximately 19,500 gallons of diesel fuel
(2) — Equivalent to approximately 109,700 gallons of diesel fuel
6
APPENDIX C
Existing Loads and Installed Capacity
KW LOADS
VILLAGE
PEAK
LOW
AVER
EST
NEW LOADS
1978
1978
197E
1979
ELIM
61
34
47
114
35 new homes, 1979, Est 35KW
4455 Sq Ft HighSchool,Est 18KW
Total Est 53 KW
FORTUNA LEDGE
(Marshall)
54
3S
46
69
High School Addn, May 1980
Est 15 KW
GOODNEWS BAY
60
32
43
100
8800 Sq Ft High School, 1980
Est 35 KW
Health Facility, Est 5 KW
Total Est 40 KW
GRAYLING
55
35
43
73
4455 Sq Ft High School, Est
18 KW
LOWER & UPPER
KALSKAG
96
60
81
132
6600 Sq Ft High School
Safewater Project
Total Est 35 KW
KALTAG
104
64
80
107
Armory 3 - KW
KIVALINA
96
55
74
99
Health Facility - 3 KW
MEKORYUK
69
45
58
105
8800 Sq Ft High School, 1980
Total Est 36 KW
MOUNTAIN VILLAGE
229
161
191
264
New High School Addition
March, 1960
O&M Storage Building
United Utilities Building
Dry Storage Building
Total Est 35 KW
NULATO
124
43
99
184
30 New Homes
Community Building
High School Addition
Total Est 60 KW
PILOT STATION
65
46
56
83
High School Addition, 1930
Est 1S KW
C-1
KW LOADS
VILLAGE
PEAK
LOW
AVER
EST
NEW LOADS
1978
1978
1978
1979
ST MARY'S incl
PITKAS POINT &
ANDREAFSKY
348
210
302
374
St Mary's Armory
United Telephone
Pitkas Point -New High School
Andreafsky-New Store
Total Est 26 KW
SCAMMON BAY
54
32
48
89
6580 Sq Ft High School
Water/Sewer Proj,
Total Est 35 KW
SHAKTOOLIK
56
30
45
101
10,000 Sq Ft High School, 1980
Fish Processor
•
Total Est 40 KW
TOGIAK
151
115
130
161
Ice Plant, New Airport
Total Est 10 KW
TOKSOOK BAY
106
53
76
116
Safewater Proj & Two Wells
Total Est 10 kw
TUNUNAK
66
36
49
129
23 New Homes, 1979, 23 KW
8800 Sq Ft High School, 1980
35 KW, Washeteria, 5 KW
Total Est 63 KW
WALES
42
25
33
47
Sewer Pros, 5 KW
C-2
Schedule of Winter Peak Loads and Units to be
in Service During 1979-1980 Peak
1978
79-80
Village
Peak
Est.
Alakanuk
1813
191
Ambler
70
100
*
Anvik
46
97
Chevak
170
170
*
Eek
44
44
*
Elim
61
139
Emmonak
192
192
*
Fortuna Ledge
70
85
Gambell
142
193
*
Goodnews Bay
60
60
*
Grayling
56
74
*
Holy Cress
84
84
Hooper Bay
216
236
*
Huslia
70
108
*
Kalskag(Lower)
96
132
#
Kaltag
104
107
Kiana
149
170
Kivalina
96
99
*
Koyuk
40
7S
Mekoryuk
8Q
80
Minto
66
96
Mt. Village
229
264
*
New Stuyahok
79
94
*
Noatak
103
128
Noorvik
176
211
Nulato
127
187
*
Nunapitchuk
141
141
Old Harbor
95
110
*
Pilot Station
67
85
Ouinhagak
76
132
#
St. Mary's
348
351
*
St. Michael's
12B
177
Savoonga
155
203
*
Scammon Bay
78
113
Selawik
163
186
Shageluk
43
58
*
Shaktoolik
60
65
Shishmaref
156
181
Shungnak
96
96
*
Stebbins
83
119
Togiak
216
226
Toksook Bay
106
116
*
Tanunak
66
89
*
Wales
42
52
Engine -Gen size
350,300
160, 160, 100
90,50,50 (from Alakanuk)
300, 300, 160
106, 50, 50
106, 100, 50
300, 300, 175
90, 75, 50
300, 160, 75
75,75
75, 50, 50 (from Chevak)
106,106
300, 300, 175, 100
160, 75, 50
160,100,75 (Tie -line to Upper Kalskag)
105,50
300, 250, 100
300, 160, 50
75, 75, 50 (from Elim)
*100, 100, 75
90,75
300,300
105, 105, 35
160, 160, 75
300,300,100 (inside, not connected)
300,300,100 (from Mt. Village)
200,150,100 (Tie -line to Kasigluk)
100
106, 75, 35
160, 75, 75
600, 600, 350
160, 105, 75
250, 100, 100
1=0, 50, 35, ( from Emmonak )
300, 250, 100
75, 50, 50
75,75,50 (from Gambell)
300, 300, 105
30, 300, 105, 50, 50(outside, not
75,75
300, 160, 90
300, 300, 100
100,50
105, 105, 35
connected
* Single-phase villages
# Excess D353 Cats (300 kW) are definitely to be moved from these
locations. One in St. Mary's, two in Kaltag. Other villages from
which excess units may be moved include: Shungnak(2),Toksook Bay (2).
Possible Tie -lines: Shungnak - Kobuk (new village) ( 150 kW)
St. Mary's - Mt. Village - Pilot Station (700 kW)
St. Michael - Stebbins (286 kW) Toksook Bay - Tanunak (205 kW)
Togiak - Twin Hills (new) (330 kW)
Source - AVEC C-3
APPENDIX D
Investigation Costs
Investigation Costs
The costs, for further investigations needed to better analyze the
feasibility of the nine most promising sites, were estimated. These
necessary additional items would include the following:
1.
Stream gaging - establish a staff gage or weir
to measure
streamflows.
2.
Surveying and mapping - survey and map the stream area for
location of diversion and intake works, penstock,
powerplant,
and transmission line.
3.
Soil and geology - examination to verify stability
and appro-
priateness of physical feature sites.
4.
Fish and Wildlife study - request Fish & Wildlife
Service to
examine and report on fish and wildlife aspects
of proposed
physical features. The same investigator should
do a brief
archeological inspection also.
5.
Project design and cost estimate - office studies
for turbine
and penstock selection based on hydrology, power
needs, soil
conditions, economics, etc. Drawings of general plan and
features should be adequate for Federal Energy
Regulatory
Commission minor license application.
The costs for these sites are tabulated on the following three pages.
D-1
SUMMARY OF INVESTIGATION COSTS
Togiak $25,000
Goodnews
20,000
Grayling
35,000
Kaltag
35,000
Scammon Bay
25,000
Elim
30,000
Kiana (Storage Plan $60,000) 40,000
Ambler 45,000
Shungnak/Kobuk/Mine 35,000
300,000
Old Harbor
Previous financing was by Alaska Power Administration, Estimated
additional cost is $31,000.
LIBRARY COPY
Alaska Power Authority
334 W. 5th Ave.
Anchorage, Alaska 99501
�O 10T �i ?,ro 3r �:�OI"� OFF9CE D 2
TABLE 1
INVESTIGATION COSTS
SCAMMON
OLD
WORK ITEM
SHUNGNAK
BAY
TOGLSK
GRAYLING
KALTAG
AMBLER
KIANA
SLIM
GOODNEWS
HARBOR
Run -of -River
Storage Plan
Stream Gaging
$ 8,930
$ 4,970
$ 3,320
$ 5,600
$ 4,500
$ 9,660
$ 8,930
$ 8,930
$4,700
$ 1,160
$15,000
Surveying &
Mapping
9,180
5,690
6,300
10,750
10,600
10,910
10,310
18,640
7,360
4,290
7,400
Soil & Geology
Examination
1,620
1,750
1,880
1,800
1,460
4,140
1,620
3,940
1,850
1,350
1,200
rr
i
b1 Fish & Wildlife
Studies
1,950
1,360
1,300
1,250
1,050
1,950
1,950
1,950
1,200
790
1,000
Project Design &
Cost Estimates
6,000
6,000
1,000
6,000
6,000
6,000
6,000
12,000
6,000
6,000
6,000
Subtotals
$27,680
$19,750
$18,800
$25,400
$23,610
$32,000
$28,810
$45,450
$21,110
$12,580
Contingencies 20%
& Inflation 10%
8,300
5,930
5,640
7,600
7,080
9,800
8,640
13,640
6,330
4,070
TOTAL (Rounded)
$36,000
$26,000
$25,000
$35,000
$35,000
$45,000
$40,000
$60,000
$23,000
$20,000
$31,000