HomeMy WebLinkAboutNotice of Comp of Negative Feasibility Rep for Hydro Power at Four AK Locations 1984HYD
045
.
I
~OT ICE OF COMPLETION OF NEGATI~ ' . 1\EASIEILITY REPORTS FOR HYDRO-
.ECTRIC POWER AT FOUR ALASKA
l#)CATIONS
REPLY TO
ATTENTION OF
DEPARTMENT OF THE ARMY
U .S •. ARMY ENGINEER DISTRICT, ALASKA
POUCH 898
ANCHORAGE, ALASKA 99606·0898
RECEIVED
Plan Formulation Section
OCT 1 1984
ALASKA POWER AUTHORITY September 27, 1984
NOTICE OF COMPLETION OF NEGATIVE FEASIBILITY
REPORTS FOR HYDROELECTRIC POWER
AT FOUR ALASKA LOCATIONS
I am announcing completion of reports on potential hydroelectric
power generating facilities at four Alaska ·locations: Chickaloon,
Galena, Kenney Lake, and Nome. In all cases, after careful
investigation and evaluation, I found that Federal development of
the facilities is not feasible at this time.
All four potential projects share a common limitation; they cannot
meet the electricity needs of their ·communities during the winter,
when Alaskan streams freeze and their flow stops or shrinks to an
amount too small to produce sufficient power. Winter is also the
period when demand for electricity . is . greatest. Even with a
hydropower _project, each of these pl _aces ·would have to continue
using fossil fue l generation in winter •. · ·
·-• ..
The four locations were studied pursuant to<a .·re5olution of the
U.S. Senate Comnittee on Public Works .. dated October 1, 1976,
directing the Corps of Engineers to determi-ne · the feasibi 1 ity of
installing small hydroelectric plants fn . isolated Alaskan
communities. The studies evaluated futur:e··, needs for electrical
power at each of the sites and alternatives available to meet those
needs. While the Corps had primary responsibility for conducting
the studies, numerous other Federal, State,· ·and local agencies and
groups contributed. A public involvement program was maintained.
All sites were identified in regional reconnaissance stuqies
performed by engineering firms under contract. -The Corps conducted
followup field investigations. Each location .is briefly described
below.
Chickaloon: The Chickaloon area, about 7b mil~s northwest of
Anchorage , is a rural community situated along the Glenn Highway,
which follows the Matanuska River. The area now receives power
from the Matanuska Electric Association (MEA), 95 percent of it
produced by gas-fired turbines. Four potential hydroelectric sites
were studied. A site on the Kings River, a tributary of the
Matanuska, appeared to hold the greatest promise of feasibility. A
run-of-the-river project evaluated for this site features a
30-foot-high concrete dam, which would furnish power for twin
turbines with a total capacity of 600 kilowatts (kW). An annual
average of 3.1 million kilowatt-hours (kWh) could be fed into the
MEA line serving the Chickaloon area. The project would cost about
$7 mi 11 ion and would have a benefit-cost ratio of 0. 3 to 1. (A
ratio of greater than 1 to 1 is required to meet Federal economic
evaluation criteria.) Besides having the problem of low streamflow
in winter, this project would have to compete against the existing
MEA electricity, which is produced with relatively inexpensive
natural gas. The project would be economically infeasible at this
time.
Galena: Galena is located on the north bank of the Yukon River,
approximately 270 miles west of Fairbanks. It is a regional hub
for state and federal agencies, a transportation center, and the
site of a U.S. Air Force Base. The potential damsite lies on Kala
Creek, across the Yukon River from Galena, at a point where the
creek • s course falls from a narrow valley to a relatively flat,
swampy plain. The optimum project would be a 100-foot-high
rockfill dam which would create a 1,300-acre reservoir. With a
turbine capacity of 650 kW, the project could generate 4.5 million
kWh a year -but no energy in February, March, or April. A larger
150-foot-high dam would provide some year-round capacity, but it
would be insufficient to meet demand and the cost would more than
doub 1 e. The optimum project wou 1 d cost $37.3 mi 11 ion and have a
benefit-cost ratio of 0.3 to 1. This project would produce power
during the warmer months, but at a greater expense than continuing
to generate electricity with diesel fuel. In addition, serious
potential problems were seen with the proposed transmission cable
crossing of the Yukon River.
Kenney Lake: This small community is located in the Tonsina River
valley 66 miles northeast of Valdez. The potential damsite lies
across the Tonsina from Kenney Lake on a small unnamed tributary of
the Tonsina. The project would incorporate a 13-foot-high rockfill
dam and a turbine generator with an installed capacity of 1,500
kW. The energy produced during the warmer months would be fed into
the Copper Valley Electric Association {CVEA) system, supplementing
existing hydropower generation. Output would be about 4.7 million
kWh a year. The project would cost $9.3 million and have a
benefit-cost ratio of 0.7 to 1. Other project sizes were
considered, but no project at this location was found to be
economically feasible for Federal development at this time.
Nome: Nome, the most populous of the four sites, is a town of
approximately 3,200 people on the south coast of the Seward
Peninsula, fronting the Bering Sea. A gold-mining boom town at the
2
turn of the century, the community has become the commercial hub of
northwestern Alaska and a center for Native handicrafts. Seven
potential hydropower sites were investigated, but only three (Nome
River, Sulphur Creek, and David Creek) offered some promise of
development without severe technical problems. The three sites
were studied both individually and in a combined plan which would
deliver power from all three over a common transmission line The
generation capacity of the combined sites would be 840 kW; they
would produce a total of 3.4 million kWh of euergy a year. The
three-site system, which would cost $21.6 million, has a
benefit-cost ratio of 0.3 to 1. This is higher than the ratio of
any of the sites considered individually. Hydroelectric energy
would be available only 6 or 7 months a year. None of the Nome
plans is capable of competing with the existing diesel fueled
generation system.
Further information on any of the above studies may be obtained
from my office or from Mr. Carl Barash, Chief of my Plan
Formulation Section, Pouch 898, Anchorage, Alaska 99506-0898. The
telephone number is (907) 552-3461.
Please pass this information on to others interested in these
reports who may not have received this notice.
3
Je~ !0 ~ Ma~~~~s of Engineers
Acting District Engineer
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FOUR LOCATIONS INVESTIGATED FOR HYDROELECTRIC POWER 40o
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INTRODUCTION
Hydropower Development Potential
of
Kenney Lake, Alaska
October 1983
RECEIVED
OCT 1 1984
Wst<A P.OWER AUTiOIJy
The evaluation of small hydroelectric systems was authorized by
a 1 October 1976 United States Senate Resolution, which directed the
U.S. Army Corps of Engineers to determine the feasibility of
installing small prepackaged hydroelectric units in isolated Alaskan
communities.
In 1982, a regional inventory for small hydropower projects in
Southcentral Alaska was completed for the Alaska District by Ebasco
Services Incorporated. This inventory analyzed more than 30 sites,
recommending nearly 20 for more detailed examination, including the
Kenney Lake site. The Kenney Lake site was one of six selected by
the Alaska District from this group for field reconnaissance and
additional analysis. Ebasco did not conduct any field
reconnaissance at the Kenney Lake site during the Southcentral
inventory.
During 9-11 August 1982, an interdisciplinary Alaska District
team conducted a field reconnaissance of a potential small
hydropower project site near the small community of Kenney Lake in
the Tonsina River Valley. The potential site is located across the
Tonsina River from Kenney Lake on a small unnamed tributary south of
the Tonsina {see figure 1 and 2). This area is approximately 6
miles southwest {upstream) of the confluence of the Tonsina River
with the Copper River and approximately 30 miles southeast of
Glennallen.
Presently, the Copper Valley Electric Association {CVEA) serves
the Kenney Lake area. Based on the August 1983 edition of 11 Alaska
Electric Power Statistics .. by the United States Department of
Energy, of the total installed nameplate capacity of 22,104 kW;
12,000 kW are produced by hydropower, 7,304 kW by diesel, and 2,800
kW by gas turbine. A total net generation of 35,941 MWh was
generated in 1982.
ENVIRONMENTAL SYNOPSIS
Principal identified environmental resources in the vicinity of
the site and the stream are Coho salmon, Chinook salmon, and Dolly
Varden. The lower reaches of the stream are used as rearing habitat
by juveniles of those species. Chinook salmon were observed
spawning at the juncture of the subject stream and the Tonsina .
River. Juvenile salmon were collected upstream of observed spawn1ng
sites. The upstream extent of salmon spawning, juvenile rearing
habitat, and resident Dolly Varden distribution {if any) was not
determined. The fish populations involved are believed to be small
and it appears that impacts to identified fish populations and
habitats could be mitigated to within acceptable limits, possibly
with minor adjustments to optimum project design and operating
regimes. The stream undoubtedly contributes macroinvertebrates,
algae, and other food-web components to the Tonsina River. Minor
losses of these organisms would occur from project operation, but
these losses could not be regarded as significant to other systems.
Moose, black bear, brown bear, and a variety of furbearers in
the canine, weasel, and rodent families occur in the area.
Reconnaissance-level biological surveys indicate that project
construction and operation would have little adverse effect on these
animals, provided that construction and operation access could be
achieved without road construction. If an access road were
required, significant project impacts and secondary impacts from
improved access would likely occur to local wildlife populations.
No endangered or threatened species were observed or identified
in a brief literature search. No cultural resource survey or
inventory has been conducted.
HYDROLOGY
Description of the Area. The unnamed stream has a drainage area of
7.8 square miles. Watershed elevations range from about 2,400 to
6,000 feet msl. Significant snowpack exists in the higher
elevations {above 5,000 feet msl), especially on the north and west
slopes, but no glaciers exist in the study area. Stream slopes in
the area average about 650 feet per mile with a maximum slope of
about 860 feet per mile. Drainage area ground slopes range from
essentially horizontal to nearly vertical. The lower elevations are
covered by dense stands of willow, alder, and birch, while the
intermediate elevations are covered with tundra plants and, where
surface water is available, stands of alder. The higher elevations
are either bare or covered by tundra plants. The stream on which
the dam would be located consists of a series of cascades and
waterfalls from the headwater area to the proposed powerhouse
location. In general, the stream is about 12 feet wide with depths
of up to about 1.5 feet between cascades and up to about 4 feet in
the energy holes at the cascades. Site investigations indicate that
stream stage fluctuations have been very minor in the past and the
stream does not appear to have sediment problems above the damsite.
Design Flows. Stage and/or discharge data in the vicinity of Kenney
Lake, Alaska, are very limited. The only gaging stations which have
existed in the area are the Little Tonsina River near Tonsina {USGS
gage number 15207800, drainage area= 22.7 mi2), Squirrel Creek at
Tonsina {USGS gage number 15208100, drainage area = 70.5 mi2), and
Tonsina River {USGS gage number 15208000, drainage area = 420 mi2).
To Glennallen
\
\
·copper Center ·· .•
(
Trana-Aiaaka
Pipeline ,.. PROPOSED
To Valdez
Scale
10 0 10 20 lr....r--J I I I -~-------.
Mile•
': .. : i··;n:5ts~_:-.;_;,.:-z~:r\ ·t · ·
,,'·•·:···-~·-·~-··,: ·····~~.:·.~;.
Wrangell-Saint Elias National Park and Preaerve
0 ALASKA DISTRICT
KENNEY LAKE
Figure 1
................ _.t-.:~'E-!!~'!f:-.... ~~-Edgerton Highway
·------= •
I
1100~
•
Transmission
Line
Powerhouse
Penstock
Dam
1000 zooo 3000 4000
0 FEET
Figure 2
KENNY LAKE
Sma II Hydropower
Of these three stations, only the Tonsina River at Tonsina gage is
presently in operation. The period of record mean annual flows for
each of these three streams is given in Table 1.
Water Year
1966
1967
1968
1969
1970
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980
Table l
Mean Annual Flow (cfs/mi2)
Little Tonsina Rv.
(D.A. = 22.7 mi2)
0.99
0.79
1.44
1.45
2.81
l. 09
Squirrel Crk.
(D.A. = 70.5 mi1)
0.51 -
0.38
0.62
0. 31
0.28
0.38
0.59
0.47
0.35
0.49
Tonsina River
(D.A. = 420 mi£)
l. 90 -
1.77
2.04
1. 40
l. 51
l. 71
2.05
1.35
1. 60
2.01
1.58
2.82
l. 58
1.80
2. 31
The Tonsina River unit flows were obviously higher than those of
the other two stations, especially the Squirrel Creek station, but
they were not extremely different from the Little Tonsina River
flows. The preliminary design flows for the Kenney Lake hydropower
project were developed by multiplying the mean monthly Tonsina River
flows in cubic feet per second per square mile by the Kenney Lake
drainage area in square miles. This resulted in flows slightly
higher than what would probably have occurred at the Kenney Lake
damsite.
ENERGY USE
Records for 1982 indicate that CVEA generated approximately
35,941 MWh. Currently, CVEA purchases energy generated by
hydropower from the Alaska Power Authority during the summer. This
time period corresponds with the time period in which the Kenney
Lake project would operate.
Energy Analysis. The HEC program 11 Hydur" was used to compute the
energy production for a variety of project sizes. _A~ overall p~ant
efficiency of 0.86, a design head of aoo•, and a m1n1mum operat1onal
capacity of 0.4 times the design capacity were used as part of the
"Hydur" input data. The results are summarized below.
Plant Size (kW)
300
700
1 '500
2,000
4,000
Average Annual Energy (MWh)
1 '470
2,696
5, 153
5,561
6,709
Benefit Analysis. At this level of analysis, it was assumed that
the total average annual energy of the hydropower system less an 8
percent transmission loss would be equal to the usable energy. Two
categories of benefits were determined for each turbine size;
displaced existing hydropower and displaced transmission costs. An
existing hydropower generation cost of 3.6¢/kWh (Copper Valley
Electric Association, Inc.) combined with a transmission cost of 7.5
¢/KW results in a total energy displacement cost of 11. 1¢/kWh.
Shown below are benefits derived for each of the turbine sizes.
Usable Displaced Displaced
Plant Size Energy Existing Transmission
{kW) (MWh) Hldro~ower Cost Total
300 1, 350 49,000 $101,000 $150,000
700 2,480 $ 89,000 $186,000 $275,000
1,500 4,740 $171,000 $356,000 $527,000
2,000 5,120 $184,000 $384,000 $568,000
4,000 6,170 $222,000 $463,000 $685,000
Cost Analysis. A preliminary cost estimate was derived for each of
the project sizes. Shown is a summary of project features.
Plant Size Dam Height Penstock Di a.
(kWi (ft.) ( in. )
300 11 14
700 12 18
1' 500 13 26
2,000 14 30
4,000 16 48
The cost estimates included the following items: rockfill dam, a
4,900-foot steel penstock, a S-mile access road to the powerhouse, 3
miles of transmission line, the powerhouse plus associated features,
intake structure, helicopter support during construction, site
preparation, mob and demob, a 20 percent contingency, 12 percent for
E&D and S&A; and interest during construction based on a 2-year
construction period. This cost estimate does not include O&M
costs. Costs were amortized using an interest rate of 8 1/8 percent
and a 50-year project life. Shown below is a summary of the
estimated costs.
Plant Size (kW) First Cost Tot a 1 Costs Annual Costs 300 $ 6,954,000 $ 7,516,000 $ 623,000 700 $ 7,507,000 $ 8, 114,000 $ 673,000 1,500 $ 8,717,000 $ 9,310,000 4 772,000 2,000 $ 9,202,000 $ 9,946,000 $ 824,000 4,000 $12,568,000 $13,584,000 $1,126,000
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KENNEY LAKE
Graph A
EVALUATION
To derive the optimum project size and the net benefits, annual
costs were compared against annual benefits. In addition, a cost
per kWh was derived by dividing the project annual cost by the
project's equivalent usable energy. The results are summarized
below.
Plant Size Annual 1-\nnual Benefit/Cost
(kW) Costs Benefits Net Benet it Ratio $/kWh
--300 $ 623,000 $150,000 -$473,000 0.24 $0.46
700 $ 673,000 $275,000 -$398,000 0.41 $0.27
l '500 $ 772,000 $527,000 -$245,000 0.68 $0.16
2,000 $ 824,000 $568,000 -$256,000 0.68 $0.16
4,000 $1,126,000 $685,000 -$441,000 0.61 $0.18
The above analysis indicates that none of the turbine sizes
evaluated is economically feasible. Plant sizes versus net benefits
were graphed to determine the optimum project and to determine if
any feasibile units exist within the range selected (Graph A). The
optimum project size was found to be a 1,500 kW system with a
benefit/cost ratio of 0.68 which would produce negative net benefits
of $245,000.
CONCLUSIONS
The project would produce power during the warmer months so that
power could be fed into CVEA grid supplementing existing hydropower
generation. It appears that all power produced by the hydropower
project could be used in the CVEA system. During the winter, no
power would be generated due to ice, and the power flow would be
from the CVEA diesel generators to the Kenney Lake area. It can be
concluded that, even with the optimistic assumptions made on the
streamflow estimates used in the above analysis, no feasible project
size exists.
RECOMMENDATIONS
It is recommended that no further Corps of Engineers studies of
hydropower development at Kenney Lake be undertaken at this time.
DETAILED COST ESTIMATE (1,500 kW Plan)
ITEM/DESCRIPTION QUANTITY UNIT UN IT PRICE TOTAL
MOB & DE~10B l I 1. s. $1,600,000
DAM & INTAKE STRUCTURE
Excavation 820 c.y. 50 $ 41,000
Excavation, Rock {Spillway) 540 c.y. 50 27,000
Concrete, Dam 50 c.y. 800 40,000
Rockfill 800 c .y. 30 24,000
Steel, Rebar & Misc. 6,900 1 bs. 2 13,800
Intake l ea. 70,000 70,000
Total Dam and Intake Structure $ 215,800
PENSTOCK
26" dia. 1/4 11 Steel 5,000 1. f. 492.?/ $2,460,000
Concrete Supports 300 c.y. 800 240,000
Total Penstock $2,700,000
POWERHOUSE
Structure 1 ea. 163,000 $ 163,000
Turbine Generator 1 ea. 640,000 640,000
Accessory Electrical 1 ea. 258,000 258,000
Auxilliary Sys. & Equip. 1 ea. 39,000 39,000
Switchyard 1 ea. 50,000 50,000
Total Powerhouse $1,150,000
TRANSMISSION LINE
14.4 KV Line 3 mi1e 100,000 $ 300,000
Clearing 8.4 acres 5,000 42,000
Total Transmission Line $ 342,000
UNIMPROVED DIRT ROAD
Access Road 8 mile 54,250 $ 434,000
48 11 CMP 54 l.f. 98 5,300
Clearing 11.5 acres 5,000 57,500
Total Unimproved Dirt Road $ 496,800
SUBTOTAL $6,504,600
Contingency ( 20%) $1,300,900
Engineering & Design ( 8%) $ 520,000
Supervision & Administration ( 6%) $ 391,500
TOTAL FIRST COST $8,717,000
ll includes site prep, helicopter support for 6 months, mob & demob.
~/ includes cost of steel, excavation, installation, bends
'
ANNUAL COSTS AND BENEFITS
Investment Cost (incl. IDC)
Interest and Amortization (8-1/8%@ 50 yrs)
Annu a 1 Benefits
Displaced Existing Hydropower
Displaced Transmission Cost
Total Annual Benefit
Benefit-Cost Ratio
Net Annual Benefit
Dam Height (ft.)
Penstock Length (ft.)
Pertinent Data Sheet
Penstock Diameter (in.)
Transmission Line Length (mile)
Access Road length (mile)
Design head (ft.)
$9,310,000
772,000
$ 171 '000
356,000
$ 527,000
0.68
-$245,000
l3
4,900
26
3
5
800
•
-·· . ---· . .._ .... -· ------------
DEPARTMENT OF THE ARMY
ALASKA DISTRICT. CORPS OF ENGINEERS
POUCH 898
ANCHORAGE , ALASKA 99505
RECEIVED
OCT 1 1984
ALASKA POWER AUTHORITY
SMALL-SCALE HYDROPOWER FOR CHICKALOON, ALASKA
LETTER REPORT
AUGUST 1984
SMALL-SCALE HYDROPOWER FOR CHICKALOON, ALASKA
SUMMARY
The Alaska District, U.S. Army Corps of Engineers, investigated the
hydropower potential for Chickaloon, Alaska. Four sites along the Kings River
near Chickaloon were studied, and one site was selected for further
evaluation. A run-of-river project evaluated for this site would feature twin
turbines with a total capacity of 600 kilowatts. Due to low winter
streamflows, it could not produce a dependable capacity year-round. An annual
average of 3.1 million kilowatt-hours (kWh) could be fed into the Matanuska
Electric Association feeder line serving the Chickaloon area. The project
would cost about $7.0 million and deliver electricity for about $0.21 per kWh
to the existing feeder line. This cost exceeds alternative power system
costs. Therefore, no further studies by the Corps of Engineers are planned at
this time.
i
PERTINENT DATA SHEET
GENERAL DATA
Project Installed Capacity (kW)
Number of Units
Dam Height (ft.)
Penstock Type
Penstock Length (ft.)
Penstock Diameter (in.)
Transmission Line Length (miles)
Access Road Length (miles)
Gross Head (ft.)
Design Net Head (ft.)
Average Annual Energy (MWh)
Average Annual Usable Energy (MWh)
600
2
30
Welded Plate Steel
3,000
60
4
4
64
55
3,100
3,100
ECONOMIC DATA (50 Years, 8-l/8 Percent Interest, 1984 Prices}
Project First Cost
Investment Cost
Annual Cost
Annual Benefits
Benefit-Cost Ratio
Cost per kWh
i i
$ 7,032,000
$ 7,450,000
$ 648,000
$ 186,000
0.3
$ 0.21
INTRODUCTION
Authority
SMALL-SCALE HYDROPOWER FOR CHICKALOON, ALASKA
LETTER REPORT
August 1984
The evaluation of small hydroelectric systems was authorized by a 1
October 1976 United States Senate Resolution which directed the U.S. Army
Corps of Engineers to determine the feasibility of installinQ small
prepackaged hydroelectric units in isolated Alaskan communities.
Scope of Study
In 1982, a regional inventory for small hydropower projects in
Southcentral Alaska was completed for the Corps by Ebasco Services, Inc. This
inventory analyzed more than 30 sites and recommended almost 20 sites for more
detailed examination, including the Chickaloon site. The Chickaloon site was
one of six selected by the Corps from this group for field reconnaissance and
additional analysis. Ebasco did not conduct any field reconnaissance at the
Chickaloon site during the Southcentral Alaska inventory.
Field studies in 1982 and 1983 investigated and rejected the dam site
selected by Ebasco because seepage probably could not be economically
controlled. The site consisted of an unconsolidated deposit of considerable
depth, formed by a landslide and full of small to very large voids. However,
three additional sites"which appeared more promising were investigated. Of
these, one site located downstream from the original site appeared to hold the
greatest promise of feasibility. This potential site is located about 4 miles
by an existing unimproved dirt road from a junction on the Glenn Highway 72
miles northeast of Anchorage (figure 1).
Matanuska Electric Association (MEA) now serves this area with a single
phase feeder line beginning at its Sutton substation on the Glenn Highway and
ending at Mile 106. In 1983, MEA fed 3,988 megawatt-hours through the
substation which serves this single phase line plus a 3-phase line which
extends from Sutton to Palmer. The energy fed through the 3-phase line from
Sutton reaches the Palmer Correctional Center (about 3 miles from Sutton),
where a switch currently breaks the line. MEA purchases its power from
Chugach Electric Association (CEA). Currently 95 percent of this power is
produced by gas fired turbines. The remaining 5 percent is supplied by
hydropower. MEA currently charges residents of the area $15 per month for
each meter plus a rate ranging from $0.0584 to 0.0751 per kWh depending on the
consumption rate.
Environmental Synopsis
Both moose and bear tracks were observed at the site. The Kings River has
been sampled using minnow traps, seines, and electrofishing gear. Chinook
salmon, grayling, Dolly Varden, and whitefish are reported to inhabit the
0 10 10
t
....... ___ , J
Scale In Mllea
! Mile 57.8
Beginning of Exlatlng
Feeder Line
N
Chickaloon
Mile 108 End of
Exl.tlng Feeder
~Line
",J_
~ ~;;., \ {g~'>
·~'" ,/' 1..;.~;./i).J";., :_;.~~ "i· . ;,_ ·rj·Y~
PROJECT LOCATION ; ~:/:! ~. '.q--> .... · :; -~~(:~,
'/<': s ,,.,/> -. _ ·'-' .. __ ~<:: .•. ":¥ f.'-~ff ·/ ~-h-~-tt , /M9V N 'f t\l ~.$ ; :·.:. \ ,/~·-
_.,;-')· i ,-_
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AREA MAP
'1
I
"
stream, but a 2-day sampling period at a location 5 miles upstream from the
project site produced only Dolly Varden. Salmon would be more likely found at
the project site than at the sampling site, but no evidence of salmon has been
found. Further investigation at the site would be recommended if the project
were to proceed.
HYDROLOGY
Description of the Area. The Kings River drains an area of 127 square
miles at the location of the potential damsite, which is 7.3 miles above its
mouth. Kings River empties into the Matanuska River 15 miles northeast of
Palmer. Kings River elevations in the study area range from about 1,100 feet
mean sea level (msl) at the dam location to mountain peak elevations up to
about 6,700 feet. Large glaciers and icefields exist above 5,500 feet.
Stream slopes range from about 80 feet per mile in the vicinity of the
powerhouse and damsite up to about 500 feet per mile in the canyon 5.5 miles
upstream of the damsite. Significant sediment deposition has occurred
upstream of the canyon, where a large sand and gravel bar has formed. Braided
stream conditions exist above this deposit area. Observations of sediment in
this headwater area indicate that sediment deposition could be a problem at
the damsite because the stream velocities would be reduced in the impoundment
area, and consequently much of the suspended material probably would drop out.
Design Flows. The only flow and stage data known to exist for Kings River
are the discharge measurements made during August 1982 and August 1983.
Therefore, flows for Kings River were developed from observed data over a
23-year period of record for, two other gaged streams in the area: Little
Susitna River near Palmer (USGS gage #15290000, drainage area= 61~9 sq. mi.)
and Caribou Creek near Sutton (USGS gage #152820000, drainage area = 289 sq.
mi.). The period of record mean annual flows in cubic feet per second per
square mile (CFSM) for each of these two stations are given in table 1.
Because the study area is located approximately midway between the two gaged
streams, Kings River flows were computed by adding about 51 percent of the
Little Susitna mean monthly flows to about 49 percent of the Caribou Creek
flows and multiplying by the Kings River drainage area of 127 square miles.
Slightly more emphasis was placed on the Little Susitna River because it is
slightly closer to Kings River.
3
Month·
Water
Year
19"56
1957
1958
1959
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
1975
1976
1977
1978
Tab 1 e 1
Mean Annual Flow, Cubic Feet per Second
per Square Mile (CFSM)
Little Susitna River Caribou Creek
(D.A. = 61.9 sq. mi.) (D.A. = 289 sq. mi.)
3.00 1.23
3.18 1.11
2.16 0.58
3.73 1.23
2.89 1.47
3.31 1.20
3.99 1.65
4.80 1.03
3.09 1.31
3.38 0.80
2.71 0.69
3.81 1.04
3.39 1.18
1.55 0.50
2.55 0.88
3.75 0.97
3.68 1.09
2.97 0.90
2.92 0.70
3.70 1.36
2.60 0.82
4.04 1.19
2.29 0.74
The estimated mean monthly flows at the project site on the Kings River are as
follows:
Month
Jan
Feb
Mar
Apr
May
Jun
Flow (cfs)
34
27
22
30
310
940
Month
Jul
Aug
Sep
Oct
Nov
Dec
Flow (cfs)
640
495
345
146
69
44
Spillwa~ Desirn Flood. The decision was made to adopt the 2 percent
probabi ity f ow for the spillway design flood. Using the methodology
described in the USGS publication, "Flood Characteristics of Alaskan Streams,"
this flow was computed to be 5,000 cubic feet per second.
4
ENERGY ANALYSIS
Demand. Energy use records for the Chickaloon area were provided by
Matanuska Electric Association (MEA). Users served by the Sutton substation
are residential, with a few schools and municipal buildings. The area
consumption for 1983 was 3,988 MWh, with a predicted 6,600-MWh use by the year
2000. A low to moderate growth rate is assumed, as forecasted by MEA. The
annual growth until the year 2000 is assumed to be 4 percent per year. No
growth was assumed to occur after the year 2000. By using these projected
energy demand figures, an average annual equivalent consumption of 5,600 MWh
was developed over a 50-year period of analysis.
Hydropower. Monthly power routings for various plant sizes ranging from
150 to 7,000 kW were made based upon the standard energy equation:
kWh= E * Q * H * 0/11.8,
where kWh = plant output in kilowatt-hours;
E = efficiency of conversion, which was assumed to equal 0.83,
Q = mean monthly flow through penstock in cfs;
H = net energy head in feet at the turbine, which was 64 feet gross
head minus head losses associated with the flow in the penstock; and
0 = 720 hours of flow, a typical month's duration.
A computer program was used to compute the power potential of v~rious
total plant capacities between 150 kW and.7,000 kW. The computations assumed
that each plant capacity would be developed by twin turbines, which would be
more capable than one large turbine of producing energy during periods of low
streamflow. This analysis, which was based on monthly streamflows, indicates
that the 500-kW and smaller plants would produce energy during every average
month (figure 2). It is expected, however, that no energy would be produced
on some days with very low flows. The larger plants would not be expected to
produce any power during some of the low flow months of typical years.
BENEFIT-COST ANALYSIS
Benefit Analysis. The annual benefits assigned to a small hydropower
project depend on the system known to be the next least costly alternative.
The most obvious avoidable cost that can be eliminated by the proposed
hydropower alternative is the cost of natural gas used by Chugach Electric
Association to run its combustion turbines in Anchorage and across Cook Inlet
at the Beluga fields.
5
Gas prices depend on the terms of various gas contracts. Contracts
written early in the history of local petroleum development were cheap and
long term, and varied between $0.25 and $0.75 per million BTU. Contracts
written in recent years vary between $1.05 and $1.80 per million BTU. The
current average gas price used in energy production is $1.23 per million BTU.
The utility uses 12,500 BTU of gas to generate a kilowatt-hour of electrical
energy; this is equivalent to 80 kWh/million BTU. As a result, the current
fuel cost per kilowatt-hour is $0.015.
To assess the impact of changing gas prices on the competitive position of
hydropower development, two basic assumptions were made, as indicated in
figure 3. First, the current average $1.23 gas price was escalated following
Data Resource, Inc. {ORI) escalation factors. This escalation was projected
undiscounted from the present (1984) to the 1990 power-on-line (POL) date
anddiscounted to POL for the remaining years of the project life. An
escalation factor of 1.8 was computed for a 1990 POL date. The second
assumption allows the gas price to jump to an assumed world price in 1997, at
which time the existing long term gas contracts end. The projected 1997 price
was based on the current world price of $3.36 per million BTU, escalated
according to DRI factors. Energy benefits claimed during the project life are
discounted to the 1990 POL date, giving a $0.055/kWh average annual fuel cost
saved by the hydropower alternative.
Capacity benefits were considered but could not be claimed in this
analysis because the hydropower facility cannot provide energy during peak
demand periods, which unfortunately occur during low streamflow periods.
Figure 2 shows that some energy is produced in every average month for all
plant sizes considered except the 800-KW and larger capacity plants. However,
it is expected that there will be short periods within the winter months in
which the flow is too small to produce any power. Although no capacity
benefits have been claimed, there may be some benefits associated with an
extended life of the gas fired turbines. One small hydroelectric facility of
this scale will do little to extend the life of large gas fired turbines.
However, the combined impact of this project with others could have the effect
of extending the life of gas turbines. Operational costs associated with the
most efficient Chugach Electric Association (CEA) gas fired turbines total
more than li per kWh. Some of these costs would remain whether or not the
turbines were used. The study assumes that about 0.5¢/kWh for other O&M costs
could be avoided if turbine operation time could be reduced. Thus, the
benefit associated with reduced O&M of gas fired turbines would be 0.5¢ per
kwh.
The benefits used in this study totaled to 6i per kWr, including 5.5i per
kWh for fuel and 0.5i per kWh for reduced O&M. The marketable hydropower
energy and its value based on these benefits is shown for various capacity
hydropower plants in table 2.
6
Plant Capacity
(kW)
150
300
400
500
600
800
1 '300
2,200
7,000
Table 2
Marketable Energy and Its Value
Marketable Energy
(MWh)
1,200
1,800
2,000
2,400
3,100
3,600
4,900
6,700
7,800
Value
($1,000)
72
110
120
140
190
220
290
400
470
Cost Analysis. A cost estimate was determined for each of the
alternative capacity projects.
7
co
ff!IOM 10 )( }0 tO I INCH
1011-1 UNf HfAVY
7000
r --
~+++ +++-++++-+ 700 +-
-,_ -r--r .
H+H++Jt-H-
. ±±J±±±.:i-::i--= I --• -U
I I I I .. LLlJ . .l.l J .l ----1\ .UJ .. UJ_ I _ _
600
I=
HJ+-H-1-
1-
I u-~
+--
l(
A
1---' •
+'
-t-Dr-·· -r
+H-l--1--l-r-r Average Armua 1 _ -r
I Energy Demand
-1--h--,--,---,--++ _ _ _ -800 -r · .--.-.-\tr---~
-l-t--'-" ---"">-·c --~ d r-· ' --_ ' '"---legen : ri-i-t-H---t-+-tt::lt~-"__--:~f-~\_;=:r-___ -=-_ -_ ----_ _-Capacity Plants (kW)
H-f-lU Megawatt-:: -H-r--2 150 ----• 500 li.
Hours · -----1 --500 1"----
_ --I"' ----t-r--~--600 Jj_ r---f---~-r---cs -~--. f1 ~t-tttOO --------t--t--r--1-~-· _ . -600 __ J r ---800 -rs _ ,,
--400 t--t-_ LU -7000 J. _)_ u· --t-t-1-t---r---.. .., -~" -~-t----r r-r--.-,--±±: 500 -r---~-+ ~-r-rr -r-1"----tL -,
IH--t-t vr:= -'[ r
t-+H+H-H+t+t+t-1-t-H--H-+H 1\b-~ ±ittliUJJjJJt::ttt:ti-ti+t-IT
~---+-l-cr:t~ 1\
I-+++1-H-+++++++-+-1--H-H+I H l --n=+-rtt::rtll-rr~-· 3
oo _ _ _ -_ -~·~•* -_~:-~ -_r.::cr-r-t·-j-~~ll&}j·-u:ft' I I I I I
1---'
-t
H
~--~·-
CI'"Tl):;-3:
OJ 0 ::l 0
""0 --s CL ::l
OJ <+
cJ{/)'"t:):J
....J. (f) -s --1
<+ ...... 0'< '< (j) c....... nrorn -o<+n::s --sro.-+ro 0 CL """'l
c._.., '"0 tO
(D):;-0'< n __. <+
<+rt-roo
U1 (D ::l (D
--s<:-+3
::l -'•OJ
OJ OJ ::l
(·+ --.~ CL
-'·
< {/)
(j) c -o -o ......
'<
I I I I
..,
N
tO c --s
(D
200
100
-~+
Jan
n
~~~~H
-·-+-·--·-·
H--H+++++i--1-H-ffJt++:H·
·II {\
-H-++-!+++-1--11 _ 1\!-·n---l-
TH-tfn=t~ltt ' --. ~tit
~H-_ I TTl
t-1-;~
++++-__ 1 __ -:-{i 1---5-.0 _ ::! ___ -~ -: --
~-j_ ... h
tr:~-1-l-l-l!--l-1 l-1--l +-l·t +++-
~~~$}\
\f\}1-
·::t=rcll"[S--Et\ -ltrL1~
+-+
.u:::tc1· ··t·r-·-~p _ _[ __ -· . -~
H--t-1----'
1-
Feb Mar Apr May June July Aug Sept Oct Nov Dec
·I~-
< w
(.)
>
Cll
Q w
U)
< :r:
(.)
~
:::;)
D.
U)
<
" :::;) ....
al
z
0 -..J
..J -:E
~ w
D.
0
8.00
(2014, $7.69}
7.00
8.00
(1997, $5.60)
5.00
ANNUAL EQUIVALENT COST : $4.39/MILLION
BTU. $0.055/kWh FOR 50-YEAR LIFE
4.00 ( 1990 TO 2040} AT 8 1/8% INTEREST
3.00 ASSUHPTI ONS:
( 1) Weighted average price of all gas
currently purchased in 1984 is $1.23,
according to Chugach Electr1c Assoc .
(CEA)
2.00 (1997, $2 .. 05} (2) Data Resources, Inc. escalation
rates used from 1984 to 1997.
( 3) Gas cost jumps to expected
world market price in 1997 when long
term gas contracts end.
1.00 (4) Data Resources, Inc. escalation
rates used from 1997 to 2040.
1184 1110 1117 2000 2010 2014 2040
YEAR FIGURE 3
CHICKALOON, ALASKA
SMALL HYDROPOWER
FEASIBILITY STUDY
PROJECTED NATURAL GAS COSTS
TO CHUGACH ELECTRIC ASSOCIATION
9 Al•ak• Dlatrlct, Corpa of Entlneera
Table 3 develops the annual costs for various alternatives. Construction
was assumed to take 18 months. The project was amortized over a 50-year (1990
to 2040) project life at 8-1/8 percent interest. An annual $30,000 operations
and maintenance cost was added to obtain total annual costs.
Table 3
Annual Costs Developed for Various Capacity Alternatives
400 500 600 800 Plant Size (kW)
First Cost ($1,000)
Interest During
6,776 6,917 7,032 7,303
1,300
8,490
Construction
403 411 418 434 (18 months)($1,000)
Investment Cost ($1,000)
Annual Interest and
Amortization (50 years
7,179 7,328 7,450 7,737
504
8,994
at 8-1/8%, 1990 POL)
($1,000)
Operations & Maintenance
($1,000)
Total Annual Cost ($1,000)
EVALUATION
595
30
625
608
30
638
618
30
648
642
30
672
746
30
776
To derive the optimum project size and the benefit/cost ratio, annual
benefits were compared with annual costs (table 4). In addition, a payback
cost per kWh was derived by dividing the project annual cost by the annual
equivalent usable energy.
Table 4
Economic Summary for Various Alternative Capacity Projects
Power Cost
Annual Annual Net Associated
Plant Size Costs Benefits Benefits Benefit/Cost with Project
(kW) ($1,000) ($1,000) ($1,000) Ratio ($/kWh)
400 625 120 -505 . 19 • 31
500 638 140 -498 .22 .27
600 648 190 -458 .29 . 21
800 672 220 -452 .33 . 19
1 '300 776 290 -486 .37 • 16
The above analysis indicates that none of the turbine sizes evaluated is
economically feasible. Based on the assumptions of the study an approximate
capacity project in the 600-kW to 800-kW range would be the optimum
alternative, but even this project would be expected to show annual losses of
some $450,000 with a benefit/cost ratio of about 0.3. The lower end of the
optimum size range was considered more appropriate since average monthly flows
tend to overstate potential energy benefits. Table 5 presents a detailed cost
estimate for the 600-kW project, which was identified as the optimum project
although it was found economically infeasible.
10
Figure 4 shows the layout of the major project features. The road
alinement shown is only approximate and does not show switchbacks, which
account for almost another mile of road. The design is based on field
measurements and observations. The powerhouse lump sum cost, excluding
tailrace and powerhouse excavation costs, is based on experience in estimating
costs of other similar Alaskan small hydropower powerhouses. The relatively
high volume, low head turbines associated with this project may tend to make
actual costs higher than shown. The cost estimates include the following
items: a 30-foot-high concrete spillway dam and related features, including an
intake structure and a temporary diversion during construction; powerhouse,
including the twin 300-kW turbines, electrical components, and tailrace; the
access road, including improvements to 4 miles of existing road and 3,000 feet
of new road; the 4 miles of transmission line, poles, and clearing required to
connect the project to the existing transmission line at mile 72 (from
Anchorage) on the Glenn Highway; 11.6 miles of new poles and a 3-phase
transmission line along the Glenn Highway from mile 72 to the Sutton
Substation; the 3,000 feet of 5-foot diameter steel penstock along the new
access road between the dam and powerhouse (about 1,200 feet of the penstock
would be buried to avoid negative ·pressure); mob and demob; lands and damages;
a 20 percent contingency; a 15 percent allowance for engineering, design,
supervision and administration; and interest during construction based on an
18-month construction period. Investment costs were amortized for a 50-year
project (1990 to 2040) at 8-1/8 percent, and an annual $30,000 operations and
maintenance cost was added to obtain total annual costs. All cost estimates
were based on 1984 price levels.
The "Pertinent Data Sheet 11 at the front of this report summarizes the
600-kW optimum project.
11
1-'
N
)
---!OWERHOUSE
" ) I TRANSMISSION LINE
~ ? {
~,... IMPROVED EXISTING
N /J~•k•
"ooo I
\ooo
1000
0 3000 3000
E 3 E3 t=1 t===! t===1
Scale In Feet
Flaure 4
PROJECT SITE MAP
Table 5
Detailed Cost Estimate
Optimum Project
Plant Capacity -600 kW
Item Description Quantity Unit Unit Total
Price
{ $)
Mob & DeMob l. s. $ 200,000
lands & Damages 1 l. s. $ 40,000
Spillway Dam & Intake Struc.
Cofferdam & Temp. Diversion 1 l. s. 25,000
Concrete 700 c.y. 1,200 840,000
Excavation 200 c.y. 50 10,000
Intake 1 1. s. 60,000
Reinforcing Steel 35,000 1 b. 1.50 52,500
$ 987,500
Penstock
60 in. Oiam. l/4 in. Steel 483,000 lb. 2 $ 966,000
{3,000 ft.)
Rock Excavation 2,500 c.y. 30 75,000
Common Excavation 260 c.y. 15 3,900
Concrete Supports 60 ea 15,600
$1,060,500
Powerhouse
Structure, Turb. Generator,
Accessory Electrical, 1 1. s. $1,085,000
Auxiliary Systems & Equip.,
Switchyard
Tailrace & P.H. Excavation 260 c.y. 50 13,000
$ 881,000
Transmission Line
Powerhouse to Glenn Highway
Along Road (includes
clearing & poles) 4 mi. 150,000 $ 600,000
Glenn Highway Mile 72
to Sutton Substation 11.6 mi. 100,000 1,160,000
$1,760,000
Access Road (12 ft. wide)
Filter Fabric (13,560 ft.) 46 Roll 350 $ 16,100
Gravel 9,100 c.y. 15 136,500
18-foot, 48 in. Diam. Steel
Culvert Pipe (including ends) 1 l.s. 1,800
Clearing (3,000 ft.) 1 1. s. 4,000
Excavation 210 c.y. 40 8,400
$ 166,800
Subtotal $5,095,800
13
Contingency (20%)
Total Contract Cost
Engineering & Design (8%)
Supervision & Administration (7%)
Total First Cost
Interest During Construction (18 months)
Investment Cost
Annual I&A (50 years at 8 l/8 %, 1990 POL)
Annual Operations and Maintenance
Total Annual Cost
CONCLUSIONS
$1,019,200
$6,115,000
$ 489,000
$ 428,000
$7,032,000
$ 418,000
$7,450,000
$ 618,000
$ 30,000
$ 648,000
T\'10 factors are primarily responsible for keeping the benefits much
lower than they might otherwise be. First, the project is not a dependable,
year-round source of energy. Projects with water storage can overcome low
flow months and claim capacity benefits. This run-of-the-river project,
however, cannot feasibly incorporate a reservoir of required magnitude due
to unfavorable topography. Second, the project is competing against
electricity produced with relatively inexpensive fuel. The hydropower
benefit/cost ratio would be about 0.3. Therefore, it is recommended that
the Corps of Engineers' study of hydropower development in the Chickaloon
area be discontinued at this time.
14
•
RECEIVED
OCT 1 1984
AlASAA POWER AlJTHORITY
SMALL SCALE HYDROPOWER FOR NOME, ALASKA
LETTER REPORT
JULY 1984
Alaska District
U.S. Army Corps of Engineers
Pouch 898, NPAEN-PL-P
Anchorage, Alaska
SMALL SCALE HYDROPOWER FOR NOME, ALASKA
JULY 1984
1. Introduction. The evaluation of small hydroelectric systems was
authorized by a 1 October 1976 United States Senate Resolution, which
directeo the U.S. Army Corps of Engineers to determine the feasibility of
installing small prepackaged hydroelectric units in isolated Alaskan
communities.
A May 1981 report on the regional inventory and reconnaissance study for
small hydropower projects in Northwest Alaska by Ottwater Engineers,
identified six potential hydropower sites in the vicinity of Nome,
Alaska. David Creek and Sulphur Creek sites were selected from this list
of sites as having the best potential to serve the Nome electrical
demand, considering site location, geology, hydrology, and topography.
The Nome River site was added to the list based on the field
reconnaissance.
During the week of 27 June through 3 July 1982, an interdisciplinary team
of personnel from the Alaska District and U.S. Fish and Wildlife Service
(FWS) conducted a field reconnaissance of hydrology, geology, structural
engineering, and biology. The team visited the Penny River, Basin Creek,
David Creek, Sulphur Creek, Buster Creek, Osborn Creek, and the Nome
River. Only four sites (Sulphur Creek, David Creek, Nome River, and
Penny River) showed mcderate potential for hydropower development. It
was determined that the Penny River site would encounter problems in the
design and construction of a suitable dam elT'bankment and penstock. The
probable route of the penstock would cross several sloughs and drainage
ditches and would require some benching into hillsides where construction
room is limited. The powerhouse location, due to probable deep alluvium,
would require the powerhouse to be founded upon pilings. A gross head of
less than 50 feet was calculated for this site and the measured
streamflow was 8 cubic feet per second (c.f.s.). Therefore, the Penny
River site was eliminated. Of the seven sites evaluated, David Creek,
Sulphur Creek, and the Nome River sites were selected for further
consideration.
Electricity which could be produced from these sites would be used by the
Nome market area and would result in less use of power provided by diesel
generators. The Nome Joint Utility operates seven diesel-powered
generators with a total installed capacity of 6,968 kilowatts (kW) and a
transmission capability of 4,160 kW. Recent peak power demands of 3,300
kW were experienced on 12 January 1982, and total energy demand in 1981
was lt,354,581 kilowatthours (kWh). Any hydropower generation added to
this system would only offset the use of diesel generation when
hydropower was availablE rather than replace ciesel generation. The
probable lack of hydropower generation in the winter months, when streams
are frozen and electrical demana is hioh, would require that dependable
capacity continue to be supplied by diesel generation.
2. Environmental Synopsis. Wilolife in the Nome area includes terns,
dippers, willow ptarmigan, arctic ground squirrels, and tundra hares.
~,oose are common alono the Nome River and hoof prints, probably belon9in9
to reindeer, were found near the streams in question. One set of rear
tracks, believed to be from a grizzly, wcs discovered along the Nome
River about 1/2-mile upstream from the damsite. For safety reasons, bear
population levels are controlled. Bears that stray into the Nome area
are quickly disposed of. The native corporation maintains a domestic
herd of reindeer for their meat, antlers, and hides.
Aquatic wildlife, in the form of anadromous fish, is present in most of
the rivers and creeks investigated. Portions of these streams offer
excellent spawning substrate and ideal flows for spawning salmon, a
factor which must be considered in locating hydropower facilities. In
addition to pink, chum, and coho salmon, anadromous char, graylin9, and
whitefish are tounc.
No encangered or threatened species were observed or identified in the
study area. No cultural resource survey or inventory has been conducted
nor any detailea environmental analysis of potential impacts made.
3. Description of the Area and Investioations. The study area
encompasses a raaius of approximately 3(; miles from the center of Nome,
as shown on figure 1. The study considered hydropower sites in this area
which could potentially supply the approximately 3,200 people of Nome
with intermittent hydropower to offset the present diesel generation
system. All of the sites, excluding the Penny River site, provided
fairly easy, though long, transmission routes over tundra overlying
grave 1.
4. Hydrology. Fiela inspections of the sites in June/July 1982
established the flow rate of each stream and the physical characteristics
of the sites. No detailed hydrologic information was developed for these
sites. Carre 1 at ion with other gaged stream data was evaluated but not
included in the report due to the significant difference in drainage
areas.
S. Desion Flows. Design flows were assumed to he tre same as the flows
measured in late June and early July 1982. The design flo¥; was used tc
set capacity of the unit( s) at each site. Averaae flow throuah the
unit(s) was expected to be 50 percent of the desig-n flow, because the
flO\'JS in these streans are severely affected by winter freeze and full
operation of the powerp 1 ant can be expected only 6 to 7 months of the
year. Listed below are descriptions of estimated design fl0\<1S.
a. f>iome River. The Nome River site is located approximately 23
miles northwest ot 1\orr,e, about l mile below the confluence of Sulphur
Creek (see figure 1). The Nome River drainage basin encompasses 28
square miles. Field measurements indicate a design flow of 196 c.f.s.
2
..
n • DAM
POWERHOUSE
3
, .... ,. 1
NOME, ALASKA
Sm•ll Hydropower
Letter Report
SITES INVESTIGATED
Alaeka Dletrlct, Corp• of Entlneere
b. Sulphur Creek. The Sulphur Creek site is located ahout l rri l e
upstream-from its confluence with the Nome River (see figure 1). Sulphur
Creek 1 s drainage basin encompasses 4 square miles. Field measurements
indicate a design flow of 33 c.f.s.
c. David Creek Site. The David Creek site is approxi!Tlately 32 miles
north of Nome and 1. 5 mi 1 es upstream from the confluence of the Nome
River. The Davie Creek drainage basin encompasses 2.1 miles. Field
measurements indicate a design flow of 23 c.f.s.
6. Energy Use. The electrical needs of Nome are met by the Nome Joint
Utility from diesel electric generation. Nome's electrical usage has
grown 3.2 percent annually from 1978 to 1981 as derived from the usa9e
values shown below:
,981 -16,354,581 k~h (kilowatt hours)
1980 -15,738,600 kWh
1979-14,917,367 kWh
1978 -14,419,200 kWh
Continued growth can be expected to accelerate occasionally by increases
in golG mining or other commercial activities. Certainly, the existinc;J
and future electrical demand would support the construction of hydropower
facilities of about l megawatt (MW) if operating such a hydropower
development was n,ore economical than operating the existing diesel system.
7. Energy Analysis. Energy developed by any hydropower plant in the
Nome vicinity would be used to offset diesel generation. Hydropower
generation could be expected only in the warm months of the year when
streams are ice free. Accordingly, the winter electrical derrand must
continue to be met by diesel generation. Hydropower generation is
expected to occur 6 to 7 months of the year. Based on the des i gr. flow
ciescribed earlier, one plant size was formulated for each site. The
following is pertinent generation information for the three sites:
Site
Nome River
Sulphur Creek
David Creek
Design
F 1 0\'1
196 c.f.s.
33 c. f. s.
23 c.f.s.
Design
Head
33 feet
55.5 feet
151.5 feet
Annual
Installed _l/ Energy
Capa.c ity Gutput 2/
460 kW 1,853,600 kWh
130 kW 523,900 kWh
250 kW 1,007,400 kWh
1/Installed capacity is based on the following formulas:
Design Flow (c.f.s.) x Design Head (feet) x 0.072 (conversion factor
incl~ding an 85 percent plant efficiency) capacity in kW
l!Energy output is based on the following formulas:
Installed Capacity (kW) x 0.5 plant factor x 8,760 hrs/yr x (100
percent -8 percent transmission loss) ~ Annual Energy Output (kWh)
4
8. Benefit Analysis. Benefits attributable to the proposed hydropower
developments are limited to the avoided cost of diesel generation.
Hydropower benefits do not include value of capacity because the
hydropower could contribute no capacity (i.e. would not be dependable)
ouring the high demand period in the winter. The avoided cost,
considered the variable cost of operating diesel generators, is
essentially the cost of fuel and lubricating oil. While maintenance and
replacement would also be reduced or. the diesel units, operation ancl
maintenance would be experienced on the hydropower units. For purposes
of this estimate, no benefit is taken for reduced maintenance and
replacement of diesel generation and no cost is ascribed to operation and
maintenance of hydropower generation, assuming they would be very nearly
equal ana cancel one another. Representatives of Nome Joint Utility
provided data on fuel costs, lubricating oil usage, and diesel fuel usage
versus electrical generation for the period 1978 through mid-1982 and for
May 1984.
The average May 1984 variable cost of diesel generation is 90.8
mills/kWh. This cost was determined using figures supplied by Nome Joint
Utility: base (t'1ay 1984) prices of $1.176 per gallon for diesel oil and
$4.10 per gallon for lubricating oil, and production ratios of 13.2 kWh
per gallon cf fuel oil and 2,340 kWh per gallon of lubricating oil. Data
Resources, Inc., predicts that real fuel costs in northwestern Alaska
will escalate annually by 1.6 percent to 1990, 3.6 percent to 1995, 3.4
percent to year 2000, 1. 6 percent to 2010, and then remain constant the
remainder of the project life. The following table shows the impact of
real fuel cost escalation on the variable cost of diesel electric
generation over the life of the project.
Year
1984
1995
2000
2005
2010
2045
NOME DIESEL GENERATING COSTS
Variable Costs
(mills/kWh)
90.8
119. 2
140.9
152.5
165. 1
165. 1
An average annual variable electric generating cost was computed from
this data for use as a measure of the power benefits. The average annual
cost of 149.3 mills/kWh represents the value at project year one, 1995,
including real fuel cost escalation for the period 1984 to 2045
discounted by present worth methods and amortized over the 50-year
project life at 8-1/8 percent interest. This average annual cost is
applied to the output ot each of the hydropower a.lternatives to i~dicate
the value of avoided costs of diesel generat1on, as shown 1n the
following table.
5
Project
Nome River
Sulphur Creek
David Creek
Three-Project
AVERAGE ANNUAL BENEFITS OF HYDROPO~ER
(Value of Avoided Diesel Generation Costs)
Value of Output
Output (kWh) (mills/kWh)
1,853,600 149.3
523,900 149.3
1,007,400 149.3
Combination 3,384,900 149.3
Annual
Benefit
$276,700
78,200
150,400
505,300
9. Cost Analysis. A pre 1 imi nary cost estimate was derived for one plant
size on each of the streams described in paragraph 5, Design Flows.
Preliminar} costs were also aeveloped for an alternative plan which
incorporated developing all three sites and utilizing one transmission
line to the Nome market. The following paragraphs describe the features
and cost of the four hydropower plans.
a. 1\ome River Hydropower Plan. This plan is located belov: the
confluence of Sulphur Creek in Nome River Valley, which measures about
600 feet across at water· level. The old Miocene Ditch, a v.;ater supply
ditch for early mining operations, runs along the west side of the
river. The plan includes a 40-foot high, 700-fcot long roller compacted
concrete darn founded on bedrock, a 60-i nch diameter penstock, a
powerhouse with 460-kW i nsta 11 ed capacity, and a 23-mi l e t ransrni ss ion
line. The penstock was sized to ccommodate a flow of 196 c.f.s. at 85
percent efficiency, the dam ~ould produce 35 feet of gross head, and the
powerhouse was sized to produce a peak capacity of 460 MW at 85 percent
efficiency and net head of 33 feet. The following items are includec ir
the cost estimate: a roller-compacted concrete dam, a 200-foot steel
penstock, a roac relocation of .5 mile, 23 miles of transmission line,
the powerhouse plus associated features, intake structure, diversion,
helicopter support during construction site preparation, and mobilization
and demobilization. The cost estimate was based on a 25-percent
contingency allowance; 18 percent for engineerin9 and design, and
supervision and administration; and interest during construction based on
a 2-year construction perioG. Costs were amortized usino an interest
rate of 8-l/8 percent and a 50-year project life. This -cost estimate
does not incluoe operation ana maintenance costs. Shewn below is a
summary of the estimated cost. A detailed cost breakdown is shorm on
exhibit 1 and the plan is shown on figure 2.
Plant Size {kW) First Code Investment Costs 1/ Annual Costs 11
460 $13,000~000 $14,066,000 $1~ 166,000
1 Investment costs include construction costs plus interest ouring
the 2-year construction period computed at 8-l/8 percent annually.
!:._!Annual costs inc 1 uoe the arrort i zed i nvestrnent costs computed as an
annual cost over 50 years at 8-1/8 percent interest, but exclude
operation and maintenance costs.
6
7
t
I
Kuparak Road
Nome River
Dam
Penstock
Powerhouse
Transmission
Line
----
Figure 2
IIOME Rl¥.11
Small Hydropower
b. Sulphur Creek Hydropower Plan. This plan is located on the
lower length of Sulphur Creek below the confluence of its feeder streams,
Alfield and Monte Cristo Creeks. 1his lower part of Sulphur Creek is
approximately 1 mile long. The plan includes a diversion dam located in
a fairl.Y steep sided reach of the creek slightly over 1 mile from the
mouth, a penstock 36 inches in diameter running along the south bank of
the creek, a powE:rhcuse of 130-kW installed capacity approximately 1,000
feet upstream of the mouth, and a 29-mile transmission line. The
diversion dam, penstock, and powerhouse were sited and sized to
accommodate, at 85 percent efficiency, a flow of 33 c.f.s. with a gross
head of 60 teet ana linlit penstock flow velocities to 5 feet per second
(f.p.s.) and head losses to 4.5 feet. The cost estimate is made up of
the follo~ing items: an Ambursen-type treated wood dam, an intake
structure, a 2,640-foot polyethylene penstock, a 1-mile access road, 29
miles of transrrlission line, the powerhouse plus associated features,
diversion of water and helicopter support during construction site
preparation, and mobilization and demobilization. The cost estimate was
based on a 25-percent contingency allowance; 18 percent for engineering
and design, and supervision and aoministration; and interest during
construction based on a 2-year construction period. Costs were amortized
using an interest rate of 8-1/8 percent and a 50-year project life. This
cost estimate, which does not include operation and maintenance costs, is
shown on exhibit 2 and the plan is shown on figure 3.
Plant Size (kW) First Code Investment Costs 1/ Annual Costs 2/
130 $8,710,000 $9,424,000 $781,000
]/Investment costs include cor.struction costs plus interest during
the 2-year construction period computed at 8-1/8 percent annually.
l!Annual costs include the amortized investment costs computed as an
annual cost over 50 years at 8-1/8 percent interest, but exclude
operation and maintenance costs.
c. David Creek Hydropo~er Plan. This plan is located on the lower
3-mile reach of David Creek. The creek flow would be diverted from a
narrow porticn ot the creek valley where the abutments rise steeply from
the stream bed with high dam diversion structure, a 36-inch diameter
penstock b~r.ched into the left bank of the creek, a powerhouse of 250-kW
installed capacity at the mouth, and a 32-mile transmission line. The
plan -was sited and sized to accommodate, with an 85-percent efficiency,
23 c.f.s. of flow and a gross head of 158 feet. It would limit flo~'
velocities to 3.5 f.p.s., and head losses tc 6.5 feet. The ccst estimate
is made up of the following items: an Ambursen-type treated wood dam and
intake structure, a 7,920-foot polyethylene penstock, a 1.5-mile access
~oad, 32 miles of transmission line, the powerhouse plus associated
featur'es, civersion, helicopter support during construction site
preparation, and mobilization and demobilization. The cost estimate was
based on a 25-percent contingency allowance; 18 percent for engineering
8
Dam
~tf~~~~~~ Penstock ~~~~~~~~-Powerhouse
f
I
~'--~-+H-"".._~f.,l.l.,~-K up a r a k Road
Transmission
Line
Nome River
----
Figure 3
SULPHUR CRI!I!K
9
ana design, ano supervision and administration; and interest during
construction based on a 2-year construction period. Costs were amortized
using an interest rate of 8-1;8 percent and a 50-year project life. This
cost estimate does not include operation and maintenance costs. Shown
belov. is a sun1mary of the estimateo costs. A detailed breakdown of costs
is shown on exhibit 3 and the plan is shown in figure 4.
Plant Size (kw) First Lost Investment Costs ll Annual Costs ll
250 $11,600,000 $12,551,000 $1,040,000
l/Investment costs include construction costs plus interest curing
the 2-year construction period computed at 8-1/8 percent annually .
.. ?/Annual costs include the amortized investment costs computed as an
annual cost over 50 years at 8-1/8 percent interest, but exclude
operation and maintenance costs.
d. Three-Site Systerr:s. A fourth plan considered combining the
generation of all three sites -Nome River, Sulphur Creek, and David
Creek -and sharing a single transmission 1 ine cost. The cost for
transmission includes a line connecting the three sites with an existing
line along the Nome-Council Coast road. The cost estimate was based on a
25-percent contingency allowance; 18 percent for engineering and design,
and supervision and administration; and interest durin9 construction
based on a 2-year construction period. Costs were amortized using an
interest rate of 8-1/8 percent and a 50-year project life. This cost
estimate does not include operation and maintenance costs.
DETAILED COST ESTIMATE
Item/Description
Mobilization and Demobilization J./
Cam and Intake Structure
Penstock ]j
Powerhouse l/
Transmission Line
Unimproved Dirt Road
Diversion
Subtotal
Contingency (25%)
Engineering ana Design (10%)
Supervision and J.l.dministration (8,~)
Total First Cost
Rounded to
l/Includes site preparation, helicopter support
mobilization and demobilization. Assumes the same
demobilization will accornrrodate all three sites. ~/Includes cost of pipe, installation, bends.
1/rncludes cost for structure, turbine, generator,
features.
10
Tot 1
$1,600,000
3,463,800
2,361,720
2,300,000
3,588,000
184,750
54,200
$13,552,470
3,388,120
1,694,060
1,355,250
$19,989,900
$19,990,000
for E months,
mobilization and
and associated
~..u-~...lp.-Dam
~~~~~~~~~--Penstock
t
I
Powerhouse
Nome River
Kuparak Road
----
Figure 4
AVID CR •• K
Small Hydropower
11
The ; nvestment cost was computed at 8-1/8 percent annua 1 interest ever a
2-year construction period. Annual co~ts are the investm~nt costs
amortized over 50 years at 8-1/8 percent 1nterest. The three-s1te system
plan is shown on figure 5, and a summary of costs is shown below:
Plant Size {kW) First Cost Investment Costs ll Annual Costs~/
8L . $19,990,000 $21,629,000 $1,793,000
l!Investment costs include construction costs plus interest during
the 2-year construction period computed at 8-1/8 percent annually.
~I Annua 1 costs inc 1 ude the amortized investment costs computed as an
annual cost over 50 years at 8-1/8 percent interest, but exclude
operation and maintenance costs.
10. Evaluation. The following table summarizes the comparison of
annual costs and benefits computed at 8-1/8 percent interest for a
50-year project life ana a power-on-line date of 1995.
Benefit
Output Annual Investment Annual Net to Cost
Plan (kWh) Benefit Cost Cost Benefit Ratio
Nome River 1,853,600 $276,700 $14,066,000 $1,166,000 -$ 889,300
Sulphur Creek 523,900 $ 78,200 $ 9,424,000 $ 781,000 -$ 702,800
David Creek 1, 007' 400 $150,400 $12,551,000 $1,040,000 -$ 889,600
Three-Site System 3,384,900 $505,300 $21,629,000 $1,793,000 -$1,287,700
11. Conclusion. As displayed above, none of the proposed plans were
found feasible. The lack of benefits to cover the costs was so great
that no amount of prcject redesign or combination of plans would be
expected to produce an economically feasible project. Hydroelectric
energy would be available only 6 or 7 months a year, not during the high
demand periods of winter. Accordingly, the existing diesel generation
systE:m woulo have to be operated, and hydrogeneration would only offset
variable costs of diesel generation. The results of the above analysis
were compared against synthetic flovJS derived from the Snake River and
Crater Lake, on the Seward Peninsula, and were found to be conservative.
The S)nthetic streamflow data are available from the Corps of Engineers,
Alaska District.
12. Recommenaations. None of the hydroelectric plans studied for Nome,
Alaska is capable of recovering its estimated costs over its project
life. No further study by the Corps of Engneers is recommended at this
time.
12
0.24
0. 10
0. 14
0.28
13
Figure 5
THREE SITE
SYSTEM
Small Hydropower
NOME RIVER (460 kW)
Detailed Cost Estimate -May 1984 Price Levels
I tern/Description
Mob and Demobl/
Dam and Intake Structure
Excavation
Excavation, Rock
Roller Compacted Concrete
Dam
Cone rete
Steel, Rebar, & Misc.
Cutoff Wall -Concrete
Total Dam and Intake Structure
Penstock
60" Diameter 1/4 11 Steel Pipe
Concrete Supports
Rock Anchors
Total Penstock
Powerhouse
S true ture
Turbine Generatorl/
Total Powerhouse
Transmission Line
13.8 KV Line
Clearing
Total Transmission Line
Unimproved Dirt Road
Access Road
Clearing
Total Unimproved Dirt Road
Quantity
1
31,000
60
27,000
110
81,000
1 '500
200
20
120
1
1
23
55.8
.5
• 7
Unit
1. s.
c.y.
c. y.
c.y.
c.y.
1. b.
c. y.
l.f.
c. Y•
1. f.
ea.
1. s.
Unit Price
18
50
38
800
2
800
210.?_/
800
6
miles 100,000
acres 5, 000
miles
acres
54' 2 50
5,000
Total
$1,600,000
$558,000
3,000
1,026,000
88,000
162,000
1,200,000
$3,037,000
$42 ,ooo
16,000
720
$58,720
$375,000
1' 100 ,ooo
$1,475,000
$2' 300,000
279,000
$2,579,000
$27' 125
3,500
$30,625
l/Includes site preparation, helicopter support for 6 months, mobilization
and demobilization.
2/Includes cost of steel pipe, installation, bends.
J/Includes cost of accessory electrical, auxiliary system and equipment, and
swTtchyard •
. EXHIBIT 1
14
NOME RIVER {460 kW) (continued)
Item/Description
Divers ion
Quantity
60 11 Diameter 1/4" Steel Pipe
Sub tot a 1
Contingency (251.)
Engineering and Design (10%)
Supervision and Administration (8%)
Total First Cost
20
Unit
1. f.
ANNUAL COSTS AND BENEFITS
Investment Cost (incl. interest during construction)
Interest and Amortization (8-1/8% at 50 years)
Annual Benefits
Benefit-Cost Ratio
Net Annual Benefit
Dam Height (feet)
Penstock Length (feet)
Penstock Diameter (inches)
Transmission Line Length (miles)
Road Relocation Length (miles)
Design Head (feet)
EXHIBIT 1 (cont.)
PERTINENT DATA
15
Unit Price
210
Total
$4,200
$8,784,545
$2,196,455
$1,098,000
$13,000,000
$14,066,000
$1,166,000
$276,700
0.24
$-889,300
40
200
60
23 .s
33
SULPHUR CREEK (130 kW)
Detailed Cost Estimate -May 1984 Price Levels
Item/Description
Mob and Demob.!J
Dam and Intake Structure
Excavation
Excavation, Rock
Wood, Dam, and Intake
Steel, Rebar and Misc.
Total Dam and Intake Structure
Penstock
36" Diameter Polyethylene Pipe
Steel Supports
Rock Anchors
Total Penstock
Powerhouse
Structure
Turbine Generator~/
Total Powerhouse
Transmission Line
13.8 KV Line
Clearing
Total Transmission Line
Unimproved Dirt Road
Access Road
Clearing
Total Unimproved Dirt Road
Quantity
1
600
200
1
1
2,640
600
1,200
1
1
29
70. 3
l
1.5
Unit
1. s.
c.y.
c. y.
l.s.
l.s.
l.f.
1. b.
1. f.
ea.
1. s.
Unit Price
18
so
215'!:_/
2
6
miles 100,000
acres 5,000
miles
acres
54,250
5,000
Total
$1,600,000
$10,800
10,000
32,000
16,000
$68 '800
$567,000
1 '200
71 200
$576,000
$75,000
250,000
$325,000
$2,900,000
351,500
$3' 25 l '500
$ 54,250
l/Includes site preparation, helicopter support for 6 months, mobilization
and demobilization.
~/Includes cost of polyethylene pipe, installation, bends.
3/Includes cost of accessory electrical, auxiliary system and equipment, and
switchyard.
EXHIBIT 2
16
SULPHER CREEK (130 kW) (continued)
Item/Description Quantity
Diversion
Subtotal
Contingency (25%)
Engineering and Design (10%)
Supervision and Administration (8%)
Total First Cost
1
Unit
1. s.
ANNUAL COSTS AND BENEFITS
Investment Cost (incl. interest during construction)
Interest and Amortization (8-1/81. at 50 years)
Annua 1 Benefits
Benefit-Cost Ratio
Net Annual Benefit
Dam Height (feet)
Penstock Length (feet)
Penstock Diameter (inches)
Transmission Line Length (miles)
Access Road Length (miles)
Design Head (feet)
EXHIBIT 2 (cont.)
PERTINENT DATA
17
Unit Price Total
$25,000
$5,908,050
$1,477,950
$738,000
$591,000
$8,710,000
$9,424,000
$781,000
$78,200
0.10
$-702,800
10
2,540
35
29
1
55.5
DAVID CREEK (250 kW)
Detailed Cost Estimate -May 1984 Price Levels
Item/Description
Mob and Demob!_/
Dam and Intake S true tu re
Excavation
Excavation, Rock
Wood, Dam, and Intake
Steel, Rebar and Misc.
Cutoff Wall -Concrete
Total Dam and Intake Structure
Penstock
36 11 Diameter Polyethylene Pipe
Steel Supports
Rock Anchors
Total Penstock
Powerhouse
Structure
Turbine Generator~/
Total Powerhouse
Transmission Line
13.8 KV Line
Clearing
Total Transmission Line
Unimproved Dirt Road
Access Road
Clearing
Total Unimproved Dirt Road
Quantity
1,000
600
1
1
150
7,920
1 '900
3,400
1
1
32
77.6
1.5
2.2
Unit
1. 5.
c.y.
c.y.
1. s.
1. s.
c.y.
1. f.
1. b.
l.f.
ea.
1. s.
Unit Price
18
50
800
2153../
2
6
miles 100,000
acres 5,000
miles
acres
54' 2 50
5,000
Total
$1,600,000
$18,000
30,000
12 7 '000
63,000
120z000
$358,000
$1,702,800
3,800
20,400
$1 '727 ,000
$62,500
437,500
$500,000
$3,200,000
388,000
$3 '588 '000
$ 81, 375
111000
$92,375
l/Includes site preparation, helicopter support for 6 months, mobilization
and demobilization.
~/Includes cost of polyethylene pipe, installation, bends.
3/Includes cost of accessory electrical, auxiliary system and equipment, and
swTtchyard.
EXHIBIT 3
18
DAVID CREEK (130 kW) (continued)
I tern/Description Quantity
Diversion
Sub tot a 1
Contingency (25%)
Engineering and Design (10%)
Supervision and Administration (8%)
Total First Cost
1
Unit
l.s.
ANNUAL COSTS AND BENEFITS
Investment Cost (incl. interest during construction)
Interest and Amortization (8-1/8% at 50 years)
Annual Benefits
Benefit-Cost Ratio
Net Annual Benefit
Dam Height (feet)
Penstock Length (feet)
Penstock Diameter (inches)
Transmission Line Length (miles)
Access Road Length (miles)
Design Head (feet)
EXHIBIT 3 (cont.)
PERTINENT DATA
19
Unit Price Total
$25,000
$7,890,375
$1,972,625
$987,000
$750,000
$11 '600 '000
$12,551,000
$1,040,000
$150,400
0.14
$-889 '600
20
7,920
36
32
1.5
151.5
HYDROPOWER LETTER REPORT
GALENA, ALASKA
July, 1984
INTRODUCTION
RECEIVED
OCT 1 1984
ALASKA POWER AUTHORITY
The evaluation of small hydroelectric systems was authorized by a
1 October 1976 United States Senate Resolution, which directed the U.S. Army
Corps of Engineers to determine the feasibility of installing small prepackaged
hydroelectric units in isolated Alaska communities.
In 1981, a regional inventory and reconnaissance study for small
hydropower projects in Northwest Alaska was completed for the Alaska
District, Corps of Engineers by Ott Water Engineers, Inc. This was one of a
series of similar studies directed at identifying potential small hydropower
development for isolated communities throughout Alaska. As a result of the
preliminary findings in this study, Galena was one of the sites selected by the
Alaska District for further analysis.
SITE INFORMATION
STUDY AREA
Galena is located on the north bank of the Yukon River approximately 20
miles east of the confluence of the Koyukuk and the Yukon. It is 270 air miles
directly west of Fairbanks and lies in the Koyukuk Lowland, a flat floodplain
characterized by muskeg, sloughs, oxbow lakes, marsh and thaw lakes.
Because of the local availaility of gravel, the military built an air field
and Air Force base in Galena, and the size of the community has grown
steadily since 1950. The village was severely flooded in 1971, and in 197 5
development of a new town site began three miles away.
- 1 -
.._-LOCATION BEGINNING OF
MAP EXISTING
TRANSMISSION
UNE
\
GALENA
TRANSMISSION UNE RWTE ______ _....
FIGURE I
~ALA CREEK ~RO
SITE MAP
LEGEND
-=-=-= = =:. UN\t.PROVED ROAD
==~MPROVED R<W>·
2
+ N
~
In 1981 (1) there were 174 residents at the old site, and 287 residents at
the new site. The village is approximately two-thirds native. There are 198
housing units in the new and old sites. The school and city offices are located
in the new site, while the post office and hotel are in the old site. (There are
299 military personnel and 45 civilians at the U.S. Air Force Base.) A
population forecast for the proposed study period (1990-2040) indicates a
population in the year 2040 of approximately 1800.
Galena's economy centers around its function as a regional "hub": state
and federal agencies locate field representatives here, and the community is a
transportation center for the surrounding villages. The U.S. Air Force Base is
also an economic influence on Galena, employing some residents and drawing
visitors to the village. Subsistence plays a role in many residents' lives, with
salmon fishing in the Yukon during summer and trapping in winter. In 1981,
the school employed 18; the city, 7; the clinic, 20; Village Corporation (Gana-
A-Yoo), 5-8; contractors, 2-3; a sawmill, 2 winter, 4 summer; Huntington
Fisheries, 20-30 summer only. There are about 20 unemployed. Services
include a post office, magistrate, state troopers, BLM fire base, FAA, state
public works (aviation), a fire department, two air taxi operators, three stores,
and a hotel. Miners use Galena as a supply point.
Galena was incorporated as a second class city in 1971, and as a first
class city in 1976, and functions under a city council -manager and mayor
government, elections being held annually the first Tuesday in October. The
city has a 3 percent sales tax. Municipality owned facilities include water,
refuse collection, and sewer. There is a school board, a planning and zoning
commission, and several city employees, including a manager, clerk/treasurer,
attorney, police chief, fire chief, and health coordinator. The native residents
of Galena are shareholders in Gana-A-Yoo Corporation, incorporated in
accordance with the terms of the Alaska Native Claims Settlement Act.
(1) Taken from Reconnaissance Study of Energy Requirements and
Alternatives, May 1982. Prepared by Acres American for the Alaska
Power Authority.
-3-
Galena is a regional transportation center with a 6,665 foot paved
runway. The FAA maintains air traffic control and is equipped for instrument
approach. Wien flies to Galena five days a week from Fairbanks and
Anchorage, and Galena Air and Harold's Air are both based in Galena. There
are no roads to Galena and passengers, mail, and cargo arrive by air. J\arge
service is performed on a weekly basis in summer by Yutana Barge Lines.
Residents use river boats in summer and snowmachines in winter to travel
around the area.
On 12-13 July 1982, an interdisciplinary study team from the Alaska
District conducted a field reconnaissance of a potential small hydropower site
near the City of Galena. The site is located on Kala Creek, south of the
Yukon River and about 15 miles southeast of Galena.
HYDROLOGY
The Kala Creek basin extends from the foothills of the Karjuh Mountains
in the south to the Yukon River in the north. Upstream of the damsite, the
channel is contained in a narrow valley falling at a gradient of approximately
25 feet per mile. The remaining four miles to the Yukon is in a relatively flat
swamp tundra plain. The proposed dam site is located at the northernmost
point of the valley just downstream of the Kelly Creek confluence.
From the dam site upstream, the creek is generally uniform in section.
The channel bed consists of well graded gravels 0/8-12 inches), sand and
some silts. The water was very clean at the time of the site visit, indicating a
low suspended particle load. The larger rocks were covered with moss and
there was no evidence of recent bed displacement. These are indications of
moderate velocities and no recent extremely high peak discharges. There are
a number of curves in the channel with gravel bars inside and steeper banks
outside. There was no evidence of recent or regular overbank flow. The banks
appeared to be stable with little evidence of erosion. This also indicated that
peak discharges are not excessively high or fast. There was very little debris
accumulation along the banks or in shallows. There were very few large armor
type rocks in the channel or along the banks. Except at outcrops, the entire
basin is covered with vegetation that included grasses, willows, and birch and
spruce trees. The ridge slopes are generally moderate.
-4-
YEAR
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
1975
1976
1977
Avg.
DESIGN FLOWS
Discharge data for the Kala Creek site has been synthesized by the
Alaska District, Corps of Engineers, as no measured data exists for this site.
The summary of monthly streamflow is presented in Table 1.
Table 1
Unregulated Streamflow -CFS
OCT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG SEP
192.
151.
44.
37.
35.
23.
44.
148.
113.
152.
139.
122.
79.
86.
97.
3. 31. 15. 9. 21. 30. 303. 582. 186. 136. 95.
26. 7. 11. 36. 19. 39. 866. 1087. 205. 407. 827.
41. 31. 5. 10. 9. 12. 1419. 356. 121. 194. 104.
46. 11. 3. 20. 26. 28. 250. 457. 314. 581. 176.
45. 37. 11. 4. 7. 12. 689. 130. 130. 255. 102.
14. 15. 7. 13. 5. I. 428. 231. 129. 96. 21.
18. 12. 3. 3. 9. 7. 574. 514. 207. 497. II 0.
46. 30. 13. 4. 2. 24. 490. 731. 180. 237. 222.
34. 22. 6. 34. 7. 29. 115. 755. 114. 174. 427.
23. 23. 20. 1. 11. 9. 1033. 620. 154. 395. 143.
48. 5. 7. 2. 1 o. 5. 115. 740. 183. 267. 350.
26. 6. 6. 8. 4. 5. 1033. 673. 102. 160. 502.
14. 18. 5. 7. 4. 7. 636. 437. 103. 62. 163.
80. 8. 11. 7. 8. 24. 407. 462. 122. 193. 613.
33. 18. 9. ll. 10. 17. 597. 555. 161. 261. 290.
GEOLOGY
The site is in a restricted portion of Kala Creek valley. The stream is
about 100 feet wide and flows at the base of a 200-foot high, steep rock slope
on the east side of the floodplain. Westward from the creek the axis crosses a
moderately sloping, open tundra area several hundred feet wide and abuts a
steep rock slope which rises more than 300 feet above the floodplain.
-5-
AVERAGE
133.
307.
196.
162.
121.
82.
166.
177.
152.
215.
!56.
221.
145.
168.
172.
The alluvium of the floodplain is gravel and boulders at the site. The
size of the alluvial material increases in an upstream direction to become
mostly boulders and decreases to a fine silt downstream near the mouth of the
creek.
Bedrock at the site is of Cretaceous age and is chiefly graywacke which
is massive bedded, fractured, jointed, contains numerous quartz veins, and dips
almost vertically upstream. The strike at the site is N 50° E. Thick sequences
of this graywacke occur on both abutments. Shale beds are also present and
are visible on the east side of the creek.
Penstock construction for this project would depend upon the size of the
dam chosen. For a high head dam, the powerhouse could be an underground
structure in the east abutment with a tunnel penstock; or, if the powerhouse
were located in the floodplain near the west abutment, the penstock could pass
along the west side of the floodplain to a powerhouse location some distance
downstream. The route of the penstock and the powerhouse would be on
alluvial materials. The alluvium, except near the stream, probably contains
permafrost.
ENVIRONMENTAL SYNOPSIS
Construction of a 100 to 150-ft. dam would create a reservoir with a
maximum surface area of 1300 to 2500 acres, and would back up Kala Creek 5
to 6 miles, and Kelly Creek 2 to 3 miles. Several small tributaries would also
be affected. Some change in the food chain would occur due to the dam and
flooded area. This change is not quantifiable without extensive study but is
estimated to be relatively minor.
Wildlife and habitat distributions within the Kala and Kelly Creek
drainages range in densities from "occasional" to "present". The Yukon River
Floodplain would not be significantly impacted by the construction of the
-6-
transmission line and a winter access road. However, high densities of some
species are present. Wildlife and habitat distributions for both areas are listed
below. (Source: Alaska's Wildlife and Habitat, Vol. I 0973) and Vol II (1978).
State of Alaska, Dept. of Fish and Game.)
P = PRESENT H.D. = HIGH DENSITY
Species Yukon River Kala & Kelly: Creek
Bear (Black, Grizzly) p p
Beaver p p
Coyote p p
Fox (Red) H.D. p
Grouse (Sharp-tailed, Ruffed,
and Spruce)) p p
Hare (Snowshoe) p p
Lynx p p
Marmot 0
Marten p p
Mink H.D. p
Moose p p
Muskrat H.D. p
Otter (Land) p p
Porcupine p p
Ptarmigan (Rock, Willow) p p
Squirrel (Red, Flying, Arctic Ground) p p
Waterfowl and Seabirds p
Weasel H.D. p
Wolf p p
Wolverine p p
The project site is in an area of sporadic permafrost. Although no site-
specific geotechnical information is available, it should be recognized that the
potential exists for problems relating to thaw settlement and thermal erosion.
-7-
A rockfill dam, rather than a rigid structure such as concrete, should suffer
relatively minor effects even if thermal degradation were to occur as a result
of the reservoir acting as a heat sink. The powerhouse and switchyard would
be located in the floodplain, which is composed primarily of gravels and
cobbles, and normal sub-Arctic foundation construction should provide
adequate protection against frost heaves or differential settlement. The most
likely problem areas in terms of frozen ground conditions would be the
transmission line and the river crossing. The potential problems associated
with the river crossing, in particular, are dramatically demonstrated by the
on-going bank erosion problems at Galena. /\ thorough geotechnical
investigation would be required prior to the design of this facility, to
determine the location and extent of such problem areas.
ENERGY CONSIDERATIONS
AVAILABLE POWER
Two sources of power presently exist for the Galena area. The Galena
Air Force Base supplies its own power with three 600KW units and one 300KW
unit. The City of Galena is supplied by M & D Electric Company with two
250KW units and one 135 KW unit. All line voltage is 2400 volts, three-phase,
at 60 hz. In addition, the school district maintains a standby 125 kw unit. All
energy is produced by diesel fuel.
ENERGY USE
Energy forecasts through 2040 are shown in Table 2. Records supplied by
the U.S. Air Force Base and M &: D Electric support the forecasts and are
summarized in Table 3. Population (and thus energy use) on the Air Force
Base is not expected to increase; and according to records supplied, daily
demand ranges from 300 kw to 1000 kw. The village is expected to grow at an
annual rate of 5% through 1991 and 272% thereafter. Peak load is about 300
kw. (Alaska Power Authority, 1982).
- 8 -
POWER POTENTIAL OF KALA CREEK
Table 6 summarizes the results of reservoir release simulations for the
three dam height options. The program HEC-5 was used to optimize the
dependable capacities based on average observed monthly plant factors and
the critical drawdown period, as determined by the program from the 14 years
of synthesized data (Table l).
The 100-and 125-ft. dams were found to yield no dependable capacity;
that is, sufficient storage was not available to provide any level of continuous
power. The average monthly outputs in Table 4 assumed installed capacities
of 650 and 850 kw, respectively, which are based on a rated discharge of 100
cfs and rated heads of 90 and 115 ft., respectively. Reservoir releases were
made only when the pool elevation exceeded a specified "buffer level". (El.
255 and 270, respectively). This allowed power generation for heads as low as
60% of the rated head, and also provided for sedimentation control at the
intake.
The 150-ft. dam yielded a dependable capacity of 852 kw. The
assumption of a plant factor of 0.6 resulted in an installed capacity of 1420
kw. The rated discharge was 136 cfs, and the rated head, 140 ft. Reservoir
releases were made only when the pool elevation exceeded 290.
-9-
Table 2
Projected Energy Demand (MWh/year)
Year U.S. AFB Galena Total
1982 6000 1106 7106
1987 6000 1502 7502
1990 6000 1812 7812
2000 6000 2863 8863
2010 6000 3600 9600
2020 6000 4120 10120
2030 6000 4430 10430
2040 6000 4610 10610
Table 3
Galena Average Monthly Energy Demand (KWh/Month)
Month U.S. AFB** Galena* Total %Annual
January 563,760 135,360 699,120 10.2
February 514,560 126,240 640,800 9.4
March 517,380 79,680 597,060 8.7
April 470,533 99,480 570,010 8.3
May 412,700 82,200 494,900 7.2
June 396,367 63,600 459,970 6.7
July 387,800 59,400 447,200 6.5
August 406,200 72,480 478,680 7.0
September 420,320 104,760 525,080 7.7
October 484,840 99,360 584,200 8.6
November 511,920 112,080 624,000 9.1
December 578,040 136,920 714,960 10.5
5,664,420 1' 171,560 6,835,980
* Based on limited data (1980 & 1981) from M & D Operator
** Based on average demands for the period April 1977 through June 1982.
-10-
Table 4
Average Annual Energy, Potential and Usable (MWH)
100' DAM 125' DAM 150' DAM
DEMAND(I) POT'L (2) USABLE(3) POT'L USABLE POT'L USABLE
JAN 971 311 311 676 676 784 784
FEB 895 0 0 605 605 700 700
MAR 828 0 0 462 462 678 687
APR 790 0 0 0 0 631 631
MAY 685 473 473 526 526 677 677
JUN 638 509 509 603 603 891 638
JUL 619 508 508 627 619 1022 619
AUG 666 547 547 701 666 1183 666
SEP 733 538 538 688 688 1052 733
OCT 819 550 550 709 709 955 819
NOV 866 524 524 702 702 711 711
DEC 1000 499 499 677 677 809 809
4502 4502 6976 6933 10093 8465
INSTALLED CAPACITY 650 KW 850 KW 1420 KW
DEPENDABLE CAPACITY 0 0 852 KW
(1) Annual Equivalent Demand, derived from energy forecasts (1990 to 2040) from
Table 2 and monthly distributions from Table 3.
(2) Potential Energy calculated using HEC-5.
(3) Usable Energy is the lesser of Demand and Potential.
-11-
0,
II -1 /
""' I ~-" / " \ g-; '"'-.. I
' 8l ~ ~ I
I
I , 7 -G)
C I G ~ ~ ~ "' --""""""'---------
r\) 5
""
~~ ....... _
;r \ 4-i I
\ /' I
3-i \ \ /' ENERGY DEMANDED, AVG. ANN. EQ.
\ I ENERGY DEMANDED, 1990 (POL) \ \ /t 2-1 \
I
\ I -----ENERGY GENERATED, 100 DAM
\ \ /t --ENERGY GENERATED, 125' DAM
\ v,' ---ENERGY GENERATED, 150' DAM
\ \_ _____ _)
__ r-"l ___ -· ·-· ._. •
~~··· ······--·· -. -···· -~ i T I I I I I I I I I
J F M A M J J A s 0 N D
USABLE ENERGY, KALA CREEK HYDRO PROJECT
DESIGN CONSIOERA TIONS
LAYOUT OF FACILITIES
The selected plant configuration is a 100-foot-high rockfill dam. For
purposes of layout and computation of quantities, the dam is assumed to have
3:1 side slopes and an overflow spillway along the right abutment (see Figure
3). The powerhouse could be located immediately downstream of the dam, as
no significant amount of additional head can be gained by moving the
powerhouse further downstream. The penstock length with this configuration
would be minimized, and is estimated to be approximately 300 feet. There
appears to be sufficient area immediately adjacent to the powerhouse to place
the switchyard also in the west floodplain, with a skewed crossing of the creek
immediately to the north (see figure 4).
POWERHOUSE LAYOUT
The powerhouse would be a conventional indoor plant with the
substructure constructed of reinforced concrete and the above-ground housing
being a pre-engineered metal building. The powerhouse would contain the
turbine, generating unit, controls, governors, switchgear, and a standby
generator. Flow of water to the turbine would be via a 42" diameter, l/4"-
thick steel penstock, controlled by hydraulically operated butterfly valves.
Control facilities would be for an unmanned plant, and protective devices
would operate automatically to protect the equipment.
-13-
.,
G')
c: ::u
m
(o)
ELEV. 300
CONCRETE ON ~! ~~~~~~~
UPSTREAM FACE
1' THICK
CUTOFF
WALL
GROUT CURTAIN
L3. MIN.
~ ROCKFILL__.,..,
ELEV. 200
Figure 3
GALENA SMALL HYDRO
TYPICAL DAM SECTION
lli.T.I.
FIGURE 4
KALA CREEK HYDRO
SITE LAYOUT -0 ~
SCALE~ 111
• ~·
J
1000
The main power equipment would consist of one horizontal Francis-type
850 KVA turbine tied to a synchronous type generator rated at 850 KVA, 0.8PF
and 900 rpm. The turbine discharge would be 100 cfs at 90 ft. of head. One
850 K VA transformer would also be provided.
MAJOR ELECTRICAL EQUIPMENT
Generator
The generator would be a synchronous type with horizontal shaft directly
coupled to the turbine. The generator would be rated at 850 KVA, 3 phase, 60
hz, 480 volt at 0.8 power factor. Drip-proof housing would be provided. The
generator would,be open-ventilated with an 80° C rise, Class B insulation and
no provisions for overload. The generator would have full run-away speed
capability. Excitation systems would be according to manufacturer's standard.
Power Transformers
Two power transformers would be required.
At the generating site, one (1) 850 KVA 0.48/34.5 KV delta-grounded
wye, 30 transformer, OA class with minimum non-premium impedance would
be required.
A substation would be required at the point at which the 34.5 KV
transmission line interfaces with the existing 2400 volt delta distribution
system. The transformer at this site would be a 850 KVA 30, 34.5/2400V wye-
delta, OA class transformer with minimum non-premium impedance.
Load Controller
The load controller would be of the gate shaft actuator type. It would be
designed to regulate the load of the generator and prevent run-away by
controlling the wicket gates. The load controller would consist of the
necessary indicating and control devices, an oil pumping set consisting of a
sump tank and two motor driven oil pumps, one or two pressure vessels as
required, and all necessary servo-motor piping.
-16-
Generator Voltage System
The connection between the generators and breakers would be with
cable. The generator and station service breakers would be metal enclosed
drawout type rated 600 V, with 1600 amp frames. The breakers would be
combined in a common switchgear lineup along with generator surge
protection and instrument transformers.
Unit Control and Protective Equipment
Unit controls would consist of manual startup and shutdown circuits,
basic protective relays, and basic instrumentation. Protective relays for each
unit would include generator differential, overspeed, overvoltage and ground
overcurrent. Instrumentation for each unit would include a voltmeter, an
ammeter, a wattmeter, and a watthour meter. The controls would be
contained in a single cabinet. No annuciation or station battery would be
provided.
Station Service
The station service power would be obtained via a tap between the
generator breaker and the main power transformer. The station service
distribution panel would be adjacent to the generator switchgear lineup.
Station service power distribution would be at 480 volts 3-phase transformed
to 240/120 volts three phase and single phase power. Standby diesel
generation (approximately 25KW) sufficient to supply station power needs
would be provided.
TRANSMISSION LINE
The 34.5 KV, three-phase transmission line would traverse northerly
approximately 4 miles to the point where it crosses the Yukon River. North of
the river, it would connect to the existing transmission line to Galena. The
line would be /12ACSR mounted on single poles and crossarms. Ground
clearance of 25'-30' must be maintained and clearing would be required where
encroachment occurs. The proposed submarine cable crossing would require
two transition terminations: one from overhead to submarine cable and one
from submarine cable to overhead. Total length of the transmission system is
approximately 8.8 miles, including the river crossing.
-17-
The 34.5 K V transmission line would be connected to the existing 2400
volt distribution system through a 850 KVA 34.5/2400 wye-delta transformer.
A transfer switch would be provided to shift from hydro to diesel as it is
required. A voltage higher than the 2400 volt existing system was selected
due to the large conductors required to avoid excessive line losses at the lower
voltage.
SUBMARINE CABLE CROSSING
A number of potentially serious problems are associated with the
proposed transmission line crossing of the Yukon River. Among the most
severe of these is the combined thermal and hydraulic degradation of the river
banks in this area, which has been an on-going problem for the City of Galena
for a number of years. It is not known whether the banks at the proposed
crossing are ice-rich, but throughout this reach of river they are highly
erodible.
In addition to the known bank erosion, the potential also exists for bed
scour which could expose the cable. No specific data is available for this site,
but local scour in similar rivers can be on the order of tens of feet.
Underwater construction, which would disturb the natural armoring of the
streambed, could be a focal point for such local scour to begin.
-18 -
ECONOMICS
BENEFIT ANALYSIS
Annual benefits for each of the three options consisted of the following:
Benefit
Displaced Diesel Fuel Costs
(Based on fuel cost of $1.64/gallon and
generating efficiencies of 8.8 and 13.0
kwh/gallon for the village and AFB systems,
respectively. Benefit value is a weighted
average.)
Fuel Escalation
(as derived from current national
fuel cost escalation rates,
developed by Data Resources, Inc.)
Displaced Operation and Maintenance Costs
Dependable Capacity
(For 150-ft. dam only)
Value
$0.14/kwh
0.08/kwh
0.02/kwh
350/kw
These values were applied to the usable energy and dependable capacity
figures from Table 4, yielding the following:
DAM USABLE DISP. FUEL DISP. DEP. TOTAL
HT. ENERGY FUEL ESC. O&:M CAP. BENEFITS
100ft 4502MWh $ 630,000 $378,000 $90,000 s 0 $1,098,000
125 6933 971,000 583,000 139,000 0 1,693,000
150 8465 1,185,000 711,000 169,000 298,000 2,363,000
COST ANALYSIS
Cost estimates were derived for each of the project sizes based on
October 1984 prices and included the following items: rockfill dam, steel
penstock, powerhouse and associated equipment, transmission line, road
improvements, mobilization, demobilization, profit, contingencies (20%),
engineering and design (7 .5%), supervision and administration (6.5%), and
interest during construction (18 months at 8 3/8%). Costs were amortized
-19-
over 50 years at 8 3/8%, and an additional $70,00 was added to account for
operation and maintenance. Costs are summarized below.
DAM TOTAL INV. AMORTIZED TOTAL
HT. FIRST COST I.D.C. COST INV. COST ANNUAL COST
100 ft. $34,557,000 $2,765,000 $37,322,000 $3,184,000 $3,254,000
125 52,169,000 4,174,000 56,343,000 4,806,000 4,876,000
150 77,7 59,000 6,221,000 83,980,000 7' 163,000 7,233,000
A detailed cost estimate for the selected plan may be found on the following
pages.
EVALUATION
To derive the optimum plan, net benefit and benefit-cost ratios were
determined and are as follows:
DAM ANNUAL ANNUAL NET
HEIGHT COSTS BENEFITS BENEFITS B/C RATIO
100ft $3,254,000 $1,098,000 $-2,156,000 .34
125 4,876,000 1,693,000 -3,183,000 .35
150 7,233,000 2,363,000 -4,870,000 .33
The above analysis indicates that none of the options evaluated is
economically feasible. Based on net benefits, however, the 100-ft. dam would be
the selected plan.
-20-
CONCLUSIONS
The project would produce power during the warmer months for the City
of Galena and the adjacent Air Force base. During the winter, insufficient
power would be generated and the existing diesel generators would be required.
Some dependable capacity could be developed by the 150-foot dam but, as
stated above, it would be insufficient to meet the demand.
The maximum net benefit is yielded by the 100-foot dam, even though
this option has no dependable capacity. Benefit-cost ratios for all three
studied options (100-ft., 125-ft, 150-ft.) are extremely low, and all net benefit
figures are negative.
RECOMMENDATIONS
Based on presently available information, it is recommended that no
further Corps of Engineers studies of hydropower development at Kala Creek
be undertaken at this time.
-21 -
DETAILED COST ESTIMATE (100-FT DAM)
ITEM/DESCRIPTION QUANTITY UNIT UNIT PRICE TOTAL
DAM & INTAKE
Excavation 2,000 CY s 5 s 1 (),000
Rock Stabilization 10,000 SF 20 200,000
Soil Stabilization 200 CY 250 50,000
Filter Fabric 900 SF 3 3,000
Rockfill 240,000 CY 35 8,400,000
Concrete 2,000 CY 1,000 2,000,000
Spillway (excavation) 1,800 CY 250 450,000
Spillway (concrete) 205 CY 1,000 205,000
Intake 1 EA 60,000 60,000
TOTAL DAM & INTAKE $11,378,000
PENSTOCK
Tunnel Excavation 200 LF 2,500 s 500,000
42-in Steel Pipe (1/4") 300 LF 950 28 5,000
Concrete Anchor Blocks
and Thrust Blocks 24 CY 1,000 24,000
Rock Bolts 20 EA 50 1,000
Drainage and Vent 1 LS 20,000 20,000
TOTAL PENSTOCK $830,000
POWERHOUSE
Structure 1 LS $253,000 $253,000
Turbine/Generator 1 LS 325,000 32 5,00()
Accessory Electrical 1 LS 258,000 258,000
Aux. Systems & Equip. 1 LS 24,000 24,000
Switch yard 1 LS 42,000 42,000
Tailrace 1 LS 81,000 81,000
TOTAL POWERHOUSE $983,000
TRANSMISSION LINE
Treated Wood Posts 300 EA 5,000 s 1' 500,000 Conductors and
Insulators 43,000 LF 20 860,000
Submarine Cable 53,000 LF 70 3,710,000
Connect to Existing
System 1 LS 1,000,000 1,000,000
TOTAL TRANSMISSION LINE $7,070,000
-22-
ROAD IMPROVEMENTS
Upgrade Existing 4
Cat Trail
MOBILIZATION AND PROFIT
Mobilization 1
Project Operation 18
Demobilization 1
Contractors Profit 5
TOTAL MOBILIZATION
SUBTOTAL
Contingincies (20%)
Engineering & Design (7 .5%)
Supervision & Administration (6.5%)
TOTAL FIRST COST
Interest During Construction
TOTAL INVESTMENT COST
ANNUAL COSTS
Total Investment Cost,
Amortized over 50 years at 8 3/8%
Operation and Maintenance
TOTAL ANNUAL COST
ANNUAL BENEFITS
Displaced Fuel Cost
Fuel Escalation
Saved 0 & M
TOTAL ANNUAL BENEFIT
BENEFIT -COST RATIO
NET ANNUAL BENEFIT
-23-
Miles
LS
Months
LS
%
$350,000
100,000
150,000
100,000
$1,400,000
$100,000
2,700,000
100,000
1,228,000
$4,128,000
$25,789,000
5,158,000
1,934,000
1,676,000
$34,557,000
2,765,000
$37,322,000
$3,184,000
70,000
$3,25l!-,OOO
$ 630,000
378,000
90,000
$1,098,000
0.34
-$2,156,000