HomeMy WebLinkAboutSmall Scale Hydropower for Gustavus, Alaska Letter Report 1984HYD
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Letter Report
JUNE 1984
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Alaska Power Authority
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Anchorage, Alaska 99501
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ATTENTION OF:
DEPARTMENT OF THE ARMY
ALASKA DISTRICT. CORPS OF ENGINEERS
POUCH 898
ANCHORAGE. ALASKA 99506 -0898
Plan Formulation Section
Mr. Larry Crawford
Executive Director
Alaska Power Authority
334 West Fifth Avenue
Anchorage, Alaska 99501
Dear Mr. Crawford:
RECEIVED
JUL 11 1984
Enclosed is a copy of our report evaluating the hydropower
potential for Gustavus, Alaska. The findings show that the project
is not feasible. Our study analyzed a project located on Falls
Creek near Gustavus.
If I can be of further assistance, please do not hesitate to
contact me directly. If further details are desired by your staff,
contact can be made with Mr. Charles Cox of my Plan Formulation
Section at (907~ 552-3461.
Enclosure
E. Saling
Colonel, Corps of Engineers
District Engineer
SMALL-SCALE HYDROPOWER FOR GUSTAVUS, ALASKA
LETTER REPORT
June 1984
Alaska District
U.S. Army Corps of Engineers
Pouch 898, NPAEN-Pl-P
Anchorage, Alaska
SMALL SCALE HYDROPOWER FOR GUSTAVUS, ALASKA
LETTER REPORT
SUMMARY
__.
The Alaska District, U.S. Army Corps of Engineers, investioated the
feasibility of hydropower development for Gustavus and Bartlett Cove,
Alaska, in response to a United States Senate Committee Resolution dated
1 O:tober 1976. The planning objective was to determine the technical
and economic feasibility of developing hydroelectric power generation
facilities to replace the diesel power generators currently in use in the
Gustavus area.
The study evaluated hydrop·ower potential of Falls Creek, which is
east of Gustavus (Plate 1, Draft Interim Feasibility Study). Plants from
160 to 3,900 kilowatts (kW) were investigated; the optimum development
appeared to be about 400 kW. This plant could produce about 1,400,000
kW-hours (kWh) of energy annually.
Numerous problems ~ere encountered in the course of studying this
alternative. The dense forest and rugged terrain along Falls Creek would
make development of the project difficult and costly. Poor soil
conditions along the penstock route between the diversion structure and
powerhouse would be particularly troublesome. Low stream flows during
. several months of the year would limit hydropower production.
The estimated first cost of this project is $7,958,000. The findings
of this study indicate that a hydropower project at Falls Creek would not
be cost competitive with the installation and operation of a similarly
sized central diesel generation system. Therefore, it is concluded that
no further study at Falls Creek by the Corps of Engineers is warranted at
this time.
I. Background
A. Authority
This study was authorized by a October 1976 United States Senate
Public Works Committee Reso.lution that directed the Corps of Engineers to
determine the feasibility of installing small prepackaged hydroelectric
units in isolated Alaskan communities.
B. Objective
This letter report summarizes the background, plan formulation,
project costs, benefit analyses, and conclusions and recommendations of
the Falls Creek hydropower study conducted by the Alaska District. The
technical and economic feasibility of hydroelectric power development for
Gustavus and Bartlett Cove is determined herein.
LR-1
C. Scope
Studies conducted for the examination of hydroelectric generation
at Gustavus and Bartlett Cove reflect the level of detail required for
plan formulation evaluations of a general investigation feasibility
study. Design, cost, and economic analyses of the alternatives were
accomplished.
D. Study Area Location
The Falls Creek site is located east of Gustavus, Alaska. The
electrical needs of both Gustavus and the National Park Service•s
Bartlett Cove headquarters were examined for this study. Gustavus is
located in the northern portion of Southeast Alaska about 50 miles
northwest of Juneau (see Plate 1 in the expanded report). Bartlett Cove
is about 10 miles from Gustavus on the southeastern shore of Glacier Bay
and is the primary land access point to Glacier Bay National Park.
E. Coordination
Considerable interaction between the Corps of Engineers and the
community of Gustavus has taken place in the course of this study. A
public meeting was held in Gustavus in May 1982; the meeting was attended
by a substantial portion of the resident population. In addition, much
contact has been made with individuals in Gustavus. Various Federal and
State agencies also have provided input into this study.
F. Problems and Needs
The existing community generating system includes two 100-kW
generators and supplies power to 22 customers. This system, which was
previously privately owned, became a public utility in 1983. The
existing diesel generating facilities at Bartlett Cove include two 185-kW
units and one 100-kW unit. Most area residents use small gas or diesel
generating units from 2 to 6 kW.
Demand for electrical power could increase in the future. Most of
the increase would be attributed to installations of more appliances and
equipment. Some residents currently not using electricity could acquire
small generating units. New demands could also result from the projected
developments of a new fire station, a school addition, a new recreational
camp (which opened in 1983), a 40-unit lodge, and new residences.
The June 1983 price of fuel oil delivered to the Bartlett Cove dock
was 1.23 per gallon. At currently forecasted fuel cost escalation rates,
the fuel cost in 30 years will be about $3.30 per gallon for
Gustavus/Bartlett Cove. If an average fuel conversion efficiency of 10
kWh per gallon is assumed, the fuel cost portion of diesel generated
electricity of 10 kWh per gallon is assumed, the fuel cost portion of
diesel generated electricity would increase in 30 years from $0.13 to
$0.33 per kWh.
LR-2
II Formulation of Alternatives
A. Genera 1
Various alternatives that could be utilized to meet the energy
production needs of the area and to possibly offset the rising costs of
diesel generated power were considered. These included: conservation,
wood, coal/peat, natural gas, solar, transmission intertie, waste heat
recovery, wind, and hydropower. Hydroelectric generation was determined
to be the most feasible and attractive of these possibilities.
Three potential hydropower sites were considered: Falls Creek,
Salmon River, and Excursion Inlet. The lack of sufficient flow and
excessive penstock lengths made the Salmon site infeasible. Similarly, a
0.7-mile submarine cable and 11 miles of overland transmission line to
Gustavus made the Excursion Inlet site economically infeasible. This
left only the Falls Creek Development as potentially viable.
B. Hydropower --Falls Creek
Two options for development could take advantage of the elevation
drop over two waterfalls on Falls Creek. The upstream site would require
considerable excavation to install the penstock; much less excavation and
fewer environmental disturbances would be likely for the downstream
option.
III. Selected Plan
A. Project Description
The Falls Creek project could produce an average annual output
over 50 years of about 1,400,000 kWh. (The average annual demand for the
same period is projected to be about 1,561,000 kWh). The plan·would
include a 20-foot-high diversion dam less than 100 feet wide, a
34-inch-diameter penstock about 1,200 feet long, and a prefabricated
powerhouse with two turbine generator units with a total capacity of
about 400 kW. A 2-mile-long access road would extend eastward from Rink
Road north of the airport. The first mile of access road would consist
of an upgraded existing logging road. A 10-mile-long transmission line
would run from the powerhouse to Bartlett Cove. A 2-mile spur line would
connect the Gustavus powerplant.
B. Environmental Impact Analysis
Construction of this alternative would have a moderate effect on
the project site environment. Clearing for the dam, penstock, powerhouse
access road, and transmission line would result in a loss of about 40
acres of overstory. A minor increase in stream turbidity could result
from construction of cofferdams, the permanent dam, and a temporary rock
fill stream crossing. Any changes in fishery habitat due to changes in
overflow from the project could be mitigated by the creation of new
habitat in the itmJediate area.
LR-3
C. Economic Analysis
Estimated development costs and benefits for the proposed project
are outlined below. The expected project life is 50 years, evaluated at
8-1/8 percent interest and October 1983 price levels.
IV.
Category
Power
Emp 1 oyment ·
Annu.al Benefit
Project First Costs
Estimated Cost
roc {2 years at 8-1/8%)
Investment Costs
Annual Benefit
$ 408,000
47,000
$ 455,000
$ 7,958,000
651,000
$ 8,609,000
Annual Costs (50 years at 8-1/8%)
Investment ($8,609,000 X 0.0829)
o&M Estimate
Annual Costs
$
$
714,000
34,000
748,000
Benefit-Cost (B/C) Analysis
Average Annual Demand
Average Annual Equivalent
Annua 1 Benefits
Annua 1 Costs
B/C Ratio
Net Benefits
1,561,000 kWh
1,400,000 kWh
$ 455,000
$ 748,000
0.61
-$ 293,000
B/C Analysis Without Employment
Annual Benefit $ 408,000
Annual Costs $ 748,000
B/C 0.55
Net Benefit -$ 340,000
Cost per kWh (50 years at 8-l/8%) $ 0.53
Conclusions and Recommendations
The selected plan would be uneconomical because construction costs
for the dam and penstock would be high. The rugged terrain for the
access road and the poor foundation conditions along the penstock route
would be costly problems to overcome. Continued use of diesel generation
appears to be significantly less costly than development of the
hydropower project evaluated in this report. Therefore, no further study
by the Corps of Engineers is recommended at this time, as the project
would not pass the Federal economic evaluation criteria.
LR-4
..
GUSTAVUS SMALL HYDR OP GJER
PLAN FORMULATION ANALYSIS
I NTR OOUCTI Q\l
Authority
Scope of Study
Study Participants
Studies by Others
Existing Projects
C()lMUNITY PRCfiLE
Location
Population
Economy
Table of Contents
Government and Services
· · Transportation
Social Environment
Natural Resources
Cultural Resources
EXISTING FACILITIES
Generation and Distribution Systems
Energy Use
PROJECTED ENERGY DEMAND
To Base year 1990
Energy Demand After 1990
Comparison with Another Demand Prediction
PLANNING OBJECTIVES.
PLAN FOR MULA TI Q\l
No Action
Diesel
Conservation
Wood Generation
Coal/Peat
Natural Gas
Solar Energy
Transmission Intertie
Wind Generator
HydropONer
/
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PLAN SELECTION
Rationale
Plant Size Optimization
NED Selection
OVerview of the Selected Plan
With Project Conditions
Monthly Demand Distribution
CONCLUSIONS
RECG1MENDATI ONS
HYDROLCGY
Area Description
Climate
Hydrologic Analysis
Sedimentation
Plant Sizing
DESIGN
TECHNICAL APPENDIX
Dam, Spillway, and Intake
Penstock and Access
Cofferdam
Powerhouse and Transmission
PROJECT ECO'J(}'tiCS
Costs
Benefits
Summary
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T-1
T -1
T-2
T-5
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INTROOUCTIO'I
Authority
SMALL SCALE HYDROPOWER FOR GUSTAVUS, ALASKA
PLAN F CRMULA TI ON ANAL y·s IS
The evaluation of small-scale hydroelectric systems was authorized by
a United States Resolution dated 1 October 1976. That resolution
directed the U.S. Army Corps of Engineers to determine the feasibility of
installing small prepackaged hydroelectric units in isolated communities
throughout Alaska. The full text of the resolution reads:
RESOLVED BY THE COMMITTEE ON PUBLIC WORKS OF THE UNITED STATES
SENATE, the the Board of Engineers for Rivers and Harbors be, and is
hereby requested to review the reports of the Chief of Engineers on
Rivers and Harbors in Alaska, pulished as House Document Numbered
414, 83rd Congress, 2nd Session; Southeastern Alaska, published as
House Document Numbered 501, 83rd Congress, 2nd Session; Cook Inlet
and Tributaries, Alaska, published as House Document Numbered 34,
85th Congress, 1st Session,; Copp~r River and Gulf Coast, Alaska;
published as House Document Numbered 182, 83rd Congress, 1st Session;
Tanana River Basin, Alaska, published as House Document Numbered 137,
84th Congress, 1st Session; Southwestern Alaska, published as House
Document Numbered 390, 84th Congress, 2nd Session; Northwestern
Alaska, published as House Document Numbered 99, 86th Congress, 1st
Session, Yukon and Kuskokwim River Basins, Alaska, published as House
Document Numbered 218, 88th Congress, 2nd Session; and other
pertinent reports, with a view to determining the advisability of
modifying the existing plans with particular reference to the
feasibility of installing 5MW or less prepackaged hydroelectric
plants to service isolated communities.
Because the considered project is located within a National Park,
special authority was required to allaN the Corps to proceed with the
study. This authority was provided in the 1982 Department of the
Interior and Related Agencies Appropriations Bill, which states:
The Committee (Senate Committee on Appropriations) also directs that
the (National Park) Service shall cooperate with the U.S. Army Corps of
Engineers in a survey and study of the hydrolelectric potentials of Falls
Creek as a source of electrical power for the community of Gustavus (sic)
and for the Glacier Bay National Monument. (Parenthesized words added
for clarity.)
1
Scope of Study
This interim study was made to determine if there are economically
and environmentally feasible alternatives that could meet or supplement
the electrical energy needs of Gustavus and the National Park Service's
Bartlett Cove headquarters area. This study only considers electrical
energy needs because total study area energy needs have previously been
addressed by the Alaska Power Authority (APA). A summary of findings for
the Gustavus portion of this APA study is given in the Studies by Others
section below. ·
Study Participants
Federal agencies that provided input to this study included the U.S.
Fish and Wildlife Service, National Park Service, U.S. Department of
Energy Alaska Power Administration, Federal Aviation Administration, and
National Weather Service. State agencies that provided input included
the Alaska Department of Transportation and Public Facilities, Department
of Game and Fish, Department of Natural Resources, Department of
Community and Regional Affairs, and the APA. Especially important were
the contributions of the Gustavus area residents.
Studies by Others
Gustavus energy needs were addressed in a March 1982 draft report
prepared for the APA. This report, 11 Reconnaissance Study of Energy
Requirements and Alternatives,~ concluded that electrical power
generation from a Falls Creek hydropower installation could be attractive
and that further study should be done.
The Alaska Department of Transportation and Public Facilities'
~tober 1981 "Preliminary State Transportation Policy Plan 11 assessed
transportation needs throughout the State and, at Gustavus, considered
airport improvements. This plan is being revised and should be issued as
a final report in 1983.
In April 1983, the National Park Service issued the "Draft General
Management Plan and Environmental Assessment 11 for the Glacier Bay
National Park and Preserve. This document presents alternative plans for
the management and use of the resources of the park and preserve over the
next 10 to 15 years. It includes an environmental assessment of the
proposed alternatives, a wilderness review, and a land protection
strategy.
The National Park Service and the State of Alaska currently are
discussing the proposed transfer of some Glacier Bay National Park and
Preserve lands near Gustavus to State ownership in exchange for State
lands in another part of the State. The Falls Creek study area is
included within the Gustavus area lands considered for ownership
transfer. When and if this transfer will actually occur is uncertain at
this time.
2
Existing Projects
There are no existing Federal projects for electric power at
Gustavus. The present diesel system in the community was originally
owned and operated by the Federal Aviation Administration but was later
turned over to the Alaska Department of Transportation and Public
Facilities, which in turn sold it to a private operator. The generators
are still under private ownership.
The Federal government, via the National Park Service, owns and
operates the diesel generating system that serves the park. The nature
and extent of these facilities are discussed later in the report.
CCJv1MUNITY PROFILE
Location
Gustavus is a small unincorporated community located in the northern
portion of the Alaska 11 Panhandle" about 48 miles norttrwest of Juneau
(Figure 1) •. It is bounded on th'e south by Icy Strait and on all other
sides by the Glacier Bay National Park and Preserve. The community name
is taken from nearby Point Gustavus.
Barlett Cove is about 9 miles from Gustavus on the southeastern shore
of Glacier Bay and is the primary land access point to the park. The
National Park Service maintains visitor facilities and an operational
office at the cove. Because Bartlett Cove would be connected to the
proposed Falls Creek hydropower project, it is included in the study area.
Population·
U.S. Census data for the past 30 years shows a fluctuating year-round
population for Gustavus:
Year
1960
1970
1980
Population
107
64
98
There is a wide seasonal variation in the study area population,
which increases to as much as 300 during the peak summer season. This
seasonal increase is primarily due to the influx of summer residents who
spend about 6 months in the area. Most part-time residents come from
Juneau and most of the rest come from the western continental United
States. Before 1970, Gustavus was inhabited primarily by descendents of
early homesteaders. During the 1970's there was an inflow of young
adults. The current population is split about evenly between these two
groups. The following census profile provides a comparative cross
section of Gustavus demographics.
3
POINT
GUSTAVUS
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I'IGUIIIII 1
GUSTAVUS, ALASKA
Loc•tJon & VIcinity
M•p
Aleak• Dl•trlcl < Corp• of Engineer~
Census Year
caterorx_ 1970 1980
Tota popultion """64 98
Total Families 16 26
Persons by Race
White 60 96
American Indian 4 2
Persons bx_ Sex and Age Male Female Male Female
Economy
0-9
10-19
20-44
45-74
Median Age of Persons
Occupancy Status of Year-Round
Total
Occupied
Vacant
12 2
1 5
12 8
6 9
14.7
Housing Units
27
16
11
-6-
4
28
10
30.8
111
44
67
The economy in Gusta·vus is driven by four basic employment
components; subsistence, year-round local employment, seasonal local
employment, and external employment.
13
2
24
11
Fishing and farming are the primary subsistence activities, with
nearly all of the residents engaging in one or both. Year-round.local
employment is created by the Alaska Department of Transportation and
Public Facilities, the local store, the National Park Service, the
school, and the post office. Combined, these sources constituted
employment for 10 people in 1981.
Commercial fishing, the largest personl income generator in the
area, comprises a major portion of seasonal employment. The remainder is
associated with the Glacier Bay tourist industry from May through
October. Nearly 14,000 annual visitors arrive at the Gustavus airport
during May-through September on their way to Bart lett Cove and the Park.
This visitory activity creates local jobs through the National Park
Service, the Gustavus Inn, another inn, Alaska Airlines, and the National
Park Service concessionaires. Finally, some residents either supplement
or derive their entire income from outside the Gustavus area, mainly
Juneau.
5
The Alaska Department of Labor has compiled economic data for the
communities of Cape Spencer, Elfin Cove, Funter Bay, Gull Cove, Yakobi
Island, Port Althorp, Idaho Inlet, Bartlet Cove, and Gustavus, whose
population represents 78 percent of the total.* The data provide an
indication of the amount of employment located in the Gustavus region.
Only totals are given to maintain the confidentiality of employers.
Year
1975
1976
1977
1978
1979
1980**
Average Number Employed
40
41
25
50
61
60
Government and Services
Average Number of Firms
9
9
9
7
8
8
Gustavus is an unincorporated community within an unorganized
borough. It has a State operated school that offers grades 1 through
12. Other government services include road rr'iaintenance, telephone
service, and mail delivery. The community has elected to have a
satellite televisioo receiving station installed in the community.
Individual wells and surface runoff are the main source of water.
Privies are used for sewage disposal.
* The data are broken da.-vn by industry, except for co.mmercial
fishing, which is not represented. The categories include mining,
transportation construction, services, manufacturing, and Federal
government. Employment is highly seasonal, at nearly 80 percent from
April through September.
** First three quarters.
Transportation
The Gustavus area contains about 12 miles of improved road, the
majority of which connects Gustavus to Bartlett Cove.
Air access is provided by the Gustavus airport with two paved
runways, one 7,500 feet long and the other 5,000 feet long. Glacier Bay
Airlines, based in Gustavus, flies regularly to Juneau. Alaska Airlines
furnishes commercial jet service to and from Gustavus twice each day
during the tourist season. Various air charter services are also
available within the region.
6
A 48-foot dock is located on the Icy Strait waterfront near
Gustavus. This dock can handle supply barges and similar sized vessels.
Small craft can navigate the Salmon River during high tides. There is
currently ne State ferry service to Gustavus, although it has been
considered in recent regional master transportation plans.
Social Environment
The most prominent feature of the social climate in Gustavus is the
quiet rural lifestyle. The majority of full-and part-time residents
live in the area because it provides a simple, independent, and mostly
subsistence way of life. However, differing factions have developed
within the community as to how and to what extent this lifestyle should
be preserved. Because Gustavus is not incorporated, there is no
established formal government that can represent the residents.
With respect to hydropower, recent town meetings and discussions
with residents have indicated that the community is divided in its view
toward hydroelectric development. Those residents in favor of ·hydropower
believe hydropower would be acceptable if electrical energy could be
produced and delivered at a "reasonable" cost.
Natural Resources
Gustavus is located on a broad, flat plain on the north side of Icy
Strait, about 50 miles northwest of Juneau (Figure 1 ). The community is
bounded on the east, north, and west by the Glacier Bay National Park and
Preserve. Falls Creek enters Icy Strait about4 miles,east of the
community, as shown on Figure 1.
The Nat·iona 1 Park headquarters are located about 11 miles northwest
of the community. The park complex includes a headquarters building, a
large lodge, visitor center, dock complex, employee housing, and support
f ac i1 it i e s.
Topography
The mountainous area of southeastern Alaska around Gustavus reflects
the convergence of the North Pacific and Continental tectonic plates of
the earth 1 S crust. Area geology is extremely complex because of three
major fault systems. Bed~ock has been dated from early Paleozoic to
middle or late Pleistocene. Much of the area is glacial or periglacial,
hence the name Glacier Bay National Park. The glaciers in the Chilkat
Range near Gustavus have receeded while those of Mount Fairweather
(15,300 feet) 75 miles northwest are advancing. LaPerouse noted glaciers
at the mouth of Glacier Bay in 1786, 56 miles from their present position.
7
No evidence of recent volcanic activity exists; however, earthquakes
up to 7.9 have been measured in the past. A 7.9 earthquake in 1958
caused 30 million cubic meters of rock to plunge into Lituya Bay and
generated a surge of water that rose 1,690 feet on the opposite wall of
the inlet.
A geologic reconnaissance conducted for the National Park Service in
1978 found few mineral deposits. Of those, found, most were non-metallic
commodities.
Vegetation
The Falls Creek drainage supports a dense, relatively pure and
native Sitka spruce forest. Alder and devils club are the main under
story along the creek boundaries, which gives way to blueberry and
salmonberry at higher elevations away from the creek. Skunk cabbage is
present in areas where the soil is wet. Ground cover is a thick mat of
mostly mosses. Additional site-specific details are presented in the
Technical Index.
Fish and Wildlife
The Falls Creek area supports a large concentration of black bears
through most of the year. Well used bear trails crisscross throughout
the drainage. Bears forage along the beach during spring until the
grasses and skunk cabbage emerge at higher elevations. From mid-July to
September, concentrations of bears can be found at the creek, where they
eat on the anadromous salmon.
Bald eagles are abundant in the study area and are concentrated near
Falls Creek during the salmon runs. There are no known eagle nests in
the immediate area. Falls Creek supports spawning populations of pink,
chum, and coho salmon as well as Dolly Varden char. The Alaska
Department of Fish and Game annually assesses the escapement of Falls
Creek from the intertidal area to the oJd reach. Spawning habitat above
the bridge to the powerhouse site is good to fair with approximately 200
square meters between the powerhouse and falls. Rearing habitat for
juvenile coho and Dolly Varden are mainly in areas where log jams have
created pools. There appears to be no fishery above the falls; however,
this speculation is based on limited field data.
The flow available for hydropower was reduced to reserve a minimum
stream flow of 5 cfs between the dam and powerhouse to maintain the
salmon spawning habitat. This level of reduced flow would be subject to
further review if the project were feasible.
8
Cultural Resources
Various surveys have identified 60 historically significant distinct
sites or structural complexes in the area. Future sites will likely be
found in stable unglaciated areas. As of 1983, no archeological or
historical sites or structures around Glacier Bay were on the National
Register of Historic Places.
About 10,000 years ago, during the early post-glacial era, man
apparently managed floral and fauna resources at Ground Hog Bay, just
east of the park. More recent evidence of man is not found until 2,000
years ago. Evidence of a house, microlithic tools, and heavy woodworking
tools dates from the beginning of the little ice age. Another gap in
records exists until 200 years ago. Many sites within the National Park
remain from activities of late historic Tlingit fishing camps or from
European mineral or fishing ventures. No sites were found along coastal
regions of the park, which is explained by limited access to the sea
because of the cliffs and lack of beaches. Sites were also not found in
the inlets and bays, some of which may have been considered dangerous.
One such otherwise promising location, Lituya Bay, was destroyed by an
earthquake. Tlingit folklore describes a history of natural disasters in
this seismic area. Apparently the Tlingits dwelled in semi-permanent
villages during the winter and moved to camps for seasonal hunting,
fishing, and gathering.
In 1741, Russian ships reached Glacier Bay. Subse·quently, Europeans
exploited the area's fur animals and'claimed the land as their own.
After the United States purchsed Alaska, 'troops and naval vessels were
sent to Sitka to prevent Tlingit uprisings in the area. The last of the
ships remained until 1896. The gold rush boom missed Gracier Bay except
for some small-scale mining~
A saltery was constructed at Bartlett Cove, adjacent to Gustavus, in
the late 1890's. By 1900 a cannery in nearby Dundas Bay supported a
community of 40 houses. The cannery was abandoned in 1935 but
prospectors, fishermen, traders, and settlers kept the area populated.
Spectacular views of glaciers attracted tourists on regular ship tours of
Glacier Bay starting in 1883. Experts, most notably John Muir, studied
the glaciers and their retreat. An 1899 earthquake ended these tours by
filling Glacier Bay with broken ice. Glacier Bay National Monument was
created in 1925 and again began to attract tourists. The monument, later
to become a National Park, was proclaimed by President Hoover to have
11 tidewater glaciers of the first rank in a magnificent setting of lofty
peaks and more accessible to ordinary travel than other regions of
Alaska.11
9
EXISTING FACILITIES
Generation and Distribution Systems
The existing privately owned and operated Gustavus community
generating system includes two 100-kW generators. Generator bus bar
capacity is 2,400 V. The two generators each use about 100 gallons of
diesel fuel per day. The system also includes about 2.5 miles of active
three-phase transmission line with a line voltage of 7,200 V. Delivered
power is 60 Hz at 240/120 V. Most of this line is in good condition and,
with continued maintenance, could be incorporated into an expanded
system. In 1983 the existing 7200 V delta distribution system was
converted to a grounded wye 7200/12,470 V system. As part of the
modifications by the newly formed utility, 3.2 miles of 7200 V single
phase underground cables were laid. An abandoned line extends about 3
miles from Gustavus to the National Park boundary west of the community.
This line is in very poor condition and is not considered to be useable.
The existing diesel facilities at Bartlett Cove include two 185-kW
units and one 100-kW unit in generally good condition. These can
generate a maximum bus bar capacity of 480 V, which is stepped up to
13,800 V for distribution throughout the park. The three-phase
distribution system delivers 208 to 480 V to the various park facilities.
Most area residents use small gas or diesel powered generating
units. These units vary from 2 to 6 kW with an average capacity of about
4 kW. The units deliver single phase, 120/240 V. The larger units
provide power at residences using a wide range of appliances including
residence heating. The smaller 2-to 3-kW units are generally limited to
meeting lighting needs and running small power tools, Power conversion
efficiency for these units is approximately 3.5 kWh per gallon of fuel.
Energy Use
Energy use at Gustavus and the Glacier Bay National Park facilities
at Bartlett Cove during 1983 was determined from field interviews with
operators of the existing systems, surveys of area residents not served
by a centralized system, and research of pertinent literature on energy
use patterns in small isolated communities.
Existing energy use in the study area has been categorized into the
following user groups.
Bartlett Cove
Gustavus central system
Other existing residential *
other public **
Other commercial **
* Includes residences deriving power from individually owned and
operated generating units or those using no electricity at present.
** Includes public or commercial facilities not served by a central
system.
10
A discussion of existing study area energy used by each group is given
in the following paragraphs.
GUSTAVUS CENTRAL SYSTEM. The Gustavus system became a public
utility in 1983 and currently serves 22 customers, including: the Alaska
Department of Transportation and Public Facilities buildings, the airport
facility, Alaska Airlines, the telephone exchange, school, general store,
and three National Park Service homes. This system was privately owned
and operated in 1982 since being publicaly owned and operated by the
Alaska Department of Transportation and Public Facilities and the Federal
Aviation Administration (FAA). The addition of more hookups to the
system, which had nine customers in early 1983, required licensing by the
Alaska Public Utilities Commission.
The 1983 peak energy use ranged from a maximum of about 90 kW in the
winter to a minimum of about 50 kW in the summer. Average monthly 1982
demand measured over a 3-year period (excluding FAA facilities) is given
in Table 1. The percentage distribution of typical monthly demand
(measured in kilowatt-hours) is also shown in Table 1. Of the total
average annual system demand, residential demand accounts for about 20
percent of the total demand.
Table 1 -1982 Eners,r: Use -Gustavus Central S,r:stem Average Monthl,r: Demand
Month Total (kWh} Residential {kWhl % of Annual
January 21,430 3, 720 12.9
February 17,820 3,450 10.8
March 14,620 3,250 8.8
Apri 1 13,650 3,030 8.2
May 12,190 2,580 7.4
June 10,580 2, l40 6.4
July 11 '030 2,220 6.7
August 11,030 2,220 6.8
September 11' 190 2,680 6.8
O:tober 13,060 3,330 7.9
November 15,160 3,600 9.2
December 13,580 3,280 8.2
TOTAL 165,620~/ 36,080 100.0
a/ Excluding FAA facilities and a major school addition, which was
partially complete in late 1982.
Use
Bartlett Cove System. The Glacier Bay National Park headquarters and
visitor facilities are served by the existing diesel generating system.
The 1982 peak energy use ranged from a maximum summer (August) demand of
160 kW to a winter demand of about 50 kW. Average monthly energy
generation for the Bartlett Cove system is given in Table 2.
11
Table 2 -1982 Energy Use -Bartlett Cove System Average Monthly Use
Month
January
February
March
April
May
June
July
August
September
Cctober
November
December
Total
Total Use (kWh)
16, 100
14,000
16,800
14,000
35,350
40,250
46,550
47,600
49,350
30,800
23,100
16,800
350,700
% of Annual Use
4.6
4.0
4,8
4.0
10. 1
11.5
13.3
13.6
14. 1
8.8
6.6
4.8
100.0
Other Existing 1982 Residential Use. Most of the Gustavus area
residents depend on small gas or diesel powered generators or other
sources of energy to meet lighting and heating needs. Those without an
electric power source commonly use wood, oil, or LPN gas for heat and gas
or kerosene for lighting.
At least 29 homes in the area have some appliances. Of these, about
23 used small (2-to 5-kW) gas or diesel generating units in 1982. These
units belong to 18 year-round residents who use about 900 gallons per
year per household for electric power. A survey of area residences
indicates that present annual energy use for year-round and seasonal
residents with generating units averages about 3,200 and 520 kWh per
household, respectively. Total energy generated in the study area by
these small systems is estimated at 65,000 kWh per year, as shown on
Table 3.
Other Public. Other public facilities using electrical energy during
1983 include a new structure used to house the community fire truck.
However, this initial use has been insignificant to date.
Other Commercial. Other commercial facilities with an existing
energy demand include two seasonal inn-resturants. Both of these units
are served by individually owned and operated diesel generating units and
would continue to be so served in the future in the absence of a cheaper
energy source. Together these units used an estimated 33,800 kWh during
1982.
A recreational fishing camp was constructed in the area in 1982, but
did not commence operation until 1983. This facility will use diesel
generated electricity for at least the near future.
12
PROJECTED ENERGY DEMAND
To Base Year 1990
Table 3 -With Project Energy Demand, Gustavus, Alaska
Demand (kWh}
User Catesory
Bartlett Cove
Existing Gustavus System
Existing Residential
Other Public
Other Commercial
New Resident i a 1.
TOTAL
1982 Base Year -1990 350' 700 __,:_;;.....;__,;;_3~8~7:-, ~20~0~
165,620 228,800
64,900 237,000
0 6,000
33,800 339,600
0 61,800
615,020 1,260,400
Bartlett Cove System. The recently completed National Park master
plan for the Glacier Bay National Park and Preserve proposes construction
of new maintenance, administrative, and residential facilities
approximately 1 mile from the Bartlett Cove area and the construction of
additional visitor facilities within the existing developed area. These
projected improvements and visitor activities are expected to result in a
park energy demand growth rate of about 1.3 percent annually until 1990.
Total annual energy use at the park is expected to increase by 36,500 kWh
to 387,200 kWh in 1990, as shown on Table 3.
Gustavus Central System. A large number of new electrical hookups to
the existing system occurred during 1983. Increased energy use will
result from existing customers and the school addition. Total annual
energy use that would be met by this system is expected to increase from
165,620 kWh in 1982 to 228,800 kWh (including 48,200 kWh for the school
addition} by 1990. ·
Residential. Annual energy demand for 1982 year-round residents
served by small generating units is expected to increase from a 1982
average of 3,150 kWh per household to about 6,500 kWh per household in
1990. Similarly, annual energy use for seasonal residents is expected to
increase from 525 kWh in 1983 to 3,500 kWh in 1990. These projected
increases are generally in accordance with published electrical energy
demand trends for small communities in Southeast Alaska. Total annual
energy use for this development, including some households that are
expected to install a generating unit before 1990, is expected to increase
from about 65,000 kWh in 1982 to about 237,000 kWh in 1990.
Several hundred acres have become available for development in
Gustavus. Much of this land has been platted into 1-acre lots. One
development group plans to market 392 lots and has begun initial
subdivision infrastructure developments. Lot sales to the public and
actual building construction are expected to commence by 1984.
13
Sixteen new residences are expected in the area by 1990, all of which
would likely use electrical energy for lighting, appliance operation, and
limited resistance heating. It is estimated that three homes would be
year-round residences with an annual energy requirement of about 10,500
kWh each. The 13 new seasonal homes would have a 4-month energy
requirement of about 2,600 kWh each. Total annual energy needs for this
new development in 1990 are presently estimated at 61,800 kWh.
Public. The fire station constructed in 1983 would have a 1990 annual
requ1rement of about 3,500 kWh. A new satellite television system is
expected to be in operation by 1990 and have an annual energy requirement
of about 2,500 kWh. No other new public facilities are anticipated during
this period.
Commercial. Commercial energy demand in base year 1990 will result
from existing inn operations, the recreational fish camp, two new lodges
that are to be constructed before 1987, and minimal new commercial support
facilities. With continued additions of new appliances, energy demand
from the two existing inns could increase from about 34,000 kWh in 1982 to
40,000 kWh in 1990.
The new recreational camp, which opened in 1983, will operate from
mid-May through mid-October. Average energy demand as a percent of peak
demand during the pre-season periods is expected to range from 25 percent
during night hours to about 50 percent during operating hours. Average
June-September demand as a percent of peak demand is expected to range
from 30 to 75 percent for the same daily periods. Total annual energy use
in 1990, including a minor allowance for lighting at small boat mooring
facilities, is estimated at approximately 29,000 kWh.
A lodge called Glacier Bay Lodge is planned for construction in the
study area before 1990. This facility would present a peak energy demand
of about 67.5 kW. The lodge would operate during tne summer tourist
season from mid-May through mid-October. Average peak daily demand during
May and October would range from 50 percent of peak demand during the
daytime 12 hours to 25 percent during the minimal operation hours.
Average peak daily demand during June through September would range from
70 percent of peak demand during the day to 30 percent at night. Total
1990 energy demand for this facility is estimated at 101,500 kWh, as shown
in Table 4.
Another lodge with large walk-in freezers and refrigerators for fish
storage is scheduled for construction before 1990. It would have a peak
demand of 40 kW and would operate from mid-May through September. Total
annual energy use by 1990 is estimated to be 129,200 kWh.
It is expected that minimal commercial developments, possibly a
service station, hardware store, eating facilities, or similar
establishments, w~uld occur to support the expected public, residential,
and other commerc1al development. The average annual energy demand
associated with this activity is estimated at 40,000 kWh, as shown in
Table 4. Total 1990 demand for all commercial activity is estimated at
339,600 kWh.
14
Table 4 -Present and Future Commercial Demand at Gustavusa/
1982 -Existing Inn and Restaurants
1984 -Existing Inn and Restaurants
Salmon River Fish Camp
New Lodge with Large Walk-in Refigeration
TOTAL 1984 Commercial
Demand (kWh)
33,200
34,000
28,900
129,200
192, 1oo
1990 -Existing Inn and Restaurants (add electric heat)
Salmon River Fish Camp
40,000
28,900
129,200 Lodge with Walk-in Refrigeration
New Glacier Bay Lodge (40 units)
Other Commercial Support (service estabs.)
TOTAL 1990 Commercial
101,500
40,000
339,600
a/ Facilities which are presently not connected to the Gustavus central
system.
Energy Demand After 1990
Future energy demand after base year 1990 without additional
centralized energy supplies could follow any one of three possible
scenarios. The first of these would be a continuation of present
situation with no new development at the Glacier Bay National Park, a
greatly reduced commercial development, and very limited new residential
development, all restrained by escalating diesel fuel prices. The
existing central generating system would be operated as at present. This
low growth scenario could be considered a "no action•• energy growth
projection.
Another scenario might reflect the expansion of the central Gustavus
system to serve all existing and new residential, public, and commercial
development in the area. Residential energy use would be expected to
approximate recorded trends for Southeast Alaska.
The third and most likely growth scenario, in the absence of a new
electrical energy project, would reflect a situation where new park
development would be in accordance with the National Park master plan.
The existing central Gustavus system would not be expanded. Residential
demand would increase substantially as a result of State and private land
sales and subdivision developments. New commercial support development
and very limited public facilities to include a sewage treatmemt plant for
the concentrated residential development area are expected west of the
Salmon River. A central diesel generating system would probably be
constructed in this area after 1990. In the interim, users would likely
rely on individual diesel or gas powered generating units. New
residential units in other parts of the study area could also be expected
to use the· small 2-to 6-kW units.
15
Low Growth Scenario. Under this scenario, park energy use would
remain at roughly the base year 1990 level of 387,200 kWh per year.
Similarly, demand of the central Gustavus system would stabilize at about
229,000 kWh. • Other residential use would reflect limited interest in new
appliances by existing users due to increasing diesel fuel prices and an
additional 15 (5 year-round, seasonal) new homes by year 2000. Estimated
demand for development not connected to the current system should increase
with increased utilization of existing and added appliances. This usage
would be about 151,000 kWh by 2000. Total annual demand from new
residential development in 2000 is estimated at 141,100 kWh. Expected
demand from commercial actiyity would include that from the existing inns,
the recreational camp, and the 24-unit lodge. This projected commercial
demand (exclusive of central system demand) is estimated at 138,000 kWh
annually by 2000. Expected demand from public facilities not connected to
a centralized system would result from use of fire hall facilities and the
satellite television system. This demand would remain at roughly 6,000
kWh a year until 2000. Total electrical energy demand in 2000 under the
low growth scenario would be about 1,052,300 kWh, as shown in Table 5.
Table 5 -Estimated 2000 and 2040 Electrical Demand
Low Growth Scenario
User/Demand Category
Bartlett Cove
Gustavus Central System
Other Existing Residential
New Residential
Other Commercial
Other Public
TOTAL
Energy Demand (kWh)
2000 2040
387,200
229,000
151,000
141,100
138,000
6,000
1,052,300
472,700
229,000
272,000
401,000
279,300
26,000
1,680,000
Even with the low growth scenario and a dependence on fossil fuel,
energy demand is expected to grow as more and more people relocate into
the area on a seasonal, year-round, or short-term basis. A moderate
increase in park usage is estimated at 472,700 kWh by the end of the
50-year project life. Little change in demand is expected at the Gustavus
central system. A moderate increase in residential energy is expected to
occur as a result of increased utilization and added units.
End-of-project-life demands (year 2040) for existing residential
development using individual units and new residential development using
small units are estimated at 272,000 and 401,000 kWh, respectively.
Commercial activity would be increased by the addition of the 40-unit
lodge and miscellaneous small service facilities. Total commercial
electrical energy demand is estimated at 279,300 kWh annually by 2040.
Under the low growth scenario and no hydropower development, public
energy use would reflect a limited expansion of the fire fighting facility
and new sewage treatment works for subdivision development in the Salmon
River area. This expected usage is estimated at about 26,000 kWh annually
by 2040, as shown in Table 5. Total electrical energy demand under this
scenario would increase from 1,052,300 kWh in year 2000 to 1,680,000 kWh
by year 2040.
16
High Growth Scenario. Under this scenario, a maximum development plan
would be implemented at the park before 1990. This additional expansion
would result in a 1990 park electrical energy demand of about 416,800
kWh. The existing Gustavus diesel system would be expanded to accommodate
electrical energy neeas of all existing and future developments. A
significantly greater level of energy utilization per household would be
realized as residents would no longer have to contend with the operation,
maintenance, and capacity limitations of small generating units. Total
future electrical energy demand under this growth scenario is estimated at
~,659,700 and 2,483,000 kWh for 2000 and 2040, respectively, as shown in
Table 6.
Intermediate Growth Scenario. This projection reflects future
implementation of the proposed alternative National Park master plan,
continuance of-the existing Gustavus system at its present capacity,
increased utilization of electrical energy by existing residents, a
substantial demand from new residences in the Gustavus area, new
commercial development, and limited public. utility works to service a new
residential development near the Salmon River.
The. proposed facility modifications and additions at Bartlett Cove
would result in an increase in demand from 387,200 kWh in 1990 to about
427,700 kWh in 2000. Park developments after 2000 are uncertain but could
be expected .to support a 0.5 percent annual increase over a 40-year period
td 2040 for a without project demand of 522,100 kWh. A minor increase in
energy utilization by customers of the existing Gustavus system would
increase total demand from 228,800 kWh in 1990 to 231,800 kWh in 2000. No
further increase in demand is projected at this facility after 2000.
Existing residents not served by the central system could be expected
to increase their energy utilization within the limits of their individual
generating units. Five more residences would likely acquire units by
2000. Total 2000 and 2040 demand from this increased utilization by
existing residents is estimated at 323,500 and 396,000 kWh, respectively.
New residential development will continue as a result of additional
land transfers between private parties and continued development of the
subdivision near the Salmon River. Five year-round and about 45 seasonal
homes are expected in the area by 2000. A new central diesel unit would
probably be constructed to serve the Salmon River area development in the
absence of other energy sources, as indicated by land owners and
developers in the area. Total 2000 demand from this increased development
is estimated at about 224,000 kWh. The projected addition of 17
year-round and 150 seasonal homes over the next 40 years of project life
would result in a total 2040 demand of about 666,000 kWh for new
residential activity.
17
New commercial development is expected with or without any publicly
financed energy alternatives. The two lodges should be completed by 1990
with no significant increase in related energy demand. However,
additional service facilities, such as small shops and repair places, can
be expected. These small developments would result in estimated total
commercial energy demands in 2000 and 2040 of 348,400 and 372,300 kWh,
respectively. Increased public demand can be expected under this scenario
from the addition of fire fighting facilities and utilities to serve the
new Salmon River area residential development. This demand for 2000 and
2040 is estimated at 7,700 and 26,500 kWh, respectively. Total estimated
demand for the ''without project" conditioh for 2000 and 2040 is 1,503,500
and 2,214,800 kWh, respectively, as shown in Table 6.
Figure 2 shows the demand for the 1990 base year and for future years
as projected by the intermediate growth scenario. All other Gustavus
demand accounts for the demand by residential, commercial, and public
facilities, which are not now hooked up to the existing central system.
This category accounts for about half of the total demand in 1990 and for
two-thirds in 2040.
Table 6 -Estimated 2000 and 2040 Electrfcal Demand
(Without Project Condition)
Growth Scenario
R1gfi ~kWh) Intermediate {f<Wn)
Demand Categor~ 2000 2040 2000 2040
Bartlett Cove 460,400 562,000 427,700 522,100
Gustavus System 231,800 232,000 231,800 232,000
Other Existing
Residential 364,000 498,000 323,500 396,000
New Residential 282,500 792,000 224,400 665,900
Other Commercial 313,000 349,000 348,400 372' 300
Other Public 8,000 50,000 7,700 26,500
TOTAL 1,659,700 2,483,000 1 '563' 500 2,214,800
ComEarison with Another Demand Prediction
The estimates of projected energy demand were coordinated with the
Alaska Power Administration. This analysis indicated an apparently high
16.3 percent per year growth through base year 1987. However, the Corps
estimate of projected demand from 1983 to the base year was not based upon
percentage rate increases but on demand from facilities now under
construction or facilities likely to be constructed before the base year.
18
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GUSTAVUS, ALASKA
SMALL HYDROPOWER
FEASIBILITY STUDY
PREDICTED YEARLY
ENERGY DEMAND FOR
THE GUSTAVUS AREA
Alaska District, Corps of Engineers
The Alaska Power Administration (APA) also developed a low growth
scenario to provide a 1.5 percent annual increase subsequent to 1987 and
recommended this scenario for the project analysis. This rate of growth
assumes that the present area lifestyle would be maintained indefinitely
in its present form. This assumption is considered unrealistic,
considering the unique lDcation and characteristics of the study area.
Gustavus is not a typical "bush" community with a present and projected
lack of commercial and industrial activity, but is a gateway to a major
National Park. As such, it can be expected to increasingly attract more
commercial activity. There are strong indications, such as current new
lodge developments, that show that this activity is already beginning.
Landowners in the area also suggest aggressive intentions for marketing
platted lots (several hundred at present) in the Gustavus area. Initial
infrastructure developments, including roads and other utilities to serve
a large new subdivision, began in 1983. The overwhelming evidence of both
immediate and future development indicates that the projected energy
demand considered in the APA analysis is unrealistic.
PLANNING OBJECTIVES
Planning goals and objectives related to this study are local and
national in scope. The local planning objectives respond to the concerns
of local residents and the national objectives address the continuing
Federal interest in national economic development and environmental
quality. Local planning objectives used to guide this study include:
1. Stabilize or reduce the real electrical energy costs at Gustavus
and Bartlett Cove.
2. Minimize and mitigate, where required, any adverse project impact$
on the environment.
3. Preserve and, if feasible, enhance the fishery resources in the
impacted portion of Falls Creek.
4. Develop a plan that is acceptable to a majority of the local
residents.
National planning objectives that guided the formulation and
evaluation of alternative plans include:
1. Provide a technically viable plan that maximizes net economic
benefits.
2. Provide an environmentally sound plan that minimizes adverse
effects caused by the project and mitigates, to the extent possible,
unavoidable adverse impacts.
20
PLAN F CRMULATI ON
Many Gustavus residents and the National Park Service facilities at
Bartlett Cove are dependent on diesel generated electricity. This
electricity, whether generated by the central systems or by small privately
owned and operated units, has become increasingly expensive with rising
fuel costs over the past 10 years. Although there is a minor worldwide
surplus of oil and depressed fuel prices, the near and long term outlook is
for a resumption of escalating prices because oil is a finite resource.
The June 1983 price of fuel oil del~vered at the Bartlett Cove dock was
$1.23 per gallon. A portion of this fuel is off-loaded and transhipped
over land to Gustavus at a delivered price of $1.36 pe·r gallon. At
currently for~casted fuel cost escalat~on rates, the fuel cost in 30 years
will be about $3.30 per gallon. Assuming an average fuel conversion
efficiency of 10 kWh per gallon, the fuel cost portion of diesel generated
electrical energy would increase from $0.13 to $0.33 per kWh.
The purpose of this section is to evaluate the various alternatives
that could be utilized to meet the energy production needs of the study
area.
No Action
This plan would maintain the status quo at Gustavus and Bartlett Cove.
The existing central systems would be maintained and operated in their
present configurations. Local residents and some businesses not connected
to the system would continue to use their small generating units. Other
residents now not operating a system might acquire one in the future.
Imeact Assessment. This alternative would have no significant adverse
biolog1cal impacts in the study area. The increased burning of fuel oil by
existing development could result in a slight decrease in air quality.
Future increases in fuel use by new residential development would aggravate
this situation.
This alternative would help preserve the existing way of life, because
the non-availability of electrical energy could deter some people from
relocating into this area. There would be no additional transmission lines
to impact the natural aesthetics of the area. This alternative would not,
however, assist those seeking relief from the high cost of energy. These
people would remain vulnerable to rising energy costs.
21
Evaluation. Some people in the study area believe that maintenance of
their present community lifestyle is of greater concern than cheaper energy
and some area residents and land owners believe that the character of the
area can be maintained with the establishment of an area-wide electrical
power system. This alternative does not satisfy the need for a stable and
cost-efficient source of electricity.
Diesel
This alternative reflects the continuation of the existing National
Park Service Bartlett Cove diesel generating system and upgrading and
expansion of the existing Gustavus system to meet projected energy demands
from existing and future development.
The existing installed capacity of 200 kW in Gustavus would be
increased to 500 kW by 1990 and 750kW by 2040. This expansion would
require the expected addition of two sets of three differently sized
generators to optimally match seasonal loads. The actual cost of power is
currently 45¢ per kWh although this cost is decreasing as new customers
connect to the system. The cost including escalation is expected to remain
above 30¢ per kWh for the intermediate growth scenario.
Impact Assessment. This alternative would have an effect on the visual
landscape if the distribution lines were placed overhead. Underground
lines would essentially eliminate this impact but would reduce. transmission
efficiency. Overhead lines would also require right-of-way clearing in
undeveloped or sparsely developed wooded areas. Little change in
established community patterns would be forecasted because the bulk of
future development is expected to occur apart from the presently developed
area.
Evaluation. An expanded system of underground distribution lines would
be technically feasible. Environmental effects, other than increased
emissions of combustion products, would be minimal. Because hookup to the
system would be optional, few changes in lifestyle would be expected.
Therefore, this alternative is carried forward as the base case with which
alternative hydropower is compared.
22
Conservation
This alternative requires the implementation of various methods that
would reduce or restrict energy use. Conservation measures include
insulation, storm windows, weather stripping, conversion from incandescent
to fluorescent lighting, replacement of worn out appliances, and
construction of smaller houses.
Impact Assessment. This alternative has virtually no negative
environmental impacts and has very positive economic and social impacts.
The State of Alaska has estimated that thermal losses in Alaskan structures
can be reduced by 10 percent, saving an average of $180 annually, if $300
worth of conservation improvements are made. A $1,000 to $2,500 ·
expenditure could yield a 30 percent, or $500 per yea~, savings on energy
costs. In Gustavus the impact an electrical use would be negligible
because little electricity is used for heating and overall community energy
use is minimal when compared to larger communities. The cost of
electricity is now so high that minimizing its use has become a way of life
in Gustavus.
Evaluation. Energy conservation is probably the simplest method to
reduce overall energy consumption in the community. Insulation would
greatly reduce space heating costs. Implementation of t~is alternative is
ongoing. The basic responsibility for implementing this alternative lies
with the area residents. To aid in this responsibility and to lessen the
burden, various State and Federal programs are available. The State offers
conservation grants, and low interest loans and the Federal government
offers income tax credits. Althoug~ this alternative should be pursued to
the maximum extent possible by the community, it is not considered further
in this study as it does little by itself to reduce area electrical energy
requirements or costs.
Wood Generation
Wood is currently used by many area residents for space heating and
cooking. Wood can also be used to heat water to steam in a pressure
vessel. This steam can then be used to drive a turbine to produce
electricity. Because coniferous wood is abundant in the area, this would
appear to be an attractive option.
Evaluation. As identified in the APA•s March 1981 "Hoonah Wood
Generation Feasibility Study," small-scale steam plants are generally not
economical due to high operations and maintenance costs. Transportation,
handling, and storage costs usually remain dependent on oil costs. Long
range use for this type of electical generation is inhibited by a number of
items. Use of wood on a large scale at Gustavus would be impractical
because of cutting restrictions in the Glacier Bay National Park.
Environmental concerns associated with logging practices, road networks,
23
clearcutting, drainage and erosion, dust, leachate, and changes in mature
forests, which can affect wildlife populations, do not make wood as a base
loaa fuel more attractive than the established diesel generation systems.
The large size particulate matter, creosote, gases, and ashes
associated with softwood combustion would have significant impact on the
air and water quality and accelerate the solid waste disposal burden of
Gustavus. Sparks and creosote buildup would also add to the already great
fire hazard. For these reasons, this alternative is not considered further
in this analysis.
Coal/Peat
Use of coal/peat as a replacement for diesel at Gustavus is not
feasible due to the small scale of the project and the long distances from
these resources. Problems associated with the infrastructure, mining,
transportation, and air quality would adversely impact local and distant
areas. On a nonlocal level, coal/peat use could create serious problems
associated.with acid rain, the carbon dioxide (greenhouse) effects, and
land and water contamination between the mine and the source. For these
reasons coal/peat generation is not considered feasible at Gustavus.
Natural Gas
This alternative is not considered viable as no local supply exists in
the study area and one is not likely to be developed in Southeast Alaska.
Solar Energy
The high latitude and cloudy maritime climate preclude serious
consideration of active solar electrical generation at Gustavus.
Transmission Intertie
Various schemes have been considered for distributing electrical power
from major projects to Southeast Alaska communities. However, none of
these transmission interties would serve Gustavus or the Glacier Bay
National Park.
Waste Heat Recovery
Potential energy recovery from existing diesel generators could be
possible for the study area. One end use could be direct waste heat
recovery for hot water or building heat. In this application, waste heat
from the exhaust of the diesel generators heats fluid that is piped away.
Direct waste heat recovery requires that the generators be close to the
building or water supply being heated, otherwise heat is lost to the
atmosphere. If added to the existing generating units at Gustavus, this
heat source could possibly be used to heat some buildings such as the
school, post office, and government housing.
24
A second end use of recovered waste heat is electrical generation using
the Rankine Cycle. This requires vaporization of a fluid such as freon by
the waste heat from the diesels. The freon, which is under high pressure,
is then used to drive a turbine, which then produces shaft horsepower to
turn the generator for additional electrical power. However, field use
versions of the Rankine Cycle energy recovery system are still being
developed and are not considered available alternatives at this time.
Wind Generation
In wind generation, a wind energy conversion system (WECS) transforms
the force of wind moving past a tower-mounted generator into direct current
(de) electricity. This use is generally limited to lighting, resistance
space heating, or water heating. Where desired, a synchronous inverter is
provided to transform de into alternating current (ac) to match the voltage
requirements of most appliances. Expensive inverters are necessary if
conventional appliances are to be used or if the WECS is to be placed on
line with thermal or hydropower generators.
Wind is highly variable in velocity, duration, and direction. A WECS
is designed to operate between 12 and 35 mph with relatively constant
direction and long duration. As the variability of each of the wind vector
components increases, WECS design complexities and costs escalate.
Relatively complicated maintenance requires extensive operator training.
Operation in subzero conditions can create disruptions due to blade icing;
lubrication freezeup, tower damage from strong gusts, ·and other
site-specific conditions. WECS technology has established an expanding
market for units in the 1.5-to 15-kW range, which are suitable for
individual residences, farms, or small industrial cqmplexes.
Evaluation. Wind data over a 5-year period of record are available for
Gustavus. These records show that the area is subject to prevailing
southwesterly winds in the summer, with an average wind speed of about
5 mph. Winds during fall through spring are generally from the southeast
(except January winds from the north-northwest) with an aveage speed of
about 7 mph. Thus, at no time during the year do sustained wind speeds
make wind generated electricity a viable electrical energy alternative at
Gustavus.
Hydropower
A hydroelectric generation source is attractive for many reasons:
(1) it has a proven and reliable technology, (2) little, if any, fuel is,
required, (3) it uses a renewable resource, (4) costs are generally stable
for the economic life of the project and may decrease if and when the
physical life exceeds economic life, and (5) small run-of-river projects
are usually not environmentally damaging.
25
Three potential hydropower sites were considered: (1) on Falls Creek,
about 4 miles east of Gustavus, (2) on the Salmon River, about 6 miles
north of Gustavus, and (3) at Excursion Inlet, about 11 miles east of
Gustavus. The lack of sufficient flow and excessive penstock lengths made
the Salmon River site economically infeasible. Similarly, a 0.7-mile
submarine cable and 11 miles of overland transmission line to Gustavus
made the Excursion Inlet site economically infeasible, which left only the
Falls Creek development as potentjally viable.
Two options for development could take advantage of the elevatio~ drop
over two waterfalls on Falls Creek. A good damsite could be about 450
feet upstream of the upper falls, with a second site immediately upstreaw
of the falls. The upstream site would require considerable excavation to
install a water conduit between the dam and powerhouse below the first
falls. Much less excavation and fewer environmental disturbances would be
likely for the downstream option.
Either hydropower plan would include a 17-foot-high diversion dam less
than 100 feet wide, a 34-inch-diameter penstock between 1,200 and 1,800
feet long, and a prefabricated powerhouse with two small turbine generator
units with a total capacity of about 400 kW over between 170 and 185 feet
of head. A 2-mile-long access road would extend eastward from Rink Road
north of the airport. The first mile of access road would consist of
upgraded existing logging road. A 10-mile-long transmission line would
run fr.om the powerhouse to Bart 1 ett Cove. A 2-mi 1 e spur 1 i ne wou 1 d
connect with the Gustavus powerplant.
Impact Analyses. This hydropower project would produce an average
annual (over 50 years) output of about 1,400,000 kWh, as compared to an
average annual equivalent demand of about 1,561,000 kWh. Total first
costs and average annual costs would be about $8 million and $748,000,
respectively. Thus, average annual unit energy costs over the 50-year
economic life would be about $0.53 per kWh.
26
Construction would have a moderate effect on the project site
environment. Clearing for the dam~ penstock, powerhouse, access
road, and transmission line would result in the loss of about 4.0
acres of mature overstory. A minor increase in stream turbidity
could be expectea due to construction of cofferdams, the permanent
dam, and a temporary rock fill stream crossing. A temporary
increase in noise ~levels and human activity during construction
would disturb the bears.
There would be mi~or adverse effects to the immediate area
aesthetics, because the new distribution line would be visible. Use
of the existing (upgraded) power line to the park boundary and
construction on an underground line in the park would minimize
potential adverse effects. Minor changes in community patterns
would take place, as residents w~uld h~ve the option of joining or
not joining a new expanded energy system.
Evaluation. A comparison of the annual project power output and
annual costs indicates that electricity could be provided at an
average ~nnual unit cost of about $0.53 per kWh if both Gustavus and
Bartlett Co~e were served by the system.
Any minor changes in fishery habitat due to changes in overflow
releases from this project could be satisfactorily mitigated by the
creation of new habitat in the immediate area. There could be some
irreversible long term effects in the character of the area by the
input of a new community wide energy supply, but the extent of this
effect is unknown. Some portions of the forest ecosystem would be
altered over the project life, but this is considered acceptable in
terms of total similar resources available in the area.
PLAN SELECT! ON
Rationale
The selection of an alternative to diesel generation is based on
the availability and accessibility of the resources available.
Coal, gas, solar, and wood fuels held no advantage over diesel
fuel. By process of elimination, only hydropower from Falls Creek
could be economically competitive. Additional discussion of a
potential hydropower alternative follows.
Plant Size Optimization
Preliminary hydrologic data, estimated demand, estimated usable
energy, and estimated costs of development were compared for six
different plant capacities between 250 and 750 kW. The minimum cost
per kilowatt-hour was used as a basis for plant size optimization.
The various alternative capacity plants were plotted (Figure 3) to
suggest an optimum plant capacity of about 435 kW. The technical
analysis develops a two-unit optimum installed capacity.
27
t-1700
z
1.&.1 ...a:;: 1600
<(3: ~..;w;
::::)-1!500 o,_
l.&.lc:~
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100% Power Output
,
/ ,
I ,
I
100 200 300 400 500 600 700 800
UNIT SIZ.E (kW}
435 kW Optimum
100 200 300 <400 ~0 600 700 800
UNIT SIZE (kW)
flf .. re 3
GUSTAVUS 1 ALAS;<..:-
SMALL HYDROPOWER
FEASIBILITY STUDY
PLANT OPTIMIZATION
,------Alaska Districtt Corps of Engineers
28
NED Selection
Continuation of the Central diesel system (without project
condition) appears to provide the lowest cost power to the Gustavus
area. None of the alternatives evaluated could provide net positive
economic benefits. Therefore, it was not possible to identify a
National Economic Development (NED) plan.
Overview of the Falls Creek Plan
The Falls Creek hydropower plan would include a 150-and 250-kW
horizontal Francis turbine located. in a small powerhouse operating
under 170 feet of bead. The system would usually meet the total
demand during 7 months of the year and meet a significant part of
the demand for the remaining months. However, diesel generation
would be required to assist the hydropower system in meeting the
total demand during periods of below-average monthly.flows. There
may be some unusually low flow periods when total diesel generation
is required. The hydropower system would produce about 1,400,000
kWh of average annual equivalent energy.
Local labor could be employed. The system could be placed in
service about 18 months' from start of construction. A small,
three-tier, 'rock-filled bin wall dam would be constructed about
2,500 feet northeast of tidewater. A 34-inch pipe would carry up to
45 cubic feet per second (cfs) of water to a 20-by 40-foot
p,owerhouse 1,100 feet northeast of tidewater. About 12 miles of
7,200-V transmission line would connect the system to the diesel
systems at both Gustavus and Bartlett Cove. Table 7 summarizes the
project economics.
Table 7 -Summary of Project Economics
Project First Costs (October 1983 prices)
Annual Costs (50 years at 8-1/8 %)
Investment
c&M
Total
Benefit -Cost (B/C) Analysis
Annua 1 Benefits
Annual Costs
B/C Ratio
Net Benefits
With Project Conditions
$7,958,000
714,000
34,000
$ 748,000
455,000
748,000
0.61
-293,000
Implementation of the hydropower project would have minimal
impact on energy demand before base year 1990. Impending
construction of the project could induce some residents to add more
appliances in the belief that an assured energy supply would soon be
available. A few people could relocate to the Gustavus area
slightly ·earlier than planned, if they knew hydroelectric generation
was going to be available.
29
The most significant impact on demand under the with project
condition would occur after project implementation. This impact
would be most significant on the low growth scenario and would
induce more people to fully electrify their homes. This phenomenon
is well documented in other isolated Alaskan communities that were
provided with new electrical systems. The timetable for commercial
support facility development would likely be advanced. An increased
rate of new residential development would be expected, along with an
earlier need for limited public support facilities. Projected
demand for 2000 and 2040 under an intermediate growth scenario would
be approximately 1,563,500 and 2,154,800 kWh, respectively.
MonthlX Demand Distribution
Present electrical energy demand within the Gustavus area is
characterized by a high summer demand at the Glacier Bay National
Park and a high winter demand at the central Gustavus system.
Demand at residences with individual generators also peaks during
the winter when lighting and heating needs increase. Commercial
energy demand peaks during the summer, because these facilities are
open only during the May-September tourist season.
A significant change in the seasonal demand pattern is expected
after base year 1990 due to a shift in peak residential demand from
the winter months. This change would be principally due to the
expected influx of new seasonal residents. This rate of change in
seasonal residential demand should increase from 1990 to 2000 and
decrease slightly thereafter until 2040. A summary of projected
monthly demand for the base year 1990 and years 2000 and 2040 is
given in Table 8 and shown in Figures 4, 5, and 6 •
..-'
Table 8 -Summarx of Projected Monthly Demand
Base Year (kWh) Available Hydropower
Month 1990 2000 2040 Energ~ (kWh)
January b"T,7oo 76,900 10T,300 115,300
February 57,700 69,700 97,200 117' 600
March 57,800 69,500 95,700 129,600
Apri 1 52,100 62,800 86,800 197,000
May 119' 300 161,500 250,000 228,800
June 177' 900 233,000 350,100 213,700
July 185,900 241,800 361,300 174,600
August 185,800 231,000 325,600 133,400
September 159,400 177,900 215,000 214,900
October 73,900 87,400 117' 500 228,800
November 68,900 82,300 112,400 204,100
December 58,000 69,700 95,900 159,200
TOTAL 1,260,400 1,563,500 2,214,800 2, 117,000
30
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GUSTAVUS, ALASKA
SMALL HYDROPOWER
FEASIBILITY STUDY
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EXPECTED MONTHLY
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1990
Alaska District, Corps of Engineers
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32
GUSTAVUS, ALASKA
SMALL HYDROPOWER
FEASI 81 LITY STUDY
EXPECTED MONTHLY
AVERAGE ENERGY PRODUCTION
2000
AI ask a District, Corps of Engineers
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33
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GUSTAVUS, ALASKA
SMALL HYDROPOWER
FEASIBILITY STUDY
en
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EXPECTED MONTHLY
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2040
Alaska District, Corps of Engineers
The energy computed in Table 7 is based on two assumptions.
First, the flow available for hydropower was reduced to reserve a
minimum stream flow of 5 cfs for salmon spawning between the dam and
powerhouse. Second, the "available hydropower energy" is assumed to
be 75 percent of the energy computed by the computer program used
with average monthly flows as input data. This approximation
accounts for a normal reduction in available potential energy when
daily flow records are used in the computations.
The "available hydropower enery" was compared with the demand to
determine the hydroelectric energy shown in figures 4,5, and 6. The
. remaining demand would be produced by diesel generators. The
indicated hydropower production probably would not be available at
all times. Some diesel power not reflected in the figures would be
required during some lower than average periods. Monthly average
stream flows were used in the computations. Daily stream flow data
would give a more accurate indication of the actual available
hydropower energy, but were unavailable at the time of this study.
CONCLUSIONS
The growth of the future electrical use in Gustavus was
difficult to predict because few historical records existed.
Projections were based on detailed discussions with local interests
and the National Park Service. The intermediate level of expected
growth was selected for planning purposes although a lower level of
growth was suggested by the Alaska Power Administration. Following
preparation of the growth senarios, the local utility and the Park
Service were contacted to obtain actual electrical use for 1983.
Complete records for Gustavus were not available for 1983 but
significant growth appears to have occurred which exceeded
expectations. A decline in electrical use was observed for the Park
Service facilities at Bartlett Cove, which essentially offset the
surge in growth at Gustavus. Thus, the overall power projection
contained in this report appears adequate for a feasibility study.
The hydroelectric development plan would avoid future fuel price
increase; however, detailed investigation has found it to be too
costly. A primary reason that the hydropower plan was found
uneconomical is that construction access for the dam and penstock
installation would undercut the steep and unstable riverbank soil.
The hazard of operating machinery on this route would be high and
the associated costs to stabilize the route very great. No cost
effective alternate access route or method was found. Even if dam,
powerhouse, and transmission features were simplified and their
costs reduced from those presented in the Technical Appendix, the
expense of the access difficulties would be substantial.
34
Net benefits are quite sensitive to projected demand, usable
energy, diesel fuel cost escalation rates, and available water.
However, because of the low benefit-cost ratio, it is doubtful that
a change in any of these factors would effect the study findings.
RECOMMENDATIONS
The Falls Creek hydroelectric plan is not capable of recovering
the estimated cost of construction, operation, and maintenance over
a 50-year project life at a rate competitive with a diesel system.
No further study by the Corps of Engineers is recommended at this
time, because the project is not capable of yielding net benefits in
accordance with the NED objective.
35
TECHNICAL APPENDIX
TECHNICAL APPENDIX
HYDROLCGY
Area Description
The Gustavus hydropower project would be located on Falls Creek
in the coastal area of Southeast Alaska approximately 4 miles east
of Gustavus, Alaska, and about 50 miles west of Juneau, Alaska. The
affected drainage area of 10.5 square miles is elongated, with a
maximum length and width of 7 and 2.7 miles, respectively. Mountain
ridges, which range up to 2,500 feet* in the west and 3,000 feet in
the east, surround the drainage area. A maximum elevation of 3,288
feet occurs on the eastern boundary and a minimum elevation of about
300 feet is located at the damsite. The mean basin elevation is
about 1,400 feet. Most of the area is covered by Sitka spruce with
underbrush and muskeg covering about 25 percent of the basin. No
permanent ice fields were observed in the entire drainage area.
Falls Creek has a width of about 30 feet at the damsite and
about 50 feet at the powerhouse site. The stream is entrenched
between banks ranging up to about 150 feet high with bank slopes
ranging from about 40 degrees to vertical.
Climate
Generalized climatological data for the study area were based
upon National Weather Service records for the Juneau Municipal
Airport, because that station had a continuous period of record
since 1952 and was in the same general area as Falls Creek.
Comparison of the Juneau records and intermittent Gustavus Airport
records indicate that intense rainfalls generally occur at both
stations during the same month, but not necessarily on the same days
or of the same intensity.
Falls Creek is located in an area of maritime influences that
are common in most of Southeast Alaska. In general, little
sunshine, abundant precipitation, and moderate temperatures are the
area's predominant weather characteristics. The rugged mountainous
terrain and ocean influences sometimes have contradictory effects
upon local weather, resulting in significant variations in
temperature and precipitation over relatively short distances.
Daily and seasonal temperature variations are usually small.
The normal monthly temperatures range from about 250F in January
to 550F in July. Extreme temperatures of -220F in January of
1972 and gooF in July of 1975 have been recorded.
* All elevations used are National Geodetic Vertical Datum.
Precipitation records for the Juneau Municipal Airport indicate that
Februrary and June are the months of least precipitation with about 3
inches each, although the minimum recorded monthly precipitation of 0.27
inches occurred in April 1948. Conversely, the records indicate that the
month of maximum precipitation is October with a normal of 7 inches. The
maximum monthly precipitation of record is 15.25 inches, which occurred in
October 1974. Annual precipitation ranges from a low of 37.80 inches in
1951 to 68.11 inches in 1961, with the mean being 53.48 inches. However,
as an indication of the local variations in precipitation, records indicate
that the maximum annual precipitation for Juneau is nearly double that of
the Juneau Airport, even though the rain gages are only 8 miles apart.
First snowfalls normally occur in October, although traces have
o~curred as early as 9 Septembe~ or as late as the first part of December.
Average monthly snowfalls range form 18 to 26 inches during December
through March. The maximum monthly snowfall on record is 86.3 inches in
February of 1965. Greatest snow accumulations usually occur in February
with the average being about 10 inches. Snow cover is usually gone by the
middle of April but light snows have occurred as .late as the first half of
May.
U.S. Geological Survey {USGS) discharge data for streams in the area
indicate two periods of peak flows each year: {1) April, May, and June
during snow melt runoff and (2) September, October, and November during
rain runoff. Intense rainfalls can occur during any of the warmer months
and result in significant discharges.
Hydrologic Analysis
Hydrologic data for Falls Creek consist of discharge measurements made
since initiation of the project study. Intermittent precipitation records
for several stations in the Gustavus-Juneau area were investigated, but a
valid correlation between the rainfalls at the different stations could not
be developed. Similarly, difficulties were encountered while attempting to
correlate rainfall in one area with streamflow in another geographically
similar area.
USGS data for 21 stations on 19 streams in the Juneau-Gustavus area
~ere analyzed for similarities to the Falls Creek drainage area (D.A.) and
a period of record that could be cross-referenced to other streams. Four
stations on three streams were then selected as being acceptable for use in
developing flows for Falls Creek. The four base stations were:
-Hook Creek above tributary near Tenakee~ D.A.
Hook Creek near Tenakee, D.A. = 8.00 mi~
-Kadashan River above Hook Creek near Tenakee,
-Tonalite Creek near Tenakee, O.A. = 14.5 mi2
= 4.48 mi2
D.A. = 10.2 m;2
T-2
The drainage area versus mean annual flow Gurve (Figure T-1) was
then plotted to determine if a relationship between the flows from
different drainage areas could be developed. As can be seen, this
relationship appeared to be acceptable. Curves showing average
percent of mean annual flow that occurred in each of the months for
the common record period (1969-1977) were then developed to relate
the distribution of flows throughout the year. The monthly
percentages of the annual flow for Falls Creek (D.A. = 10.5 mi2)
were then read from the curves and are given in Table T-1.
Table T-1 -Falls Creek, Monthl~ Distribution of Annual Flows in
January 2.5 May 17.8 September 8.7
February 3.5 June 14.2 October 16.2
March 3.1 . July 6.2 November 10.4
April 6.9 August 5.2 December 5.3
Similarly, curves showing average monthly discharge in cubic
feet per second per square mile versus drainage area were plotted to
establish a relationship between monthly discharges of the base
stations {Figure T-1). The higher monthly discharges, most notably
September, November, May, and June, approximated a straight line
somewhat better than the higher discharges. This was to be expected
because of the variability in size and intensity of storms in the
area.
Hook Creek near Tenakee (D.A. = 8.00 mi2) was used as the
final source of flow data for Falls Creek. This station was chosen
for two reasons. First, it had the longest period of record
(1967-1980) and, second, its drainage area was near the size of the
Falls Creek drainage area. Hook Creek flows in cubic feet per
second per square mile were multiplied by monthly flow factors to
yield Falls Creek monthly flows. These factors {Table T-2) were the
ratio of the monthly curve flows for drainage areas of 10.5 and 8.0
mi2. The computed Falls Creek flows were then converted to cubic
feet per second and used as the input period of record flow data for
the power computations. The computed mean monthly flows are shown
in Table T-3. (A stream gage was installed on Falls Creek but the
data were not obtained in time for use in this report.)
January
February
March
April
Table T-2 -Hook Creek to Falls Creek
Monthly Flow Factors
1.05
1.04
1.04
1.01
May
June
July
August
1.03
1.03
1.01
1.01
T-3
September
October
November
December
1.10
1.06
1.04
1.05
Percent
a:::C 100
90 ~~ 80
70 u-60 ~~~ en a::~ 50
IL. ~ 40
0"-1 0 30
~ 0) ~ oc<D 20 <o~ a::--15 ~a::
>~ <a. 10
-2 14
(I)
13 LL
(.J -12
II
2 10 . a 9
en
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7
~ 6
0
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~ 4
X 3 ..... z
0
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0 3 <(
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#I ..
2 3 4 5 678910
I. HOOK CREEK ABOVE TRIBUTARY NEAR
TENAKEE, O.A.:4.48 SQ. MI.
2. HOOK CREEK NEAR TENAKEE, D.A.=fJ;. .
SQ. MI.
3. KAOASHAN RIVER ABOVE HOOK CREEK
NEAR TENAKEE, O.A. = I 0.22 SQ. MI.
4. TONALITE CREEK NEAR TENAKEE,
O.A. = 14.5 SQ. MI.
20 30 4J 5060
-MAY ~---===-==-· ---~OCTOBER
~~JUNE
NOVEMBER
------------:: SEPTEMBER
------------------------AUGUST
-------------------------JULY
-----------DECEMBER
--------------------~FEBRUARY
==============::::::::::=MARCH = JANUARY
2 3 4 5 6 7 8 9 10 II 12 13 14 15 16
DRAINAGE AREA (SQ. MI.) FIGURE T-1 GUSTAVUS, ALASKA
STREAMFLOW
RELATIONSHIPS
____ ALASKA DISTRICT, CORPS OF ENGINEERS
" T-4
Table T-3 Falls Creek Computed Mean
1 966 - 1 981
Monthly Flo.-.rs (cfs)
January 24 May 111 September 64
February 34 June 78 cttober 130
March 48 July 35 November 85
Apri 1 55 August 27 December 41
Sedimentation
No sediment studies were conducted for Falls Creek. However,
on-site investigations indicate that sediment problems could be very
significant. During the summer of 1982, a large log jam and
sediment deposit existed in the area of the proposed damsite. The
age of this blockage which disappeared in the fall of 1982, could
not be determined. Sand and gravel bars downstream of the damsi.te
have moved ana the main channel of the creek has shifted a few feet
in some locations. Additional sediment studies would be recommended
if the project were feasible.
Plant Sizing
Various plant capacities, ranging from 160 to 3,900 kW, were
investigated, with emphasis on capacities in the range of 300 to 750
kW. Plant sizes of 300, 435, 492, 544, 620, and 753 kW were routed
in detail. The U.S. Army Corps of Engineers Hydrologic Engineering
Center (HEC) computer program HYDUR was initially used to determine
the annual power available for the various plant capacities. The
annual available power was not applicable to the analysis of the
hydropower plant on Falls Creek because much of the streamflo.-.r
occurs during relatively short periods when the demand may not be
very high. The powerplants were then analyzed on a month by month
basis to determine the power that would have been available as
compared to the actual demand for a particular month. Using this
methodology, monthly 11 available power 11 supplies were computed and
duration curves were developed. The duration curves reflect the
loss of some energy when the 11 average" monthly flows would have been
greater than or less than the usable flows of the plant. Those
losses did not include the loss of energy in the fluctuation of
daily hydrographs, which could not be defined.
Economic benefits based solely upon energy values computed from
mean monthly flows for the period would be erroneous and
misleaaing. Field observation of Falls Creek indicates that the
stream responds rapidly to rainfall and discharges, which may vary
from low to high and back to low within a matter of hours. Because
Falls Creek would be a run-of-river project, the use of the entire
mean monthly flo.-.r would be incorrect, as part of the flo.-.r would be
above the maximum at which the plant would operate and part of the
flow would be below the minimum at which the plant would operate.
Insufficient data exist to quantify the flow hydrograph
distribution. Therefore, the assumption was made that only 75
T-5
percent of the computed "available" mean monthly energy would be
"usable" energy.
DESIGN
Dam, Spillway, and Intake
The Falls Creek hyaropcwer dam design would be a three-tier,
vertical steel bin wall structure with a timber plank stilling
basin. The 14-gage steel bins would be rock and earth filled (from
on-site salvage of excavated dam and access road material) and would
be capped with 6-by 12-inch wood planks. (Concrete would be
expected to cost several times more than wood.) The planks would be
spiked into the cross pieces. The cross pieces would be anchored to
the bins with bolts and plates. ·Cutoff walls at the toe and heel of
the dam and the stilling basin would be formed from 6-inch-thick
wood planks.
Broad-crested weir calculations showed that the 100-year flood
of 1,650 cfs would overtop the entire dam by less than 5 feet. The
upstream tier is a 10-foot-wide cell, which is sufficient to prevent
detachment of the nappe. The second and third sets of bins are 15
feet wide to provide suitable impingement of the nappe. The final
step flews into a 16-foot-wide wood plank stilling basin, which is
designed to prevent erosion of the stream bed.
The dam would be 20 feet high and 90 feet across the upstream
tier. The second and third bins would step down 6 and 5 feet into
the stilling basin, which would be 70 feet wide.
The sluiceway in the dam would be centered in the stream and
consist of a 48-inch-diameter pipe just above the bottom of the
dam. The opening would be covered by a trashrack of welded
0.75-inch (#6) reinforcing steel bar. The gate would be operated by
a hand wheel from the top of the dam. When opened, the pool would
be drawn down in about 1 hour and accumulated sediment would be
worked through the orifice by maintenance workers.
The intake would be a 34-inch steel penstock gate mounted on the
face of the dam and covered by ~ trashrack of welded #6 bar. The
top of the intake would be placed at a sufficient depth to avoid
vortex formation and interference by the maximum 1.4 feet of
potential ice formation on the pool.
The intake would be 15 feet right of the sluice and have the
invert at 192 feet, 10 feet below normal pool. Both the sluice and
intake would have 12-inch-diameter air vents downstream of the
valves to prevent collapse of the pipe in the event of sudden
dewatering.
T-6
The dam would have a notched spillway to direct low flows over
the upstream cell. This would make the sluice and penstock valves
accessible for operation and maintenance most of the year. The
entire structure would be designed to be overtopped during floods.
Penstock and Access
The optimum penstock diameter would be 34 inches, to conduct up
to 40 cfs at 7.5 feet per second (fps). Maximum pressure rise due
to water hammer would be about 306 feet or 133 psi. A steel pipe·
with 0. 19-inch-thick walls was selected. Because the hydroelectric
plant would be designed primarily to serve the base load and
increase in capacity as demand and flow increase, an extended valve
opening time would be possible. A minimum opening time of 42
seconds would be required to prevent negative pressures; 60 seconds
is selected to allow a sufficient safety factor. Times could be
decreased, but a surge tank would become necessary at increased cost.
The penstock length and gross operating head would be about
1,200 and 170, feet respectively. Considerable excavation for the
access road and penstock route would be required along unstable
slopes parallel to the stream. If undercut, the entire slope could
give way and cause serious environmental degradation and high
installation, restoration, and maintenance costs, as reflected in
Table T-4.
The access road and penstock route would generally run along and
above the creek. Slopes run between 1 and 20 percent with the last
80 feet .of penstock descending at 45 degrees to the powerhouse. The
access road separates from the penstock route at the top of this
hill to join with the access road between the town and the
powerhouse. The right-of-way would be cleared to 60 feet wide. The
pipe would be supported by wooden trestles, wooden saddle stands,
and concrete thrust blocks. A 20-foot-wide trail would connect the
powerhouse and dam and serve as the penstock corridor. This design
would allow for a 15-foot-wide road, which exceeds U.S. Forest
Service criteria and which varies substantially from the
24-foot-wide Corps of Engineers standard for design. Because of
high costs of construction, Corps standards are not recommended for
this plan. The access to the dam would not only create the penstock
route, but also would provide the primary materials source for the
filling of the bins and the construction of the cofferdam.
T-7
The access from town to the powerhouse would take advantage of
all except the last mile of an old logging haul road from town to
the mouth of Falls Creek. The last mile of the old road used would
be upgraded and repaired as necessary for the passage of
construction equipment. The road to the powerhouse would reouire
forest clearing and grading beyond the old haul road along the tidal
flats. This new section would traverse the hillside from a 50 foot
elevation, up over 100 feet, and back down to the powerhouse at 30
feet. It woula be 15 feet wide with a gravel surface and pullouts
at intervals of about 1,000 feet or less.
Cofferdam
The cofferdam used in this plan has multipl~ stage diversion.
During the first stage, while the right side of the dam is
constructed, water would be diverted through a temporary culvert.
The cofferdam would be trapezoidal in cross section, 15 feet high,
35 feet wide at the base, and 5 feet wide at the top.
Upon completion of the right side of the dam, which would
include the sluiceway and penstock intake structure, the diversion
and culvert would be removed. The materials would be transferred to
the left ana water would be diverted through the two pipes. The
left side of the dam would then be installed. All cofferdam
materials would be removed from the stream after the dam is
completed and disposed of at the site in approved areas.
Powerhouse and Transmission
The powerhouse would be a 20-by 40-foot pre-engineered steel
building mounted on a poured concrete foundation. Two horizontal
Francis turbines, one 150 and one 250 kW, would operate off a
bifurcated 34-inch penstock. The building would house all turbine
generator equipment as well as valves, overhead hoist(s), the
accessory electric switchgear, and transformers.
Project power would be transmitted through 3.6 miles of
overhead and 0.5 miles of buried three-phase, 7.2-kV line to the
upgradea existing central diesel system. An additional 5.6 miles
of overhead and 2.4 miles of buried transmission line would connect
with the Bartlett Cove facilities from a junction 2 miles west of
the powerhouse. A pad-mounted transformer would increase the
voltage from 7.2 kV to 13.8 kV to serve the existino Bartlett Cove
system. -
T-8
PROJECT ECONOMICS
Costs
Estimated hydropower development costs are outlined below and
include all costs associated with furnishing, shipping, and
installation. The expected project life is 50 years, evaluated at
8-1/8 percent interest. Interest during construction (IDC) is
calculated for the projected 18-month .installation period.
No plan considered in this study had any associated historical
or archeological salvage operation costs, relocation costs, water,
and mineral rights costs. Remaining costs including engineering,
design, supervision, and administration are shown in Table T-4.
U.S. Fish and Wildlife Service mitigation costs are inherent to the
proposed design and not shown as separate costs.
Table T-4 Costs
Unit
Price Total
Item/Descri~tion Quant it~ Unit $ ($}
Mob & Demob 403,000
Lands & Right of Way 141,000
Dam
Clearing 1.0 acre 9,000 9,000
Bin Type Retaining Wa 11 9,684 sf 50 484,200
Rock Fill for Bins 1,230 cy 20 24,600
Rock Excavation 912 cy 60 54,720
Excavation of Overburden 250 cy 12 3,000
Timber Plank 6u X 12u 34,218 bf 2.25 76,991
Timber Plank 2" X 12" 2,240 bf 3.00 6, 720
Rock Bolts lu dia. x 8' 100 ea 160 16,000
Anchor Bolts, lu dia. x 3' 112 ea 60 6,720
Rebars and Misc. Steel 3 ton 2,400 72200
Total Dam 689,151
T-9
Intake
Penstock Gate, 34" dia.
with misc. equip.
Reservoir Orawdown Gate,
48" dia. with misc. equip.
Misc. Steel for Gate
Framing 1,400
Trashrack,(4 1 X 4•) 2
Steel Pipe for Orawdown,
48" dia., 1/4" thick
Tot a 1 Intake
Rock Fill Cofferdam
Rock Fill (1st stage)
Remove Rock Fill
Rock Fill (2nd stage)·
Arch Culvert, Span 117",
rise 79 11
Total Diversion Dam
Penstock
55
1' 115
1 '115
600
140
Penstock, Steel, 34 11 dia.,
3/16 11 thick, 68 lb/ft 1,150
Ring Stiffener-1, 106 lb/ri~g 38
Concrete
Reinforcement
Rock Bolts, 111 dia. x 8 1
Wood Penstock Supports
Total Penstock
Power P1 ant
Clearing
Powerhouse Bldg. & Found.
Tailrace
Turbine/Generators
Accessory Elec. Equip.
Auxilliary Systems and
Equipment
Sw itchyard
Total Power Plant
8
3,000
76
7,150
1
1
1
1
1
1
1
1
T -10
ea
ea
lb
ea
1f
cy
cy
cy
lf
lf
ea
cy
lb
ea
bf
acre
ls
ls
1 s
ls
1s
ls
1s
12,000
15,000
2.00
3,000
57
25
16
25
300
140
3,500
600
1.20
160
2.60
9,000
12,000
15,000
2,800
6,000
14,080
49,880
27,875
17' 840
15,000
42,000
102,715
161,000
133,000
4,800
3,600
12,160
18,590
333,150
9,000
68,000
4,000
389,000
237,000
38,000
35,000
780,000
Transmission Line
7.2-kV Aerial Electric Line
Along Roads Between Power-
house and Park Boundary
7.2-kV Aerial Electric Line
Over Land
Buried 7.2-kV Electric Line
Pad-Mounted Transformer
Clearing
Total Transmission Line
Access Road
Clearing
Strip Unsuitable Material
Excavation, Common
Excavation Rock
Gravel Base Surfacing
F i 11, Se 1 ect
Scarify and Recompact
Demolish Bridge
Corregated Metal Pipe (CMP)
24" 0, 16 GA
48" 0, 14 GA
72" 0, 12 GA
CMP End Section
48 11 0
72" 0
Total Access Road
~UBTOTAL
20% Cant i ngency
Subtotal
E&D 8%
S&A 6.5%
Total First Cost roc ( 18 months)
Total Investment Cost
Annual Cost
Annua 1 0.1R Cost
Total Annual Cost
7.1
2.1
2.9
1
30
5.5
12,000
70,720
15,280
12,160
2,870
18,700
2
136
72
166 . ..
2
4
T-11
mi
mi
mi
ea
acre
acre
cy
cy
cy
cy
cy
sy
ea
1f
1f
ea
ea
ea
103,000 731,000
135,000 283,500
136,000 394,400
20,000 20,000
9,000 270,000
1,699,200
9,000
10
8
25
20
15
3
15,000
59
150
253
49,000
120,000
565,760
382,000
243,200
43,050
56,100
30,000
8,024
10,800
41,998
1' 550 3' 100
1' 710 6,840
1 '560, 372
5,758,468
1' 191 '532
6, 950,000.
556,000
452,000
7,958,000
651,000
8,609,000
714,000
34,000
748,000
Benefits
The need to prevent the waste of natural resources provides the
challenge to determine the economic feasibility of meeting area energy
demand by hydropower. If the totals of all annual costs eliminated by the
use of hydropower generation are equal to or greater than the annual costs
of the hydropower plant, the two systems should be operated in
combination. This development would free a scarce resource for other use
and would contribute to the area economy. The major savings claimed for
hydropower development would be the elimination of diesel fuel during
periods of adequate water flow.
Fuel Costs Eliminated. The fuel cost of energy per kilowatt-hour is
taken as a benefit to hydropower development and each kilowatt-hour
produced is credited with that amount as a cost prevented. By using ar
area fuel cost of $1.37/gallon and a generating efficiency of 10
kWh/gallon, a fuel savings of $0.137/kWh can be used. Based on an average
annual projected output of 1,400,000 kWh (table T-5), the annual benefit
for energy is 1,400,000 kWh X $0.137 = $192,000.
Table T-5 -Area Demand and Hydropower Output (kWh)
Period
1990
2000
2040
Average Equivalent
Total Demand
1,260,400
1,563,500
2,215,000
1,561,000
Useable
Hydro Output
1,197,000
1,379,400
1,678,000
1,400,000
Fuel Cost Escalation. The cost of diesel fuel is expected
to increase faster than construction costs. By restricting fuel
use, a future cost increase, above general cost increases, is taken
by applying an escalation factor to the current cost per
kilowatt-hour of fuel. If escalation rates are assigned to the
first 30 years of .project life, a factor of 1.60 is used to adjust
current fuel prices (Table T-6). This adjustment applied to the
energy produced by hydropower gives an annual benefit of 1,400,000
kWh X $0.0822, or $115,000.
Table T-6 -Fuel Cost Escalation Rates 11
Year
1982-1985
1985-1989
1990-1994
1995-2000
2001-2012
Rates a
-0.53 Percent
4.23 Percent
3.71 Percent
2.65 Percent
3.53 Percent
a/ Based on adoption of 1983 Development Resources Incorporated
fuel escalation rates.
T-12
,
Extended Life of Diesel. The introduction of a hydropower plant
at Gustavus would allow the diesel system to be used as a backup
power source during critical flow periods. Diesel engineers have
determined that a direct relationship exists between reduced
operating time and extended plant life. ~ith this assumption a
system designed to last 10 years under full operation would last 20
years if operated 50 percent of the time.
The estimated annualized capital cost of the generation units
for a 100 percent diesel system large enough to meet the projected
demand of the Gustavus area would be ~225,000 assuming replacement
every 10 years and amortization at 8-1/8 percent. Extending the
life of this same system to 20 years by the addition of the proposed
hydropower system would reduce the annual cost to $154,000 thus,
saving ~71,000 annually or 50.7 cents for each marketable kWh
produced by the hydropower system. Similarly a 2.1 cent savings
could be credited to the hydropower system by reducing the diesel
operation and maintenance costs by 50 percent. Therefore, the total
savings credited would be 7.2 cents per kWh produced by the
hydropower system or $101,000 annually.
Power Benefit Summary. Table T-7 demonstrates the annual
benefits claimed for a hydropower project at Gustavus with an annual
marketable output of 1,400,000 kWh.
Table T-7 -Annual Benefits
Category Average/kWh (~)
Average Benefits (~)
Fuel Saved 0.1370
Fuel Escalation 0.0822
Extended Life of Diesel 0.0720
Annua 1 Benefit -....,o""".-=2..,..9....,12:---
=
=
=
=
192,000
115,000
101,000
408,000
Other Benefits. The construction of the proposed project could
have the potent1al of providing employment to an otherwise
unemployed labor force. This social well-being benefit is taken for
the labor portion of a project cost and is developed as an NED
benefit by the following approach.
Actual construction costs, without engineering and design (E&D)
and supervision and administration (S&A), are used in the
calculation of employment benefits. Employment benefits would be:
Project First Costs
Labor Costs (36%) =
$7,958,000
$2,863,000
T-13
Tabl~ T-8 indicates the amounts assigned by category for the
employment benefits for the hydroelectric project.
Table T-8 -Employment Benefits
Skilled Labor (60%) Unskilled Labor (40%)
Amount $1,718,000 $1,145,000
Local Contribution
Amount
0.36 0.75
$ 618,000 $ 859,000
Claimed as Benefit (%)
Amount
0.30 0.45
~ 185,000 $ 387,000
Combined Project Worth $572' 000
$572,000 X 0.08292 = $ 47,000 Annual Benefit =
Summary
Table T-9 summarizes the annual benefits and costs for the
Gustavus hydropower project.
Table T-9 -Hydroelectric Summary Table
Annual Benefits
Power
Employment
Annual Benefit
Estimated Costs
Project First Costs
!DC (2 years at 8-1/8%)
Investment Costs
$ 408,000
$ 47,000
$ 455,000
$7,958,00C
$ 651,000
$8,609,000
Annual Costs (50 years at 8-1/8%)
Investment ($8,609,000 X 0.0829)
O&M Estimate
Annual Costs
T-14
$ 714,000
$ 34,000
$ 748,000
Benefit-Cost (B/C) Analysis
Average Annual Demand 1,561,000 kWh
1,400,000 kWh
$ 455,000
Average Annual Equivalent
Annual Benefits
Annual Costs
B/C Ratio
Net Benefits
$ 748,000
0. 61
-$ 293.000
B/C Analysis Without Employment
Annual Benefit
Annual Costs
B/C Ratio
$ 408,000
$ 748,000
0.55
-$ 340,000 Net Benefit
Cost per kWh (50 years at 8-1/8%) $ 0.53
T-15
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