HomeMy WebLinkAboutRegional Inventory Recon Study Small Hydro Projects Vol 1 10-1980REGIONAL INVENTORY AND RECONNAISSANCE STUDY
FOR SMALL HYDROPOWER PROJECTS
ALEUTIAN ISLANDS, ALASKA PENINSULA, KODIAK ISLAND, ALASKA
VOLUME I - OVERVIEW
DEPARTMENT OF THE ARMY
ALASKA DISTRICT, CORPS OF ENGINEERS
EBASCO SERVICES INCORPORATED
OCTOBER 1980
VOLUME I — OVERVIEW
TABLE OF CONTENTS
Page
1.0
SUMMARY . . . . . . . . . . . . . . . . . . . . . . . .
. . . 1-1
2.0
INTRODUCTION . . . . . . . . . . . . . . . . . . . . . .
. . . 2-1
2.1 STUDY AUTHORITY . . . . . . . . . . . . . . . . . .
. . . 2-1
2.2 STUDY PROCESS . . . . . . . . . . . . . . . . . .
. . . 2-1
2.3 OTHER STUDIES . . . . . . . . . . . . . . . . . .
. . . 2-2
3.0
THE PROBLEM . . . . . . . . . . . . . . . . . . . . . .
. . . 3-1
3.1 EXISTING CONDITIONS . . . . . . . . . . . . . . . .
. . . 3-1
3.2 NEEDS . . . . . . . . .
. . . 3-2
3.3 PLANNING OBJECTIVES AND CONSTRAINTS . . . . . . .
. . . 3-3
4.0
ENERGY REQUIREMENTS AND COSTS . . . . . . . . . . . . .
. . . 4-1
4.1 REGIONAL SETTING . . . . . . . . . . .
. . . 4-1
4.2 COMMUNITY CHARACTERISTICS . . . . . . . . . . .
. . . 4-3
4.3 COMMUNITY LOAD GROWTH POTENTIAL . . . . . . . . . .
. . . 4-4
5.0
COMMUNITY HYDROELECTRIC DEVELOPMENT POTENTIAL . . . . .
. . . 5-1
5.1 PRELIMINARY SCREENING . . . . . . . . . . . . . . .
. . . 5-1
5.2 FIELD RECONNAISSANCE . . . . . . . . . . . . . . .
. . . 5-2
5.3 REVISED SCREENING . . . . . . . . . . . . . . . . .
. . . 5-3
5.4 DETAILED STUDIES . . . . . . . . . . . . . . . . .
. . . 5-4
5.4.1 Fossil —Fueled Power Generation . . . . . . .
. . . 5-4
5.4.2 Hydropower Generation . . . . . . . . . . .
. . . 5-4
6.0
REFERENCES . . . . . . . . . . . . . . . . . . . . . . .
. . . 6-1
APPENDIX
SECTION A — HYDROLOGY
SECTION B — ECONOMIC ANALYSIS
SECTION C — HYDROPOWER STUDIES
SECTION D — FEDERAL AND STATE PERMITS
VOLUME I - OVERVIEW
LIST OF TABLES
Table Number
Table Name
Page
1-1
COMMUNITY HYDROELECTRIC POWER EVALUATION -
PRESENT WORTH COMPARISON . . . . . . . . . . .
. . 1-3
1-2
COMMUNITIES WITH NON -ECONOMIC OR NO
HYDROPOWER DEVELOPMENT POTENTIAL . . . . . . .
. . 1-6
2-1
STUDY AREA COMMUNITIES . . . . . . . . . . . .
. . 2-3
2-2
PREVIOUS HYDROPOWER STUDIES . . . . . . . . .
. . 2-4
3-1
TYPICAL COSTS OF ELECTRICITY FOR SMALL
VILLAGES WITH CENTRAL ELECTRIC SYSTEMS . . . .
. . 3-4
3-2
TYPICAL COSTS OF ELECTRICITY FOR VILLAGES
WITH FLAT RATE CENTRAL ELECTRIC SYSTEMS . . .
. . 3-5
3-3
APPROXIMATE RESIDENTIAL COST OF ELECTRICITY
FOR TOWNS WITHOUT CENTRAL ELECTRIC SYSTEMS . .
. . 3-6
4-1
EXISTING VILLAGE POWER SYSTEM - DATA SUMMARY .
. . 4-9
4-2
VILLAGE CLASSIFICATIONS . . . . . . . . . . .
. . 4-10
4-3
COMMUNITY LOAD FORECASTS - RATE OF
GROWTH . . . . . . . . . . . . . . . . . . . .
. . 4-11
4-4
ASSUMPTIONS USED IN PROJECTING
FUTURE ENERGY REQUIREMENTS . . . . . . . . . .
. . 4-12
VOLUME 1 — OVERVIEW
LIST OF FIGURES
Figure Number Figure Name
1 STUDY AREA
2 INTAKE STRUCTURE
3 INTAKE STRUCTURE — TYPE B — CONCRETE
4 POWERHOUSE — TYPICAL LAYOUT
TABLE 1-1
COMMUNITY HYDROELECTRIC POWER ELEVATION
PRESENT WORTH COMPARISON
Paae 1 of 3
Installed
Hydropower
Hydropower
Diesel
Power
Energy
Benefit -Cost
Capacity
First Cost
Energy Costl
Cost2
$/kW
Comparison
Location
(kW)
$1,000)
$/kWh
0%
2%
5%
0%
2%
5%
Chignik Bay
Site No. 3
360
2,479
•.062
.081
.104
.168
1.31
1.68
2.71
Site No. 4
550
2,566
.042
.081
.104
.168
1.92
2.48
4.00
Chignik Lagoon
Site No. 1
620
4,163
.229
.181
.204
.268
0.79
0.89
1.17
Site No. 2
130
1,139
.127
.181
.204
.268
1.43
1.61
2.11
Chignik Lake
Site No. 5
370
2,333
.128
.164
.187
.250
1.28
1.46
1.95
Site No. 6
240
2,004
.131
.164
.187
.250
1.25
1.43
1.91
Site No. 7
1,340
7,043
.287
.164
.187
.250
0.57
0.65
0.87
Perryville
Site No. 1
4,450
9,486
.289
.141
.163
.224
0.49
0.56
0.78
Site No. 2
850
3,016
.108
.141
.163
.224
1.31
1.51
2.07
Ivanoff Bay
Site No. 3
650
3,792
.297
.189
.211
.272
0.64
0.71
0.92
Cold Bay
Site No. 1
370
3,226
.077
.092
.113
.175
1.19
1.48
2.27
Site No. 2
700
4,260
.058
.092
.113
.175
1.59
1.95
3.01
Site No. 3
1,720
7,110
.066
.092
.113
.175
1.39
1.72
2.65
Site No. 4
1,500
7,438
.071
.092
.113
.175
1.30
1.59
2.46
1 Assumes low plant utilization factor - Discount rate 7 1/8 percent - 50-year period of analysis.
2 Assumes high load growth scenario - Discount rate 7 1/8 percent - 50-year period of analysis.
3 Data from Revised Screening Project Data Summary - see Table C-1.
TABLE 1-1
COMMUNITY HYDROELECTRIC POWER ELEVATION
PRESENT WORTH COMPARISON
Installed
Hydropower
Hydropower
Capacity
First Cost
Energy Costl
Location
kW
$1 000
$/kWh
King Cove
- Belkofski
Site No.
5
170
1,890
.104
Site No.
6
740
3,817
.045
Atka
Site No.
1
1,340
5,416
.263
Site No.
2
490
2,460
.136
Site No.
3
700
3,600
.185
Site No.
4
31
390
.080
Site No.
5
180
1,188
.096
Nikolski
Site No.
1
120
1,403
.130
Site No.
2
1,000
5,435
.255
Site No.
3
130
2,340
.195
False Pass
Site No.
1
3,380
9,337
.038
Site No.
2
900
3,406
.033
Akutan
Site No.
1
1,500
7,275
.349
Site No.
23
69
705
.116
Site No.
33
112
964
.108
Site No.
43
117
1,060
.113
Unalaska-3/
Site No.
1
2,450
5,960
.018
Site No.
2
399
3,220
.071
Akhiok
Site No.
1
330
2,651
.184
Site No.
2
230
2,086
.167
Site No.
3
200
1,506
.132
Diesel Power Energy
Cost2 $/kWh
0% 2% 5%
2of 3
Benefit -Cost
Comparison
0% 2% 5%
.080
.101
.163
0.77
0.97
1.57
.080
.101
.163
1.78
2.24
3.62
.145
.167
.228
0.55
0.63
0.87
.145
.167
.228
1.07
1.23
1.68
.145
.167
.228
0.78
0.90
1.23
.145
.167
.228
1.81
2.09
2.85
.145
.167
.228
1.51
1.74
2.38
.142
.164
.225
1.09
1.26
1.73
.142
.164
.225
0.56
0.64
0.88
.142
.164
.225
0.73
0.84
1.15
.087
.054
.085
2.29
1.42
2.24
.087
.054
.085
2.64
1.64
2.58
.145
.167
.228
0.42
0.46
0.65
.145
.167
.228
1.25
1.44
1.97
.145
.167
.228
1.34
1.55
2.11
.145
.167
.228
1.28
1.48
2.02
.063
.080
.127
3.50
4.44
7.06
.063
.080
.127
0.89
1.13
1.79
.188
.210
.271
1.02
1.14
1.47
.188
.210
.271
1.13
1.26
1.62
.188
.210
.271
1.42
1.59
2.05
TABLE 1-1
COMMUNITY HYDROELECTRIC POWER ELEVATION
PRESENT WORTH COMPARISON
Page 3 of 3
Installed
Hydropower
Hydropower Diesel Power Energy
Benefit -Cost
Capacity
First Cost
Energy Costl Cost2 $/kWh
Comparison
Location (kW)
($1,000)
$/kWh 0% 20 57
0 2 57.
Karluk
Site No.
1 420
2,910
.115
.133
.155
.217
1.16
1.35
1.89
Site No.
2 190
1,732
.104
.133
.155
.217
1.28
1.49
2.09
Site No.
3 180
1,711
.106
.133
.155
.217
1.25
1.46
2.05
Old Harbor
Site No.
1 2,280
6,685
.154
.122
.143
.205
0.79
0.93
1.33
Site No.
2 680
2,896
.084
.122
.143
.205
1.45
1.70
2.44
Site No.
3 340
2,356
.091
.122
.143
.205
1.34
1.57
2.25
Kodiak3
Site No.
3 120
1,660
.131
.063
.079
.124
0.48
0.60
0.95
Site No.
4 627
3,150
.045
.063
.079
.124
1.40
1.75
2.76
Site No.
5 924
3,960
.038
.063
.079
.124
1.66
2.08
3.26
Ouzinkie
Site No.
1 990
4,111
.110
.102
.124
.185
0.93
1.13
1.68
Site No.
2 220
1,906
.097
.102
.124
.185
1.05
1.28
1.91
Port Lions3
Site No.
1 48
751
.162
.104
.126
.187
0.64
0.78
1.15
Site No.
2 334
3,390
.099
.104
.126
.187
1.05
1.27.
1.89
Site No.
3 140
1,240
.082
.104
.126
.187
1.27
1.54
2.28
Larsen Bay,
Site No.
1 364
2,020
.050
.085
.107
.168
1.70
2.14
3.36
Site No.
2 477
2,790
.051
.085
.107
.168
1.67
2.10
3.29
Site No.
3 154
1,340
.084
.085
.107
.168
1.01
1.27
2.00
TABLE 1-2
COMMUNITIES WITH NON —ECONOMIC OR
NO HYDROPOWER DEVELOPMENT POTENTIAL
Communities with Non —Economic Communities with No Hydropower
Hydropower Development Options Development Options
Alaska Peninsula
Port Heiden
Iliamnal
Naknekl
Sand Point
Squaw Harbor
Aleutian Islands
Ad ak
Attu
Kodiak Island
Cape Chiniak
Alaska Peninsula
Igiugig 1
Egegik
King Salmon/South Naknekl
Nelson Lagoon
Pauloff Harbor
Pilot Point/Ugashik
1 It should be noted that larger sites which could serve some of these
communities have been identified by Retherford (1979).
1-6
1.0 SUMMARY
A reconnaissance level study has been conducted to identify the
hydroelectric power resources at 36 isolated communities on the Alaska
Peninsula, Aleutian Islands, and Kodiak Island. The villages of the
study region, all faced with rising fossil fuel prices, have indicated
an interest in pursuing an energy development policy which will lessen
dependence on fossil fuel (diesel). The analyses presented in this
reconnaissance level study provide the basis for further evaluations
and serve as an aid in identifying those communities which may have
hydropower potential from those communities which are likely to have
little or no potential.
Future electric energy requirements were projected for each community
for the period 1980 to 2030. Cost estimates were developed for an
initial screening to identify communities which held the possibility of
having hydropower development potential when compared to diesel
generating systems, assuming an annual 5 percent rise in fuel prices.
For those communities which demonstrated that hydropower could be
economically developed in the aforementioned screening process, more
detailed studies of dam —type, penstock alignments, equipment needs, and
costs were provided.
The present worth of the average annual cost of meeting projected
energy needs utilizing diesel generators was calculated for each of the
communities, assuming diesel fuel prices escalate after an adjustment
for inflation at a rate of 0 percent, 2 percent, and 5 percent.
Present worth of capital, operating and maintenance costs were also
developed for each hydroelectric project identified as having economic
development potential.
1-1
The results of the present —worth comparisons of hydroelectric power to
diesel power for each community are presented in Table 1-1. Those
communities which are identified in Table 1-1 exhibit the potential to
provide economic hydropower development options, assuming fuel prices
will continue to climb and that energy generated by these plants can be
utilized 42 to 51 percent of the time depending on location.1
The likelihood of identifying small hydropower sites that may be
economically developed is remote for those communities listed in
Table 1-2. None of these communities have economic hydropower sites
even when fuel prices are allowed to escalate at 5 percent annually.
It is recommended that for each of the communities which have been
identified in Table 1-1, an additional screening process occur at the
prefeasibility level. Those sites which survive a prefeasibility
screening should be investigated in depth to further establish project
feasibility, community —by —community growth potential, and the seasonal
requirements for energy.
IA significant amount of sensitivity was introduced into the evalua—
tion of hydropower development at the communities listed in Table 1.
For each community, high and low plant utilization factors were
developed and for most communities two load growth scenarios were
provided. In addition, most hydropower sites near a community with
economic development potential were identified and evaluated. The data
base used in these evaluations is provided in Volume II — Community
Hydropower Reports.
1-2
2.0 INTRODUCTION
A study of the small hydropower resources at 36 isolated communities
spanning over 1500 miles in the Aleutian Islands, Alaska Peninsula, and
Kodiak Island has been conducted for the U.S. Department of the Army,
Alaska District, Corps of Engineers (Figure 1). The purpose of this
study is to provide a reconnaissance grade report outlining the
potential for hydropower development at each community listed in Table
2-1. The report provides an overview of hydropower potential in each
community, the present cost of energy, and for those communities with
economic hydropower potential, identification of specific sites
including identification of the preliminary size of project components,
equipment required, hydrologic characteristics, conceptual cost
estimates, and an environmental overview.
2.1 STUDY AUTHORITY
The Alaskan Small Hydropower Study authorized the Corps of Engineers to
assess the potential for installing small hydropower prepackaged units
5 megawatts or less to serve isolated communities throughout the
State. The Aleutian Islands, Alaska Peninsula, and Kodiak Island area
represent one of six subregions that have been or will be studied.
2.2 STUDY PROCESS
The study was accomplished by the consultants in four major stages
during the period January to October 1980. The first stage involved a
preliminary screening to identify drainage basins which could have
hydropower potential. The second stage involved a field reconnaissance
designed to provide study participants and individual community leaders
with an in —field overview of sites which illustrated some development
potential as well as exposure to field conditions and individual
community needs. The third screening involved a review of material
developed during the preliminary screening and field reconnaissance.
2-1
In the third screening, adjustments were made to hydrologic data and
information developed which described existing power costs and energy
needs.
The fourth phase included the preparation of more detailed layouts and
cost estimates for those sites which exhibited economic development
potential by surviving the first three levels of screening. Revised
benefit —cost ratios were computed for each hydropower project by
comparison of the hydropower alternatives to the most likely energy
alternative (diesel, with the exception of the village of Kodiak where
combustion turbines were assumed to be the most likely alternative) in
the study area.
2.3 OTHER STUDIES
It was an overall objective of the study to avoid duplication of
studies conducted by other agencies at the Federal and State level.
Such studies were reviewed to further strengthen the data base which
was used to conduct this reconnaissance level hydropower study. A
summary of other hydropower studies which have been completed is
provided in Table 2-2.
Other agencies which contributed significant information to this study
and focused on the hydropower resources of the region included the
Alaska Power Administration and Alaska Power Authority. The Alaska
Power Administration conducted a number of studies describing load
growth potential while the Alaska Power Authority is the State agency
responsible for pursuing the feasibility and construction of projects.
PM
TABLE 2-1
STUDY AREA COMMUNITIES
ALEUTIAN ISLANDS KODIAK ISLAND ALASKA PENINSULA
Adak
Akhiok
Belkofski
Akutan
Cape Chiniak x
Chignik Bay
Atka
Karluk
Chignik Lagoon
Attu x
Kodiak
Chignik Lake
False Pass
Larsen Bay
Cold Bay
Iliamna x
Old Harbor
Egegik
Nikolski
Ouzinkie
Igiugig
Unalaska
Port Lions
Ivanoff Bay
King Cove
King Salmon
Naknek Y
Nelson Lagoon
Pauloff Harbor
Perryville
Pilot Point
Port Heiden X
Sand Point x
South Naknek
Squaw Harbor x
Ugashik
2-3
TABLE 2-2
PREVIOUS HYDRPOWER STUDIES, ALEUTIAN
PENINSULA
Retherford, R.W. Associaties. 1980. Akutan Corps of Engineers site
no. 4 for Alaska Power Authority.
rRetherford, R.W. Associates. 1980. Preliminary feasibility designs
and cost estimates for a hydroelectric project near Larsen Bay,
Alaska. U.S. Department of Energy, Alaska Power Administration,
Juneau, Alaska.
Retherford, R.W. Associates. 1980. Preliminary feasibility designs
and cost estimates for a hydroelectric project on the Port Lions
River, Port Lions, Alaska. U.S. Department of Energy, Alaska
Power Administration, Juneau Alaska.
Retherford, R.W. Associates. 1980. Ram Creek hydro potential at King
Cove for Alaska Power Authority.
Retherford, R.W. Associates. 1979. City of Unalaska electrification
study. R.W. Retherford Associates, Anchorage, Alaska.
Retherford, R.W. Associates. 1979. Bristol Bay energy and electric
power potential phase I. U.S. Department of Energy, Juneau,
Alaska.
U.S. Army Corps Engineers. 1979. Akutan.
U.S. Dept. of Energy, Alaska Power Admin. 1979. Hydropower at Atka,
Alaska.
U.S. Dept. of Energy, Alaska Power Administration. 1979. Small
hydroelectric inventory of villages served by Alaska Village
Electric Cooperative. Hydro Projects Office. Seattle, Washington.
U.S. Dept. of Energy, Alaska Power Administration. 1978.
Hydroelectric power potential for Larsen Bay and Old Harbor,
Kodiak Island, Alaska. Appraisal evaluation.
y
2-4
3.0 THE PROBLEM
In each of the 36 communities which were studied most, if not all, of
their electric energy is obtained from diesel generators. Generators
range in size from the very small plrants which serve individual
residences to the more sophisticated plants which serve entire
communities through central electric systems.
While one of the objectives of this study was to obtain data on the
age, condition, and life expectancy of existing generator systems, it
was discovered that little information is available within the
communities that operate systems to properly portray these conditions.
Generally, poorly -maintained units have life expectancies that range
from 5 to 10 years while well —maintained units may provide service for
15 to 20 years.
A small amount of electric energy is also provided by non —diesel
sources in the study area. Communities with non —diesel sources include
Akutan where a 5kw hydropower plant has been installed and operating
since 1924, Chignik Bay where a 50kw hydropower plant has operated
since 1979 in the Alaska Packers Association cannery, and Nelson Lagoon
where a 20kw windmill has been installed and operated intermittently
over the last two years. The village of Atka is presently constructing
a 50kw hydroelectric plant and the village of Akutan has plans to
proceed with construction of a 150kw hydroelectric plant. The villages
of Karluk, Belkofski, Pauloff Harbor, Squaw Harbor, and Ugashik
presently do not have operating diesel generators.
3.1 EXISTING CONDITIONS
Village power costs are escalating at such a rapid rate that continuity
of service may be threatened because of the general inability of
consumers to pay utility bills. Throughout the study region, this
trend was evident as community leaders consistently expressed an
interest in turning to a power source that could provide fairly stable
3-1
electric rates. Values given in Table 3-1 and 3-2 are illustrative of
the effect that rapid escalation in fuel prices has on typical
residential electric rates. Electric rates, if increased to account
for fuel price and system operating cost escalation, will reflect a
rise in the kWh price of electricity by approximately 50 percent for
the period 1979 to 1980 for communities with central electric systems.
This estimate is based on the fact that fuel prices have increased from
an average of approximately $0.65 per gallon to an average $1.30 per
gallon during that period and system operating, maintenance and
replacment costs have escalated at approximately 10.5 percent. The
price of electricity is also escalating in villages that do not have
central systems. In the communities identified, the cost of operating
individual residential systems has increased by approximately 100
percent as shown in Table 3-3.
3.2 NEEDS
Villages have begun to search for alternative sources of power which
can produce energy at a cost that will be less than that produced from
diesel generators. Each of the communities in the study area which
were visited have expressed a desire to explore the hydroelectric
option in the hope that the development of a non —fossil fuel generating
source will lead to more stable community electric energy costs.
The price for basic necessities and services are extraordinarily high
throughout the region under study. Energy costs continue to consume a
disproportionate share of family income. The alternative for village
residents is to limit consumption of electric energy to the burning of
a few lights or eliminate altogether the consumption of electric energy
where costs exceed individual families' ability to pay.
Aleutian Islands and Alaska Peninsula communities have incomes
averaging approximately $12,700 per year (Tetra Tech 1979). Presently,
Kodiak Island community residents (with the exception of Kodiak) are
spending 8 to 19 percent of their average annual incomes on electricity
costs (KANA 1980). In such subsistence economies, up to 20 percent or
more of total annual income can be consumed by electric energy costs.
3-2
3.3 PLANNING OBJECTIVES AND CONSTRAINTS
Overall, for the purposes of this study, existing generating capacity
has been identified and cost of electricity has been estimated to
establish present day average annual energy costs assuming new diesel
generating equipment for each of the 36 communities under study. Loads
in each community have been forecasted for high and low load growth
scenarios over a period of 50 years to establish power requirements and
provide a basis for estimating the average annual cost of power
utilizing diesel generators and small hydropower powerplants.
A map reconnaissance of over 650 drainage basins was accomplished
during the preliminary screening to identify approximately 90 drainage
basins with hydroelectric development potential at 29 locations.
Projects which were identified were sized based on the assumption that
hydropower would be supplied on a run —of —the —river basis to individual
communities. Seven locations during the preliminary reconnaissance
were found to have no significant hydroelectric development potential
(assuming an isolated system to serve an individual community need) and
were eliminated from further consideration.)
The Corps of Engineers then selected, utilizing information provided in
the preliminary screening, 15 villages for field reconnaissance
studies. Field investigations were limited, because of the size of the
geographic territory under study, to villages which had not been
previously visited during the course of other studies or to those
communities with demonstrated strong potential for hydropower
development.
IStudy area communities with no significant hydropower development
include Igiugig, Egegik, King Salmon, Nelson Lagoon, Pauloff Harbor,
South Naknek, and Ugashik.
3-3
TABLE 3-1
TYPICAL COSTS OF ELECTRICITY FOR SMALL VILLAGES
WITH METERED CENTRAL ELECTRIC SYSTEMS
Village
Cost
Per
kwhl
$
1979
Average
Monthly
kwh
Monthly
Electric
Cost
$
Cost
Per
kwh2
$
1980
Average
Monthly
kwh
Monthly
Electric
Cost
$
Cold Bay
0.090
5344
48
0.134
534
72
Egegik
0.230
1833
42
0.343
183
63
King Cove
0.150
5344
80
0.244
534
170
King Salmon
0.180
5343
96
0.268
534
143
Kodiak
0.140
5344
75
0.209
534
112
Naknek
0.180
5343
96
0.268
534
143
Perryville
0.300
1213
36
0.447
121
54
Port Lions
0.250
1214
30
0.333
121
40
Sand Point
0.150
5344
80
0.224
534
120
South Naknek
0.180
5343
96
0.268
534
143
Unalaska
0.130
5344
69
0.194
534
104
Nikolski
0.260
1214
31
0.387
121
47
Old Harbor
0.327
1214
40
0.492
121
60
Port Heiden
0.200
1213
24
0.298
121
36
lFor villages
with central electric
systems and
meters;
including opera—
tion, maintenance,
and
distribution
costs; Source: 1979 Community
Energy
Survey, the
Department
of Commerce
and Economic
Development, Division of
Energy and Power Development, 1979.
2Assumes diesel fuel prices increased from an average of $0.65 per gallon
in 1979 to $1.30 per gallon in 1980. Diesel fuel accounts for 43 percent
of the total generation and distribution cost. Source: Small Hydroelec—
tric Inventory of Villages Served by Alaska Village Electric Cooperative,
Alaska Power Administration, 1979.
3Bristol Bay Energy and Electric Power Potential, Robert W. Retherford
Associates, Alaska Power Administration, 1979.
4Assumes average monthly residential consumption equal to either 121 KWH
or 534 KWH per month, an amount equivalent to communities with similar
socioeconomic characteristics to those communities identified in the
Bristol Bay Energy and Electric Power Potential Study (1979).
3-4
TABLE 3-2
TYPICAL COSTS OF ELECTRICITY FOR VILLAGES
WITH FLAT —RATE CENTRAL ELECTRIC SYSTEMS
Village 1979 Monthly Rate 1980 Monthly Rate
Atkal NA $ 40.00
Akutan $12.50 NA
Ouzinkiel $35.00 $ 60.00
Akhiokl NA $109.003
Adak2 NA NA
Attu2 NA NA
Nelson Lagoon NA NA
lGenerators run only part time.
2No published rate; U.S. Military Installation.
3Kodiak Area Native Association, Overall Economic Development Plan,
1980.
3-5
TABLE 3-3
APPROXIMATE RESIDENTIAL COST OF ELECTRICITY
FOR TOWNS WITHOUT CENTRAL ELECTRIC SYSTEMS'l
979
1980
Average Average Cost
Monthly
Average Cost
Monthly
Monthly of Energgy
Electric
of Energy
Electric
Village. KWH2 Per KWH2,3
Cost
Per KWH2,4
Cost
Akutan
120
0.14
17
0.297
36
Cape Chiniak
120
0.14
17
0.242
29
Chignik Lagoon
120
0.14
17
0.307
37
Chignik Lake
120
0.14
17
0.307
37
False Pass
120
0.14
17
0.307
37
Igiugig
120
0.14
17
0.307
37
Iliamna
120
0.14
17
0.297
36
Ivanoff Bay
120
0.14
17
0.297
36
Pilot Point
120
0.14
17
0.297
36
Larsen Bay
120
0.14
17
0.297
36
1No allowance for depreciation, operation, or maintenance of small
generators.
26ristol Bay Energy and Electric Power Potential, U.S. Department of
Energy, Alaska Power Administration, 1979.
3Assumes 4.5 kWh per gallon of energy are generated at a fuel cost of $0.65
per gallon, assuming the use of a small diesel generator set with capacity
in the 3-8 kW range.
4Assumes 4.5 kWh per gallon of fuel with price of energy computed on the
basis of 1980 quoted delivered price for diesel at the village.
3-6
4.0 ENERGY REQUIREMENTS
Electricity is produced in the study area from diesel generators
ranging in size from 3kW at communities without central electric
systems to 21,000kW at Kodiak by the Kodiak Electric Association. For
the most part, the isolated fragmented existing systems are
characterized by several generating units, which are small in size, and
receive maintenance at irregular intervals. Some systems operate
24 hours per day while other systems only operate during part of the
day. A data summary showing individual electric system characteristics
is provided in Table 4-1.
4.1 REGIONAL SETTING
A range of cultural, social, and economic characteristics may be found
over the 1500-4nile long study area. The study area covers
approximately 10 percent of the total 586,000—square mile land area of
Alaska. Study area territory falls within two major state planning
regions and three subregions as follows:
PLANNING UNIT
Southwestern Region
Bristol Bay Subregion
Aleutian Subregion
Southcentral Region
Kodiak—Shelikof Subregion
SQUARE MILES SQUARE MILES
40,000
11,000
51,000
11,000
11,000
Total Study Area 62,000
4-1
Extension of the national coastal zone limits in 1976 for commercial
fishing has resulted in regional economic growth throughout most of the
Alaska Peninsula, Kodiak Island, and Aleutian Island communities. This
has diminished fishing by Russian and Japanese fleets and set the stage
for further development of domestic commercial fishing and fish
processing.
The fishing and seafood processing industry is the economic base in
southwestern Alaska. Fishing is a seasonal activity, which relies
heavily upon transient labor. Therefore, fishing is not necessarily a
stable source of income for the residents. Salmon, King crab, Tanner
crab, and halibut are the main fish harvested in southwestern Alaska.
The bottomfish industry is beginning to develop in this area.
The trend of the fishing industry in the last 20 years has been toward
centralization. A number of canneries in the study area communities
have burned and have not been rebuilt. Fish processors are
concentrated presently in the following communities:
Unalaska — 15 facilities
King Salmon/Naknek — 9 facilities
Sand Point — 3 facilities
Kodiak — 2 facilities
Processors are also located in False Pass, Akutan (floating), Chignik,
Cold Bay (floating), and King Cove.
In addition to the growth of fishing and seafood processing, other
major regional development trends include:
1. Increased non—native population with a decrease in the
proportion of native population;
2. Native community social and cultural changes; and
3. Rapid community growth in villages with strong fishing —based
economies.
4-2
4.2 COMMUNITY CHARACTERISTICS
The current literature pertaining to the study area was reviewed in
order to determine existing electric energy consumption and predict
patterns of growth for each community. Information obtained from the
literature included current population and number of households,
population trends, community infra —structure, housing conditions,
economic activity, and community lifestyle.
The methodology developed for predicting electric energy requirements
throughout a 50—year period accounts for variations in socioeconomic
activity among communities. Village classfication by socioeconomic
characteristics for each of the 36 communities is given in Table 4-2.
In general, "very small" communities have a small and, in some cases,
declining population, subsistence economy, and some potential for
growth if the fish processing industry builds facilities in the area.
"Small" communities also have a small population but show signs of more
economic activity than do very small communities. "Growing"
communities have an expanding population and provide stable sources of
employment, primarily through the fish processing industry.
"Nonconventional" communities have a temporary or transient population
because they support military or government installations.
Annual household income generally increases with community size in
southwestern Alaskan villages. This relationship exists because
employment opportunities are in the fish processing industry which is
associated with growing communities. The disparity of annual income
among communities has been well documented (Alaska Health and Social
Service Consultants, Inc. 1979). For example, in 1977, over 50 percent
of the households in Akutan, where the economy is subsistence based,
had an annual income ranging between $0-4,999 and there were no
households in the over $20,000 income bracket. In contrast to Akutan,
50 percent of the households in Sand Point, where the economy is based
on commercial fishing, had earnings of more than $20,000 annually.
4-3
The income level of households has consequences for both future
electric energy requirements and power plant financing. Households
with relatively higher annual incomes have more disposable income to
spend on energy —intensive goods. Therefore, communities expanding in
the fish processing industry may have proportionately higher electric
energy demands.
4.3 COMMUNITY LOAD GROWTH POTENTIAL
The primary objective of developing a methodology for predicting future
electric energy requirements is to accurately forecast load growth for
each of the 36 communities, assuming each community will receive power
through a central distribution system. Load forecasts were developed
by examining the growth potential of each energy end use sector. End
use sectors included residential, schools, small commercial, government
installations, and fish processing facilities. In addition, the
electric requirements for space heating were differentiated between the
requirements for lighting and electric appliances since few of the
residences presently have electric space heating. Categorization of
electric consumption by end use enables identification of the major
electric energy users, making the methodology flexible if consumption
patterns change over time.
Electric energy demand, assuming central electric systems in 1980, were
calculated based on the number of households and the composition of the
community in terms of numbers and size of buildings such as schools,
stores, and community facilities. Population data were taken from the
1979 Community Energy Survey and Alaska's Energy Index. Electric
energy requirements for each end use sector were derived from the heat
loss calculations in the Alaska Power Administration funded study of
Bristol Bay with some modifications.
The electrification of the Alaskan villages is traced through the 50
year period 1980 to 2030. Electric energy consumption scenarios were
as follows:
4-4
Electric Energy Consumption Scenarios
1980 — Hydroelectric power plant installed; households increase
energy consumption from the pre-1980 level of 1452 kWh/year to
4356 kWh/year.I
1995 — Households increase energy consumption to 6000 kWh/year.2
2000 — One—fourth of village households have electric space heating
by year 2008, the mid —point of the 2000-2015 period; per
capita consumption of electricty for lighting and appliances
remains at 6000 kWh/year.3
IBristol Bay Energy and Electric Power Potential, U.S. Department of
Energy, Alaska Power Administration, 1979. Alaskan households which
draw electric energy from a central system consume approximately 4,356
kWh per year. p. A-289.
2R.W. Retherford and Associates indicated in the Bristol Bay Ener
and Electric Power Potential Study (p. A-294) that house o s were
using 4,356 k h year in 9 t has been assumed that households add
appliances through 1995 at a rate which increases household consump—
tion 2 percent annually. It has also been assumed that, at least in
many of the communities, residents are striving to obtain appliances
that will improve the standard of living. The HUD, for example, is
presently constructing homes in a number of Alaskan communities.
These homes resemble, at least on the inside, fairly typical American
homes. Homes which were visited by our staff members in the field
reconnaissance had a remarkable consistency over a geographic area.
Interviews with residents in each of the villages visited indicated an
interest and the economic means to acquire household appliances which
contribute to improved standard of living.
317he price of diesel was escalated at a rate of 5 percent per year for
the study period 1980-2030 in order to determine the substitution price
of hydroelectric power for diesel fuel for space heating. Based on
this assumption, it is indicated that it becomes economical for the
consumer to convert from a diesel burner to electricity for space heat—
ing sometime shortly after the year 2000. At this time, diesel fuel
reaches $4.00 per gallon, a price which is equivalent to the use of
electricity for space heating assuming one kWh costs approximately
$0.13. The reason for the disparity of price per kWh of equivalent
heat is due to the relative end use inefficiency of electricity for
space heating compared to diesel fuel.
4-5
2015 — One half of village households have electric space heating;
electric space heating in schools, stores, and public
buildings; per capita consumption of electricity for lighting
and appliances remains at 6000 kWh/year.
2030 — All households have electric space heating; electric space
heating in schools, stores, and public buildings; per capita
consumption of electricity for lighting and appliances remains
at 6000 kWh/year.
Rates of growth, which are given in Table 4-3, were calculated for each
community type through the four time periods. From each of the four
classifications, a representative community was selected for building
the growth scenario and establishing growth rates.
Population projections were built into the load growth scenarios.
Growth rates were based on the Bristol Bay Energy and Electric Power
Potential Study of population trends developed for the Bristol Bay area
and range from 0.5 percent per year to 2 percent per year (Retherford
Associates 1974). Since the expansion and development of the fish
industry will further the population growth in these rural areas, it
was assumed that a two percent growth rate would occur in the "very
small" study area communities. An annual increase of one percent was
assumed for the "growing" communities based on the theory that there is
an upper limit to population growthl. Similarly, it was assumed that
"small" communities would grow at a rate of 2 percent per year until
1995 and then decrease to 1 percent per year to 2020.
lThe Gompertz curve and logistic curve are two established methods
used in forcasting population. Both methods use a decreasing rate of
increase after a given time since populations do not proceed forever
at an exponential rate. In addition, the carrying capacity concept is
a planning tool used to forecast population given constraints such as
the available amount of developable land.
The underlying assumptions to these growth rates where electricity is
used for space heating were the heat loss calculations computed by
Retherford Associates in the Bristol Bay Energy and Electric Power
Potential Study — 1979. Some modifications were made and include a
reduction of the design temperature from 65`F to 62`F and a heat
content rate of diesel fuel of 140,000 BTUs/gallon. After considering
several factors which influence heating requirements (e.g., average
electric energy consumption by household, heating degree—days, wind
chill factor, and home construction and insulation), it was decided
that 23,300 kWh per household per year was a reasonable value for
meeting residential heating requirements in the study area. The
heating requirements for schools, public, and commercial buildings were
similarly adjusted utilizing the above assumptions. A summary of
assumptions used in predicting future energy requirements is given in
Table 4-4.
The insulation standard of homes in the study area varies
dramatically. The older homes tend to be poorly insulated while the
newer HUD homes meet stringent insulation standards. Heat loss from
walls, roof, doors, and windows, and infiltration through cracks around
doors and windows accounts for the total heat —transfer loss of a
building. Variables other than housing construction such as heating
degree—days and wind—chill factor influence the total heat loss.
Standard weatherization measures on existing homes include insulation
of walls and roof, caulking and weatherstripping to seal cracks,
double —paned windows, shower flow restrictors, draperies, and
insulation of the domestic hot water heater. These measures can
substantially reduce the heating requirements of older homes in the
study area.
The housing situation in southwestern Alaska is currently being shaped
by a HUD program designed to upgrade housing conditions in these remote
communities. The majority of communities in the study area either
4-7
presently have or are planning to move families from the older homes
into new HUD homes. These homes meet the HUD Minimum Property
Standards which include the following.)
Insulation R Value
Walls 19
Ceiling 38
Floor 30
Windows Double— or triple —paned glass
These standards also meet the U.S. Department of Energy regulations for
the State of Alaska.2
Annual load forecasts in kWh and kW for peak demand for electric energy
consumption for each community are presented in Volume II — Community
Hydropower Reports for high and low load growth scenarios.3 Electric
energy loads were individually calculated for all 36 communities for
the year 1980. Projections for the years 1995, 2000, 2015, and 2030
were calculated assuming growth rates outlined in the previously
discussed "Electric Energy Consumption Scenarios."
1Personal communication with Don Smith, Chief of Engineering and Archi—
tectural Division, U.S. Department of Housing and Urban Development,
September 1980.
2Federal Register. Residential Conservation Service Program, U.S.
Department of Energy, November 7, 1979.
3A high growth scenario was developed for the majority of the communi—
ties and shows higher electric energy demand from the addition of fish
processing facilities. For the very small community classification, it
was assumed that one fish processing facility would be added in 1995;
for the small and growing community classification, two fish processing
facilities would be built by 1995. It was assumed that nonconventional
communities (military or government) would not experience high load
growth from the location of fish processing facilities.
Table 4-1
Existing Village Power
System Data Summary
1980 ESTIMATED CURRENT METHOD
ESTIMATED NUMBER OF ELECTRIC UTILITY OF ELECTRICAL (2)(3) COST OF0I ESEL
COMMUNITY POPULATION HOUSEHOLDS NAME TYPE OF OWNERSHIP GENERATION INSTALLED CAPACITY FUEL $/GALLON
Aleutians and
Alaskan Peninsula
Adak
4500
615
None
-
Diesel
Unknown
0.945
Akutan
74
22
None
-
Diesel
- Hydro
20 kW (5 kW -Hydro)
1.335
Atka
90
22
None
-
Diesel
65 kW
1.335
Attu Island
40
13
None
-
Diesel
Unknown
0.945
Belkofski
12
6
None
-
None
-
1.385
Chignik Bay
73
15
(Alaska Packers Cannery)
Private
Diesel
- Hydro
2450 KW(50 kW -Hydro)
1.385
Chignik Lagoon
57110)
15R
None
- -
Diesel
75 kW in small units
1.385
loos
-
Chignik Lake
117
25
None
-
Diesel
135 kill in small units
1.385
Cold Bay
200
35
Northern Power E Eng.
Investor Owned
Diesel
1520 kW
1.335
Egegik
102
32
Naknek Electric Assoc.
REA Cooperative
Diesel
135 kW
1.335
False Pass
62
16
None
-
Diesel
15D V
in small units
1.385
Igiugig
40
12
None
-
Diesel
40 k
36 kW In small units
1385
Ilianna
125
27
None (REA Coop forming)
-
Diesel
125 kW
1335
1 vant,ff Bay
30
11
None
-
Diesel
50 kW
1335
King Cove
-409R
72 -
None
-
Diesel
3000 kW (will add 800 kW unit)
1.335
200S
King Salmon
350
70
Naknek Electric Assoc.
REA Cooperative
Diesel
1400 kW
1.335
Naknek
350
45
Naknek Electric Assoc.
REA Cooperative
Diesel
See King Salmon
1.335
Nelson Lagoon
55
15
None
-
Diesel
- Wind
120 kW
1.335
20 kW (wind)
Nikolski
60
24
Nikolski Power and Light
-
Diesel
40 kW
1.335
Pauloff Harbor
14
2
None
-
None
-
1.385
Perryville
101
25
None
-
Diesel
150 kW
1.335
Pilot Point
60
14
None
-
Diesel
unknown
1.335
Port Heiden
70
18
None
-
Diesel
225 kW
1.385
Sand Point
528
125
None
-
Diesel
1600 kW (Cogeneration used
'
to heat 5 large buildings)
1.335
South Naknek
153
37
Naknek Electric Assoc.
REA Cooperative
Diesel
See King Salmon
1385
Squaw Harbor
5
2
None
-
None
-
1.385
Ugashik
23
6
None
-
None
-
1.385
Unalaska
615R
1256S
200
City of Unalaska
Public
Diesel
1200 kW
1.025
Kodiak Island
Akhiok
114
15
None
-
Diesel
55 kW in small units
1.335
Cape Chiniak
125
25
None
-
Diesel
75 kW in small units
1.093
karluk
122
31
None
-
None
1.335
Kodiak
3624
940
Kodiak
Electric Assoc.
REA Cooperative
Diesel
-21,000 kW
1.093
Larsen Bay
111
51
None
-
Diesel
150 kW in small units
1.335
Old Harbor
138
45
Alaska
Village Elec.Coop.
REA Cooperative
Diesel
200 kW
1.335
ouzinkie
190
41
None
-
Diesel
80 kW
1.335
Port Lions
265
61
Kodiak
Electric Assoc.
REA Cooperative
Diesel
985 kW
1.335
(1) R = Resident
S - Seasonal
(2) Private Generator - 3 kW (Retherford).
(3) Does not include generating capacity of canneries.
TABLE 4-2
VILLAGE CLASSIFICATIONS
1. Very small community
Characteristics: minimal or no electricity; few community
facilities; no cannery or other place of employment; subsistence
economy; overcrowded housing conditions; some potential for growth.
Villages: Ivanoff Bay, Atka, Nelson Lagoon, Port Heiden,
Belkofski, Nikolski, Igiugig, Atkutan, Ugashik, Pauloff Harbor,
Squaw Harbor, Karluk.
2. Small community
Characteristics: public water supply; some community facilities,
unimproved roads; seasonal employment; potential for growth.
Villages: Egegik, Pilot Point, Chignik Lagoon, Chignik Bay,
Chignik Lake, Perryville, Ouzinkie, Akhiok, Larsen Bay, Cape
Chiniak, South Naknek, Iliamna, False Pass, Old Harbor, Port
Lions, King Salmon.
3. Growing community
Characteristics: population of 250+; central electric system;
public water supply; roads and some vehicles; fish processing
plants; stable sources of employment; modern school.
Villages: Sand Point, King Cove, Unalaska, Naknek, Kodiak
4. Nonconventional community
Characteristics: more a group of government and private agencies
than a community; people employed in the village are temporary or
transient; military community.
Villages: Cold Bay and Adak (exclusively military), Attu (Coast
Guard Station).
0,
TABLE 4-3
COMMUNITY LOAD FORECASTS — RATE OF GROWTH
1767-177�
1"o—LWu
cuuu-Lu15
Lu15-Luau
n ncrease
o Increase
n Increase
o Increase
per Year
per Year
per Year
per Year
(not com—
(not com—
(not com—
(not com—
Community Type
pounded)
pounded)
pounded)
pounded)
Very Small
4.3
25.5
11.4
3.6
Community
Small
6.3
17.6
11.6
6.3
Community
Growing
2.6
14.0
12.3
6.0
Community
Nonconventional
2.1
31.0
17.0
2.0
4-11
TABLE 4-4
ASSUMPTIONS USED IN PROJECTING
FUTURE ENERGY REQUIREMENTS
CURRENT ANNUAL ENERGY CONSUMPTIONI
Electric Use (lighting and appliances)
a. Residential — Average
(1452 kWh per year) — if supplied by private generator
(4356 kWh per year) — if supplied by central plant
b. School — Average
small school — 52,000 kWh/year (10+ households)
medium school — 105,995 kWh/year (30+ households)
large school — 230,060 kWh/year (50+ households)
C. Village stores (assumes 2 stores/22 families)
5,000 kWh/year
d. Public buildings (assume 1 community building/50 households)
3,644 kWh/year
e. Fish Processing — peak demand 400 kW
PROJECTED ENERGY CONSUMPTION
Population Increase
2 percent/year for very small villages
2 percent/year for small villages to year 1995, then
1 percent/year to year 2030
1 percent/year for growing villages (assuming more people will out
migrate because villages will reach a maximum population due
to limited land and resources at an earlier date than the
smaller villages).
Assume 4 person/household by year 20002
IBristol Bay Energy and Electric Power Potential, Retherford,
R.W. Associates, 1979, Appendix A, page A-289.
2Bristol Bay Energy and Electric Power Potential, Retherford,
R.W. Associates, 1979, p. 111.
4-12
Heating Requirements3
a. Residential — 23,300 kWh/year
b. Schools:
small school — 270,910 kWh/year
medium school — 494,960 kWh/year
large school — 1,100,260 kWh/year
C. Village stores — 36,700 kWh/year
d. Public buildings — 77,252 kWh/year
e. Cannery — peak demand 600 kW with freezers
Electric use (lighting and electrical appliances)
a. Residential — increasing to 6,000 kWh/year4
b. Amount of electrical consumption for schools, stores, and public
buildings is equivalent to consumption projected for the year 1985.
Projected system demand
Assume a 50 percent load factor.
3Based on heat loss calculations in Bristol Bay Energy and Electric
Power Potential, Retherford, R.W. Associates, 1979 Report.
4Based on current electric consumption of "typical" American home,
which is estimated to be 6600 kWh/year. Other Homes and Garbage,
p. 37.
Source: Leckie, J. et al. 1975. Other Homes and Garbage, p. 32.
4-13
5.0 COMMUNITY HYDROELECTRIC DEVELOPMENT POTENTIAL
The screening of 36 villages to identify hydropower potential was
accompished in four major phases which are summarized in Tables 1-1 and
1-2.
Preliminary Screening;
Field Reconnaissance;
Revised Screening; and
Detailed Layout and Cost Studies.
5.1 PRELIMINARY SCREENING
An inventory of water resources with hydroelectric development
potential within the study area was initially performed and resulted in
the delineation of over 650 drainage basins through the utilization of
USGS base maps and appropriate NOAA navigation charts (see Appendix —
Section A). Evaluations conducted during the preliminary screening
confirmed the need for maximizing the power potential at sites by
maximizing the head despite increased penstock costs and greater
difficulty of access to the diversion dam sites. This approach led to
the use of high hydraulic heads on very small capacity projects. The
number of candidate basins was reduced to approximately 90 basins by
applying a general set of screening criteria. The criteria used in the
process included:
1. Estimates of power potential derived from a rough appraisal of
each basin's drainage area, available head and average annual
flow using annual runoff values given in the Southwest Alaska
Regional Atlas (1979);
2. Transmission line distances which, depending upon each basin's
power potential and therefore voltage requirements, generally
limited the study area surrounding each community to a radius
of approximatley 15 miles; and
5-1
3. Potential dam site and powerhouse location which also included
an evaluation of usable head and penstock length.
For each of the approximately 90 sites, costs associated with
equipment, penstock, dam, and transmission line facilities were summed
to arrive at total energy costs in mills per kWh. Equipment costs were
derived (including allowance for operation and maintenance costs)
utilizing the empirically developed costing equations of Gordon and
Penman (1979).1
The average annual cost of energy at the most attractive hydroelectric
sites identified during this preliminary screening process was compared
to preliminary estimates of the average annual cost of diesel
generation for the low and high load growth scenarios.
5.2 FIELD RECONNAISSANCE
A field reconnaissance was conducted at 15 sites in the study area.
The purpose of the reconnaissance was to observe sites with development
potential, discuss hydroelectric development options with community
leaders and conduct in —the —field observations of dam and powerhouse
sites. Sites at which field reconnaissance was conducted are listed
below:
IThe Gordon and Penman studies provide an analysis of recent North
American small hydropower equipment costs with classification into
unit sizes above and below 500 kW of capacity. For each of these size
classes, a simple, quickly —applied formula provides an approximation
of all project costs with the exception of dam, penstock, and trans—
mission line costs. These costs were summed and multipled by 12.5 per—
cent (an allowance for interest, amortization, operation, and mainten—
ance costs) to arrive at installation (project) costs which were then
divided by average energy output assuming 50 percent plant factor to
provide the present value of project energy in mills per kWh.
61%
Port Heiden
' Chignik Bay
Chignik Lagoon
Chignik Lake
Perryville
/Ivanoff Bay
Akutan
Ouzinkie
^Nikolski
,'False Pass
' Cold Bay
King Cove/Belkofski
/Akhiok
Karluk
'Old Harbor
Aerial overflights and/or ground reconnaissance were conducted over
hydroelectric sites that were identified as having development
potential. During the preliminary screening, drainage basin
characteristics were observed, dam sites identified, and powerhouse
locations noted.
Meetings were held in communities to discuss the small hydropower
development potential and overall study purpose. Community leaders
were contacted in the villages by letter before site visits were
conducted. During meetings in the community, study purpose and
objectives were outlined, project schedule discussed, and State and
Federal agency responsibilities reviewed. Village leaders were asked
questions about their current level of electric service, power
requirements, population, fuel prices, environmental concerns, economic
characteristics, and anticipated changes in electric consumption
patterns should a more reliable and less costly source of power become
available.
5.3 REVISED SCREENING
Observations of project sites and community characteristics were useful
during the revised screening process. Data collected in the field were
used to check and update, where necessary, preliminary screening
assumptions made for load forecasting, hydrologic analyses, diesel
costs, and environmental observations. Sixty—eight sites were
identified in the revised screening as having the best hydropower
development potential. The screening process is described and data
summary is provided in Appendix C.
5-3
5.4 DETAILED STUDIES
Estimates of the cost of power for the diesel and hydroelectric options
were made. Estimates included capital costs, operation, maintenance,
and replacement costs and interest and amortization costs at the
Federal discount rate of 7-1/8 percent. Costs of diesel power were
developed for the low and high load growth scenarios at 0 percent, 2
percent, and 5 percent per year (real) fuel cost escalation. Detailed
(reconnaissance level) layouts and cost of hydropower alternatives
which exhibited positive benefit —cost comparisons to the fossil —fueled
(diesel) alternative were developed.
5.4.1 Fossil —Fueled Power Generation
Electricity generation costs (assuming new production to meet low and
high load growth projections) were estimated for all communities
studied, assuming power production fueled by middle distillate oil
using diesel generation technology for all communities but Kodiak.
Diesel technology was chosen due to the size ranges of the generator
sets involved: 0.05-7.5 mw. (For the City of Kodiak, efficient small
frame combustion turbines were assumed because their low cost would be
less than diesel to serve the same load.) Annualized capital costs,
operating and maintenance costs, and fuels and lube costs were then
estimated. The detailed estimate of annual cost of fossil —fueled power
over the 50—year period of analysis is provided in Volume II —
Community Hydropower Reports. Criteria which were assumed in
developing the cost of fossil —fueled generation are provided in the
Appendix — Section B.
5.4.2 Hydropower Generation
Detailed reconnaissance level studies were conducted of the diversion
dam, soils and foundations, waterways, mechanical and electrical
equipment, powerhouse, transmission lines, access, and mobilization and
demobilization. (Assumptions developed in determining project
configuration and cost are in the Appendix — Section C.) The studies
included review and evaluation of:
1. Previously completed reports;
2. Layouts of major project structures;
3. Manufacturer's data;
4. Transmission voltage requirements;
5. Access techniques; and
6. Contractor mobilization/demobilization requirements.
Diversion Dam
Studies were conducted on two types of diversion structures. At most
sites, a sheetpile and rockfill diversion structure as shown in Figure
2 would be appropriate. These structures would be used where soils
conditions allow the driving of sheetpile.
Alternatively, for sites where bedrock is exposed or large boulders
preclude the driving of sheetpile, a concrete diversion dam is
proposed. The dam, as shown on Figure 3, would be similar in
configuration to a sheetpile dam incorporating an intake structure, an
overflow section with fish ladder, and course gravel or riprap on the
downstream face.
Diversion into penstock pipe occurs from an intake box, slightly
recessed into one stream abutment, just downstream of the dam face.
Flows enter this intake box through a heavy grating —type trashrack,
located horizontally along the top of the box. This arrangement allows
for easy maintenance removal of any accumulated trash and the vertical
walls of the box exclude bottom sediment from the vicinity of the pipe
intake. A scour valve has been incorporated for periodical flushing of
bottom sediment accumulated outside the intake box. For the
sheetpile—type diversion structure, it is proposed that the intake box
be prefabricated from steel plate and then field —attached to the
sheetpile cutoff wall by bolting, thus avoiding the need for any
concrete.
5-5
An overflow weir is located centrally over the stream bed, with its
crest.elevation 3 feet above the top of the intake box. This will
allow winter flow to enter the penstock even after a 2—foot thick ice
cover has formed. A three —step fish ladder off the downstream face of
the weir also serves as an energy dissipator during high stream flows.
Soils and Foundations
The type of bedrock is of relatively minor significance for the very
small size hydraulic structures that would be required on this
project. Bedrock profile should be established at the intake and
powerhouse site. Diversion dam and powerhouse structures do not
necessarily have to be seated on bedrock, but could be supported on
dense gravel or in some cases, on soils of volcanic origin if tailrace
or tail channel exits from the powerhouse are protected. For both the
dam and powerhouse structures, a cutoff to bedrock would have to be
constructed in order to avoid seepage and subsequent potential piping
failure at the intake weir and undermining by eddying currents at the
powerhouse.
Waterways — Penstocks
During the preliminary screening, the length of penstocks had been
maximized in order to obtain large hydraulic heads. Minimizing the
cost of penstocks can be accomplished both by limiting the design
pressure and by reducing roughness of pipe, thus enabling the penstock
diameter to be reduced.
For the small size generating units involved in this study, ready means
are available to limit the potential pressure rise upon sudden flow
changes in the penstock, without resorting to relatively expensive
hydraulic structures, such as construction of surge tanks. The use of
pressure regulators reduces or eliminates pressure rise. In the case
of Francis units, this would be a separate valve synchronized with the
turbine flow control device. This can be arranged to function as a
5-6
synchronous bypass which would permit rapid load change without
changing the velocity in the penstock. When load stabilizes at a new
value, the bypass closes at a rate slow enough to make the pressure
rise insignificant.
Moderation or elimination of potential pressure rise from sudden flow
changes in the case of impulse —type turbines is built into the machine
in that the jet deflector reduces discharge to the wheel controlling
load without changing flow in the penstock. Therefore, the needle
closing time can be readily adjusted to a value slow enough to protect
the penstock from pressure surge.
The pressure regulator or the nozzle needle can be blocked from fully
closing in the event that it is desired to maintain some flow in the
penstocks to avoid freezing. If it is anticipated that any of the
plants might be shut down for long periods, the intake valves provided
at the head of the penstock can be closed to allow draining of the
penstock. These can be manually operated or electrically operated
locally or remotely.
Small diameter penstocks, (in sizes of 12" to 60" diameter under
pressure heads of 200 feet to 800 feet and with penstock lengths of
2,000 feet to 10,000 feet), for above —ground installation in Alaska
would be competitive in plastic or steel pipe.l A brief
state—of—the—art survey was carried out for the smoothest type of
readily available, long—lasting, and economic internal lining for both
factory manufactured steel pipes and field —assembled small diameter (5
feet and below) steel penstocks. The optimum lining proved to be
either polyurethane vinyl, hand coated in 3 to 5 mil thickness, or
mechanical extruded vinyl lining (30 mil). For the outside zinc rich
exterior primer with 2 protective coats polyurethane vinyl would be
suitable for the Alaska locations.
lEither FRP (glass fiber reinforced isopthalic resin) or high density
polyethelene, or lined and coated carbon steel ASTM-106 or 516.
5-7
Tar, tar enamel, tar epoxy, or asphalt exterior coatings would not be
recommended as these protective coatings become brittle and spall at
the sub -zero Alaskan winter temperatures.
Plastic pipe has been installed both above ground and underground for
water supply and sewerage service in the Alaska environment, and has
performed satisfactorily.
Wood stave pipe is readily available in the Pacific Northwest and
installation costs were obtained for pipe sizes above 24 inches,
smaller sizes being in the opinion of the manufacturer not
cost -competitive. Wood pipe would maintain a smoothness equal to
vinyl. Its main advantages are the readily transportable, light pieces
into which it breaks down and the manufacturer supplied support
cradles, use of which obviates the need for field installation of steel
and concrete supports. The pressure range for which this type of pipe
is being manufactured extends up to 450-foot head, corresponding
approximately to the lower half of the pressures considered in this
study.
The use of open canals was abandoned as the result of field inspection,
but similar penstock alignment was maintained in order to maximize the
low pressure pipeline sections of the penstocks. The use of a low -head
penstock section would be possible along the upper reaches of many
sites. Except for a very short section immediately downstream of each
intake weir, where burial and/or concrete encasements appear to be
practically a requirement in order to provide protection against
undermining and other damage from high flood flows, the penstock line
can be left exposed. (Burial of up to 2-mile long penstocks would, in
most cases, prove to be very expensive and the long-term environmental
impact from potentially extensive excavation and soil erosion could be
significant.)
M
Turbines
The turbine sizes evaulated range from 30 to 2,000 kilowatts, with
heads up to 800 feet.1 The turbines utilized are impulse -type
machines which have an inherent flexibility in terms of the number of
nozzels per wheel, unit speed, and the drive interface between turbine
and generator. With this type of turbine, there is only negligible
decrease in efficiency until the flows have decreased down to 30 or
even 20 percent. Accordingly, hydroelectric generation can thus be
basically maintained with two turbines to equally low flows.
Accordingly, on all the project sites the diverted flow through the
penstock is assumed to be divided at the powerhouse into two equally
sized impulse -type units. The typical arrangement, using two packaged
units, is shown on Figure 4. The penstock would bifurcate just
upstream of the powerhouse into two pipes, each supplying a skid -
mounted unit package, seated on a concrete base slab. Each unit would
discharge into a tailrace slot cut into this concrete base slab.
Because impulse turbines have to discharge into atmospheric pressure
above the maximum tailrace elevation, about 6 to 10 feet of hydraulic
head is lost compared to Francis type reaction turbines. This loss,
however, is negligible for most high head layouts.
1Discussions were held with the manufacturers of small -size, but
basically medium- to high -head turbines. One U.S. manufacturer
indicated that there were so few inquiries for impulse turbines that
they do not consider them for development. They had recently con-
sidered the possibility of standardization of small Francis -type
turbines, but no results were available to date.
The other long-established manufacturer expressed interest, but was
not able to give any pricing information whatsoever. He would,
however, offer impulse -type turbines to cover the entire project
range, including the relatively low -head, small capacity turbines
where use of Kaplan or horizontal Francis turbines would have normally
been expected.
Price information covering the full project range was provided by a
third manufacturer for this class of equipment which falls in the
application range of their integrated package units that include also
a governor, generator, and control equipment.
The package unit enclosures are supplied by the manufacturer and are
included in the total cost of the unit. If these package enclosures
prove to be not sufficiently insulated, a prefabricated wooden building
could be readily draped over the two unit packages. The additional
cost would be negligible in comparison with each project cost.
The preferred orientation of the powerhouse, directing the tailrace
flows to meet the stream at approximately 45 degrees, is shown in
Figure 4. It should also be noted that the vertical location of
impulse —type turbines approximately 5 feet above the tailrace water
surface effectively precludes any fish from entering the generating
units.
Transmission
Transmission line capabilities under relatively small loading and short
distances have been evaluated to assess transmission capabilities up to
5 megawatts at voltages of 7.2kv and 14.4kv. The economies involved do
not warrant consideration of higher voltages for the range of loads and
distances considered.
The transmission line capabilities for voltages and distances
considered are dependent primarily upon size and number of conductors,
voltage, distance, power factor, and, to a lesser degree, phase
spacing. This study assumed a minimum power factor of 0.9 and typical
phase spacing for 3—phase lines.
The basic, most economic transmission system, the single —wire ground
return (SWGR), has been selected for all the small developments
investigated. The SWGR transmission system is well —suited for
southwestern Alaska since ground moisture is required for
conductivity. This system is also appropriate for short transmission
distances until the combined effect of increased generating unit
capacity, and/or increased distance of transmission from powerhouse to
load center cause the line power losses to exceed 5 percent. A 7.2kv
5-10
or 14.4kv four —wire transmission line is suggested for larger and/or
more remote powerhouses. Use of this four —wire line is subject to the
same 5 percent loss consideration.
Submarine cable is used at a few sites. Use of submarine cable under a
few narrows increases transmission costs but does not cause a
pronounced jump in site development costs.
Site Access
The impulse turbines selected as the generating units are packaged in a
container which can be readily transported to the sites during
wintertime on a sled. Remote control projects are assumed for the
majority of the sites. Therefore, no permanent roads have been assumed
to be needed to powerhouse locations or other project features.
Access tracks to powerhouse and intake areas would be required. As a
basis for costs in the project area, the recent Alaska Power Authority,
1979, unit costs for Akutan have been adopted, except in a few cases
where these have been increased to allow for presence of more rugged
terrain. The total track mileage allows both for looping access track
to intake and penstock. The total track mileage allows for part of a
transmission line where the conditions appear to be sufficiently
difficult to call for an extra allowance.
Mobilization
Costs of mobilization were not developed, but an upper bound of
$500,000 was used based on reports on Akutan (Retherford, 1980). This
cost estimate includes both helicopter and highline access mobilization
to mountain top areas. For more readily reached sites these costs were
progressively decreased, with $100,000 estimated as the basic minimum
cost.
5-11
Economics
The sites with economic hydropower development potential were
determined by comparing the average annual cost of hydropower to the
average annual cost of fossil —fueled power generation. Costs of
fossil —fueled and hydropower power generation were determined as
described in the Appendix — Section B.
5-12
Iliamna
Igmgig Q
Naknek
King Salmon o,o
knek
n ,
MAF LflEA - int
a %0unnlue
Karlukfn \ B\ �sKotliak
tAs IUIf v "LL
Larsen Bay QZ� �, `/�I Cape Chiniak
KODIAK ISLAND e..-., i 17
Akhipk yd6
6 p
V
Atka
■ STUDY AREA COMMUNITY
KALE:
0 50 100 150
Attu :GIONAL INVENTORY & RECONNAISSANCE STUDY
SMALL HYDROPOWER PROJECTS
TIAN ISLANDS, ALASKA PENINSULA, KODIAK ISLAND
ATU ISLAND
STUDY AREA
FIGURE 1
DEPARTMENT OF THE ARMY
ALASKA DISTRICT
CORPS OF ENGINEERS
c
215�
J��11
10 0 10 20
1 1 1
SCALE IN FEET
REGIONAL INVENTORY & RECONNAISSANCE STUDY
SMALL HYDROPOWER PROJECTS
ALEUTIAN ISLANDS, ALASKA PENINSULA, KODIAK ISLAND
INTAKE STRUCTURE
TYPE A - SHEETPILE
FIGURE 2
DEPARTMENT OF THE ARMY
ALASKA DISTRICT
CORPS OF ENGINEERS
NORMAL_
MAINTENANCE
ACCESS
o VAR IESL
m®� 2
SLIDE GATE
0
SECTION A - A
't
SECTION B - B
AIR VENT
18" HIGH FISH
LADDER (TYP)
10 0 10 20
SCALE IN FEET
REGIONAL INVENTORY & RECONNAISSANCE STUDY
SMALL HYDROPOWER PROJECTS
ALEUTIAN ISLANDS, ALASKA PENINSULA, KODIAK ISLAND
INTAKE STRUCTURE
TYPE B - CONCRETE
FIGURE 3
DEPARTMENT OF THE ARMY
ALASKA DISTRICT
CORPS OF ENGINEERS
6.0 REFERENCES
Alaska Health and Social Service Consultants, Inc. 1979. Working
draft environmental impact statement for World War II debris
removal and cleanup, Aleutian Islands and Lower Alaska Peninsula,
Alaska. Alaska District, U.S. Army Corps of Engineers, Anchorage,
Alaska.
CH2M Hill Engineering of Alaska, Inc. 1979. Regional inventory and
reconnaissance study for small hydropower sites in southeast
Alaska. CH2M Hill Engineering of Alaska, Inc., Anchorage, Alaska.
Davis, C.V. and K.E. Sorensen. 1970. Handbook of applied hydraulics.
McGraw—Hill, pp. 1-1-1-46.
Department of Commerce and Economic Development Division of Energy and
Power Development. 1979. 1979 community energy survey.
Department of Commerce and Economic Development Division of Energy
and Power Development, Anchorage, Alaska.
Eisenhuth, M.P. ed. 1963. Index of surface water records to
Dec. 31, 1963 — Alaska. U.S. Geological Survey Circular 516.
Gale Research Co. 1978. Climates of the states. Volume I. Gale
Research Co. Detroit, Michigan.
Gordon, J.L. and A.C. Penman. Quick estimating techniques for small
hydro potential. Water Power. October 1979.
Gray, D. ed. 1973. Handbook on the principles of hydrology. Water
Information Center, Inc. — National Research Council of Canada,
pp. 8.1-8.64.
Harza Engineering Company. 1979. Black Bear lake project, a
reconnaissance report, pp. B1B-2, B—B-3.
Harza Engineering Company. 1979. Gartina Creek project: a
reconnaissance report. Alaska Power Authority, Anchorage, Alaska.
Kodiak Area Native Association. 1980. Overall economic development
program report for Kodiak Island. Kodiak Area Native Association,
Kodiak, Alaska.
Linsley, R.K. et al. 1975. Hydrology for engineers. 2nd ed.
McGraw—Hill, pp. 133-148, 223-283.
Maynard and Partch Architects. Aleutian region school district
comprehensive educational plan. Vol. 1 — Facilities Surveys and
Analysis. Maynard and Partch Architects, Anchorage, Alaska.
O'Brian, E. et al. 1977. Evaluation of small hydroelectric
Potential. Tippetts—Abbett—McCarthy—Stratton, N.Y.
6-1
Retherford, R.W. Associaties. 1980. Akutan Corps of Engineers site
no. 4 for Alaska Power Authority.
Retherford, R.W. Associates. 1979. Bristol Bay energy and electric
power potential phase I. U.S. Department of Energy, Juneau, Alaska.
Retherford, R.W. Associates. 1979. City of Unalaska electrification
study. R.W. Retherford Associates, Anchorage, Alaska.
Retherford, R.W. Associates. 1980. Preliminary feasibility designs
and cost estimates for a hydroelectric project on the Port Lions
River, Port Lions, Alaska. U.S. Department of Energy, Alaska Power
Administration, Juneau Alaska.
Retherford, R.W. Associates. 1980. Preliminary feasibility designs
and cost estimates for a hydroelectric project near Larsen Bay,
Alaska. U.S. Department of Energy, Alaska Power Administration,
Juneau, Alaska.
Retherford, R.W. Associates. 1980. Ram Creek hydro potential at Ring
Cave for Alaska Power Authority.
Retherford, R.W. Associates. 1978. Application for License Project
No. 2743. Volume 1. Terror Lake Hydroelectric Project.
Schaake, J.C. et al. 1967. Experimental examination of the rational
method. J. Hyd. Div. Procd. Am. Soc. Civil Engineer, Nov. 1967,
pp. 353-370.
Selkgregg, Lidia L. ed. 1976. Alaska regional profiles: southwest
region. Vol. III. University of Alaska, Arctic Environmental
Information and Data Center, Fairbanks, Alaska.
Tundra Times Energy Special. 1979. Alaska's energy index: where it
is, how it gets there, and how much it costs. Tundra Times.
U.S. Army Corps Engineers, Hydrologic Engineering Center. 1979.
Feasibility studies for small scale hydropower additions, a guide
manual.
U.S. Bureau of Reclamation. 1977. Design of small dams. U.S.
Department of the Interior. pp. 37-95.
U.S. Dept. of Energy, Alaska Power Administration. 1978.
Hydroelectric power potential for Larsen Bay and Old Harbor, Kodiak
Island, Alaska. Appraisal evaluation.
U.S. Dept. of Energy, Alaska Power Administration. 1979. Hydropower
at Atka, Alaska.
U.S. Dept. of Energy, Alaska Power Administration. 1979. Small
hydroelectric inventory of villages served by Alaska Village
Electric Cooperative. Hydro Projects Office. Seattle, Washington.
6-2
U.S. Environmental Data Service. 1975-1979. Climatological data,
Alaska. Vols. 36-65. National Oceanic and Atmospheric
Administration.
U.S Federal Power Commission. 1979. The 1976 Alaska power survey.
Volumes I and II. U.S. Federal Power Commission.
U.S. Geological Survey. 1976. Water availability, quality, and use in
Alaska. U.S. Dept, of Interior Open File Report 76-513,
pp. 153-192.
U.S. Geological Survey. 1961-1977. Water resources data for Alaska,
water year 1977 etc. to 1961. U.S. Department of the Interior.
U.S. Water Resources Council. December 14, 1979. Procedures for
Evaluation of National Economic Development (NED) Benefits and
Costs in Water Resources Planning (Level C); Final Rule. Federal
Register, Wasington, D.C.
University of Alaska. Arctic Environmental Information and Data
Center. 1978. Aleutian/Pribilof Islands region community
profiles: a background for planning. Alaska Department of
Community and Regional Affairs, Fairbanks, Alaska.
Woodward —Clyde Consultants. 1977. Oil terminal and marine service
base sites in the Kodiak Island Borough. Woodward —Clyde
Consultants, Anchorage, Alaska.
6-3
REGIONAL INVENTORY AND RECONNAISSANCE STUDY
FOR SMALL HYDROPOWER PROJECTS
ALEUTIAN ISLANDS, ALASKA PENINSULA, KODIAK ISLAND, ALASKA
APPENDIX
DEPARTMENT OF THE ARMY
ALASKA DISTRICT, CORPS OF ENGINEERS
GENERAL CONTENTS
Title Section
Hydrology A
Economic Analysis B
Hydropower Studies C
Federal and State Permits
SECTION A
HYDROLOGY
The purpose of the hydrological analysis was to develop accurate
synthetic streamflow information, in the absence of actual long term
data, to be used in determining the hydroelectric power potential of
candidate streams in the vicinity of the 36 study communities.
Initially, annual average streamflow was determined to generally
characterize stream size and annual average power potential. These
averages were then modified by synthesized annual flow frequency curves
to estimate the yearly stream flow patterns which affect hydroelectric
generating capabilities.
Climate
The climate of the southwest region of Alaska encompassing the study
communities is basically dominated by maritime air masses. Average
annual precipitation in this region is generally less than the maritime
areas in southcentral and southeastern Alaska, typically ranging from
20 to 70 inches. Leeward coastal locations may receive an annual
average precipitation as low as 13 inches. The north sides of the
Alaskan Peninsula and Aleutian Island chain are considered leeward
since the precipitation producing winds generally come from the south.
Temperatures (in Farenheit) typically fall between the mid-50's for a
summer maximum to the mid to low 20's for a winter minimum. Record
extremes for the Aleutian chain are —50F and 77`F (Selkgregg 1976).
In general, there is a high degree of variability in the maritime
weather patterns which can be attritubed to local geography and
topography. The region's climate can therefore be considered to be
composed of a series of maritime micro —climates. It is therefore
desirable to localize hydrological analyses using the nearest available
precipitation and streamflow data.
A-1
Rainfall data in the southwestern region of Alaska, especially covering
the Aleutian Island chain and the Alaska Peninsula, is limited. The
most complete summarization of data appears in the Alaska Regional
Profiles series (Selkgregg 1976). According to this atlas, 16
locations, with the exclusion of Kodiak Island, have at some point in
time monitored precipitation for a period of three years or longer. A
check of Climatological Data of the U.S. (U.S. Environmental Data
Service 1979) for the State of Alaska indicates that presently only
nine of these stations are in operation, including one station on
Kodiak Island. A list of these stations is given in Table A-1,
together with long—term annual average precipitation. Figure A-1
presents isohyets of annual precipitation developed from National
Weather Service and U.S. Geological Survey (USGS) information.
Ctroamflnw
Gauged streams in the study region are more numerous than precipitation
stations, but unevenly distributed. Based on USGS Water Resources
Data. (USGS, 1961-1977), there are 23 streams in the study area where
flows have been measured for a period of one year or longer. However,
11 of these occur on Kodiak Island, and of the remaining 12, six are
located on Amchitka Island, three on Shemya Island, and two are large
rivers fed by large lake systems. With the exception of Eskimo Creek
at King Salmon, there are virtually no records of streamflow
measurements on the entire Alaskan Peninsula and the Aleutian Island
chain to Amchitka Island. As a result, the developed hydrology
methodology relied heavily on recognized estimating techiques to
correlate the existing flow and precipitation data to the streams of
interest.
For initial power potential estimates and site screening purposes, a
rough estimation of streamflow for ungauged streams was made by
applying the rational principle (Linsey et al. 1975, Davis and Sorensen
1970, Gray 1973, Scaake 1967):
A-2
Q a A (1)
Where Q is streamflow in cubic feet per second (cfs) and A is Basin
(watershed) area in square miles (mi2). Areas of equal mean runoff,
unit Q/A values in cfs/mi2, have been derived by the USGS for the
State of Alaska (USGS 1976). These data which are presented as
isolines (Figures A-2, A-3, and A-4), were used to initially
approximate streamflows by multiplying unit flow values by estimated
basin areas.
For subsequent screening, more accurate estimation of streamflow was
made by using a modified rational formula, incorporating factors to
account for precipitation and elevation differences between basins.
The formula is developed as follows:
The rational equation is given as: Q = ciA (2)
Where Q is streamflow, i is rainfall intensity, A is basin area,
and c is a ground cover factor. Thus, for areas of similar weather
patterns and ground cover, a proportion can be set up, so that:
Q1/A1 = Q2/A2 (3)
where the subscripts 1 and 2 refer to gauged and ungauged streams,
respectively.
Addition of precipitation and elevation adjustment factors yields the
expression:
Q2/A2 = (Q1/A1) P + (nH) E (4)
where P is a derived precipitation related flow adjustment factor, off
refers to an elevation differential, E is a derived elevation related
flow adjustment factor, and Q2 is the modified ungauged streamflow.
A-3
To properly implement Equation 4, it was necessary to pair gauged
streams with ungauged streams, check flow records for "normalcy," and
then determine appropriate precipitation and elevation flow adjustment
factors. Based on proximity to study site, period of record, basin
size, general topography, and climatological (weather system)
similarity, five representative gauged basins were chosen to be paired
with the ungauged study basins. Gauged streams paired to ungauged
streams at each of the study area sites are given in Table A-2. Daily
flows for complete years of record were computerized, and annual
average flows were calculated for these five gauged basins.
Due to the relatively short period of record for several of the gauged
streams and the fact that many recorded years could not be considered
"normal", but rather high or low flow years, the development of flow
adjustment factors was necessary. The factors were developed using
long—term nearby precipitation data. Annual rainfall for each
corresponding year of streamflow data was summed and placed in a ratio
with the long—term average rainfall times the number of years of
streamflow gauge record. As an example, complete records for the Upper
Thumb River were available for 1974, 1975, and 1977. Precipitation at
the nearby Kodiak station for these years was 71.4, 79.85, and 80.8
inches respectively, totalling 232.05 inches. Three times the long
term (30 year) average annual precipitation of 56.71 inches per year
totals 170.13 inches. The adjustment factor, therefore, becomes
170.13/232.05 or 0.735, indicating that a period of higher than normal
precipitation occurred when the Upper Thumb River was gauged.
Developed adjustment factors for each gauged stream are as follows:
Gauged Stream Adjustment Factor
Bridge
Creek
1.18
Eskimo
Creek
1.05
Myrtle
Creek
0.95
Upper
Thumb River
0.735
Terror
River
1.05
GL�
Using the basin areas for the above streams at the gauging station
location, as determined by the USGS, the unit runoff for each of the
five basins was calculated and expressed as cfs/mil. This value was
then multipled by the adjustment factor to yield a corrected runoff in
cfs/mi2. The corrected runoffs, in cfs/mil, represent the Q1/A1
ratio in Equation 4.
The precipitation factor (P) is intended to incorporate known
precipitation data in the area of each ungauged stream into the flow
calculations. For the five gauged streams, long term annual normals
(in inches) from the nearest representative precipitation station are
chosen as the base precipitation for the basin. For the ungauged
streams, basin precipitation is determined by nearby precipitation
stations or by use of precipitation isolines developed by the National
Weather Service and the USGS (Figure A-1). The ungauged basin's long
term annual precipitation is then placed in a ratio to the
corresponding gauged basin's long term annual precipitation to develop
the precipitation factor. These factors and related information are
included in Table A-3. In several cases, the precipitation stations or
isolines for the gauged and ungauged streams are the same, resulting in
unity factors.
An elevation factor (E) is necessary to correct for increased
precipitation at higher elevations. Previous studies in southeastern
Alaska have estimated this factor to be 0.0045 cfs/mi2 per foot of
elevation in a region receiving 16-20 cfs/mi2 of runoff based on USGS
isolines, and 0.003 cfs/mi2 per foot of elevation in a region
receiving 8 cfs/mi2 of runoff (Harza Engineering Company 1979). The
only gauged stream in the study area with gauges at two elevations is
the Terror River, with stations at approximately 1200 and 200 feet
MSL. Assuming a linear precipitation distribution and using the runoff
data for the two stations coupled with the two USGS determined areas,
an elevation correlation factor of 0.003 cfs/mi2 per foot was
calculated for the Terror River. These stations lie between the 4 and
8 cfs/mi2 runoff isolines determined by the USGS. Based on this
FTIM
information, it was judged reasonable to apply no elevation correction
for basins with damsites below 200 feet MSL, and elevation corrections
of 0.0015 cfs/mil per foot of elevation for streams falling within
the USGS 2 cfs/mi2 runoff isoline, and 0.003 cfs/mil per foot of
elevation for streams falling within the USGS 4-8 cfs/mi2 isolines.
The elevation difference (oH) is specific for each stream, and is the
difference between the dam elevation and an elevation of 200 feet MSL.
Elevations were determined from USGS topographic maps or altimeter
measurements made during the field reconnaissance.
The areas of the ungauged streams (02) were determined by locating the
dam sites on a detailed USGS base map, outlining the drainage basins
contributing runoff to that point, and planimetering the resulting
areas. Standard planimeter techniques were observed in this
determination.
Flow Frequency Curves
Using the computerized flow records, dimensionless annual flow
frequency curves were generated for the five gauged streams paired to
each of the ungauged streams in the study area. These curves are shown
in Figures A-5 to A-9.
Since the curves are dimensionless, they may be applied to the
corresponding ungauged streams. Once the annual average streamflow is
determined as outlined in the preceeding section, typical annual
minimum and maximum flows may be estimated directly from the graph.
The flow frequency curves were also used in the detailed analysis of
hydroelectric generating capability for those sites which exhibited an
economic development potential. The area under the curve represents
the total volume of water available in a year, and hence is a
representation of the average flow and the theoretical maximum
available energy.
A portion of the area under the curve is defined by the design and
minimum operational flow ratio values for a given generating unit or
combination of units. This area represents the actual volume of water
available in a year to generate power. The ratio of this area to the
total area thus represents the capacity factor for the installation.
Optimizing the use of the area under the flow frequency curve and
therefore the amount of usable energy is an extremely important design
process involving tradeoffs between energy utilization and equipment
costs. The design flow is typically chosen for a run of the river
system to be 1.4 to 1.5 times the average annual flow or a flow that is
exceeded at least 15 percent of the time. The minimum operational flow
is determined from manufacturer's specifications, typically 20 to 30
percent of a unit's design flow (U.S. Army Corps of Engineers 1979;
O'Brian et al. 1977). A detailed discussion of the engineering process
utilized in this study is presented in Appendix C.
MA
TABLE A-1
Station
PRECIPITATION STATIONS IN THE STUDY REGION
Period of Record Long Term Annual Average
In Years (Through 1975) Precipitation in Inchesl
Attu2
20
56
Shemya2
27
27
(28.17)
Amchitka
7
36
Adak2
25
68
Atka
8-15
60
Nikolski
3 112
82
Driftwood Bay
10
21
Dutch Harbor
7
58
Sarichet Cape2
16
28
Cold Bay2
30
33
(33.23)
Port Moller
4
43
Port Heiden2
16
13
King Salmon2
24-30
20
(19.75)
Lake Brooks
10
15
Intricate Bay
10
36
Iliamna2
26
26
(26.26)
Kodiak2
>20
--
(56.71)
lIncludes water equivalent of snowfall. Values taken from Selkgregg
1976. Values in parenthesis are long term (30 year) averages taken
from Gale Research Company, 1978, summarizing U.S. Weather Bureau and
National Oceanic and Atmospheric Administration data.
2Station currently reporting data according to U.S. Environmental Data
Service, 1979.
M
TABLE A-2
HYDROLOGIC STUDY BASIN PAIRINGS
1) Bridge Creek on Amchitka Island (USGS 15297680)
Adak Attu Island
Atka Nikolski
2) Eskimo Creek at King Salmon (USGS 15297900)
Egegik Pilot Point
King Salmon Port Heiden
Naknek South Naknek
Nelson Lagoon Ugashik
3) Myrtle Creek near Kodiak (USGS 15297200)
Akutan
Ivanoff Bay
Belkofski
King Cove
Chignik Bay
Pauloff Harbor
Chignik Lagoon
Perryville
Chignik Lake
Sand Point
Cold Bay
Squaw Harbor
False Pass
Unalaska
Akhiok
Cape Chiniak
Kodiak
Old Harbor
Ouzinkie
4) Upper Thumb River near Larsen Bay (USGS 15296550)
Karluk
Larsen Bay
5) Terror River at mouth near Kodiak (USGS 25-2957)
Port Lions
A-9
TABLE A-3
UNGAUGED STREAM PRECIPITATION PAIRINGS AND FACTORS
Study Precipitation Station/ Precipitation
Community Isoline Factor
Adak
Adak
1.79
Atka
Atka
1.67
Attu
Attu
1.56
Nikolski
Nikolski
2.58
Egegik
Isoline
1.00
Iliamna
Iliamna
1.32
King Salmon
King Salmon
1.00
Naknek
Isoline
1.00
Nelson Lagoon
Port Moller
2.18
Pilot Point
Isoline
1.00
Port Heiden
Isoline
2.03
South Naknek
Isoline
1.00
Ugashik
Isoline
1.00
Akutan
Isoline
0.56
Belkofski
Isoline
0.56
Chignik Bay
Isoline
1.00
Chignik Lake
Isoline
1.00
Cold Bay
Cold Bay
0.56
False Pass
Isoline
0.56
Ivanoff Bay
Isoline
1.00
King Cove
Isoline
0.56
Pauloff Harbor
Isoline
0.56
Perryville
Isoline
1.00
Sand Point
Isoline
1.00
Squaw Harbor
Isoline
1.00
Unalaska
Dutch Harbor
1.00
Akhiok
Isoline
1.00
Cape Chiniak
Isoline
1.00
Kodiak
Kodiak
1.00
Old Harbor
Isoline
1.00
Ouzinkie
Isoline
1.00
Karluk
Isoline
1.00
Larsen Bay
Isoline
1.00
Port Lions
Isoline
1.00
A-10
El
C
Precipitation valueS include the water equivalent of the snow.
O C E
A N
,o l
lJ
a
+❑
eo y 0 SOgO 150
, aC�N�f'• I!,
:o A A L A S'KA o Ts Iso zzs
!o
a OF hllomel erJ
y a a p
lao Qa G Q L ss] st..: CUT,,, ts""i's sz o. Q OQ3
zJi
Q Anal7 6a.1 Oq 0
rQa 13° n6° ° 180° lib
Adopted from National Weather Service and U. S. Geological Survey
Figure A-1
Mean Annual Precipitation Distribution
Taken from Selkgvegg, 1976
Figure A-2
Estimated Mean Annual Runoff in the
Kodiak-Shelikof Subarea
HBO Ise Iss° Isa°
1620
e2.
BERINC SEA — N°•I,Nx.;•,r�, Ir'•'.""
�e.„ -'.
P"oy,�rj'k tl E'"1k
Cape L,onto,,.,;dV,•I�I�i.. �I a9'a
'
5 h. 1... )
Am •Nu ,:aN{ y, P.•, �1xp+��5 IJl Ba��'•i/v��Td
O II m
4 mmdk sl «a... P ia�E,I S°,r°xs •' , l
UI, , and : fo 9 J " • °to �\ ° �C y • F 1
mane .. q
sxn �aResOdNnP ase ¢..,
Q:r �µ aP �. a "'w:°a .a �y asay �. °'Roll Fry Ra INu
I ,m d - L°
B, F' , � / ls: � . y s. F., A�i' • g''I P } ♦R, R. f:aiu. 'iJ {GL j1'r'i, •.'.
A"o:un MMM cr.r°r G�� T �,9GtIN�
N a 4P "... °e ^ } elu..'I . Flan.ar 1 J1 .y W.a:'rr A:-n. .
Ca + p hate, , 1 d f an L 4e .z'1C .:_ J 'S
°' h.. °j ,. y�g I . 'y °f •t a j_',r>r ds jS`a�-aa
I/n ae :.;e' p°mn HJ a-T ;� 1.' S, 4j-C4°ne .l '+^faurp.. a' C.i I �••- e`fy...
:An, ra. alask °°. iR ♦�,ay, n.,eorl I.
0
N. a Island °sn:° ,. ,G a.ls I a I Sand.' Q...,:.. ,
n, pa55 `OMc
F
ARM
' r i
.r�,Pm P. •, n, a C,r S _
O
F O �
T S PACIFIC OCEAN 5,
s1 Ilon U,S, Oaelogl cal .....A up E (Bella 1:2.500.00) PI Alaska
Oala Ilea IOlnl lads fa l-S1ala land Use Planning Ca.Niasld. (19N)
17B°
BERING SEA ,L 1700
U T $t Paul I
1 um aoe°ssor a wa"us I r
510
p nak Is sl Pa •°C
CA h,.Iand, " 5
uu I
'x ca°'°/e/ No Ra/ ti` [__
RIBILOF SLANDS FGFF
NAi ION
�nx aKa S, Ann
,
AP
Rr•,� "fe,an„O VooP� '"'•e,. 6R1N Ual",P• SI Ge°ge L MEAN I,kUll
V RIE f{fI P{N
zGS. A'.USF'IHE a�5am I. su.. ,.., 53 B In uu�iNtGe°rRel Ouu[ IIIIE
a Ali / a / .,a / Y
PACIFIC OCEAN 170° FALEUTIAN
PORTION
1706 SUBAREA
Figure A-3 PILES
Estimated Mean Annual Runoff
in the Eastern Part of the Aleutian Subarea
?I Attu Island c^
P. BER I
L
Tn.uO°re Pam 'L Q 2
N F.AR ISLANDS?. j T
PRde u 1 A N
h
Se. a.a; -u -••o.
PL
.•. .. s:... u- ..
Pal_ `; .. AT ) 2
Bird Cat- $ l A
I !i Amchitka I2975
-' c°•.�^;'^°
FC 2976'.8'5 2916.5
2916.9 2910.55
teen Ir°n U.9.faa lOgleal Surrey a.R F (aeele 1:2.500.00) of Alaeka Pole Iron Joint FaUrtal-Slala Lino URA Planning Lonai Ralon (1011)
78° Wes: ' Greerl6,Ch 176° 174'
I1
2 1
1
/�
.....
t
aOrMv'n; .. �
EXPLANATION
N
S
L
A
5.e.r.I t.Atka
''
A7990
I
019LONTINUEO CARING.
A .. :. =+
s �N
STATION SITE
P•
NUMBERS ARf 01 TXOUT THE I
V'
•m.GA—.�_:-
itli •_T Ad
_, �•,•
, _ 'a'afa.
\,
bTAiE PXfFIa IS
Tanagal'+"ca •'_ nr„+
\
1
•"•''t'
%'AdaA le•
LIME OF-EOUAI MEAN ANNUAL
.I pa•
! .
RVMOLP IX CVBIL 11IT PEI
2
tf'y
Y°Alr C
faLOXO IER ROUART MILL
E
R
WEST PORTION
ALEUTIAN SUBAREA
0 50 YI LES
Figure A-4
Estimated Mean Annual Runoff in the
Western Part of the Aleutian Subarea
8.0 +
I
7.0
6.0
5.0
Ratio
4.0
Discharge
to
Mean
Discharge 3.0
2.0
1.0
.0
Bridge Creek
1 1 2 2 3 3 4 4 5 5 6 6 7 7 8 3 9 9
5 O 5 0 5 O 5 0 5 0 5 0 5 0 5 0 5 0 5
O O 0 O O 0 0 O 0 0 0 0 0 U 4 O 0 0 U 0
Percent of Time Flow is Equaled or Exceeded
1
0
0
0
REGIONAL INVENTORY 8 FEASIBILITY STUDY
SMALL HYDROPOWER PROJECTS
ALEUTIAN ISLANDS, ALASKA PENINSULA, KODIAK ISLAND
Figure A-5
Flow Frequency
Curve for
Bridge Creek
(U.S.G.S. 15297680)
ARMY
9.0 +
8.0
7.0
4.0
Ratio 5.0
Discharge
t0 4.0
Mean
Discharge
3.0
2.0
1.0
I
I
I
I
.O +
Eskimo Creek
Adjusted Average Annual 2Flow = 13.4 cfs
Drainage Area = 16.1 mi
I REGIONAL INVENTORY & FEASIBILITY STUDY
SMALL HYDROPOWER PROJECTS
ALEUTIAN ISLANDS, ALASKA PENINSULA, KODIAK ISLAND
1
Figure A-6
1 1 2 2 3
3
4
4 5 5 6 6
7 7 6
S 9 9 O
Flow Frequency
5 0 5 O 5 O
5
0
5 O _ 0 5
0 5 0
5 0 5 0
Curve for
U 0 0 0 O 0 O
O
O
0 0 0 O 0
U 0 0
0 0 O O
Eskimo Creek
(U.S.G.S. 1529791
(DEPART
Percent of Time Flow is Equaled or Exceeded
ARMY
Ratio
Discharge
to
Mean
Discharge
7. 0
6.0
5.0
4. 0
2.0
1.0
.O
1 1 2 2 3 3 4 4 5 5 6 6 7 7 8 8 9
5 O 5 O 5 0 5 0 5 0 5 0 5 0 5 0 5 0
. .
O O O O 0 0 U 0 O O 0 0 O p O 0 0 0 U
Percent of Time Flow is Equaled or Exceeded
1
9 0
5 0
0 O
REGIONAL INVENTORY 8 FEASIBILITY STUDY
SMALL HYDROPOWER PROJECTS
ALEUTIAN ISLANDS, ALASKA PENINSULA, KODIAK ISLAND
Figure A-7
Flow Frequency Curve
for Myrtle Creek
(U.S.G.S. 15297200)
For:
DEPARTMFNT OF THE ARMY
7.0
I
6.0
5.0
Ratio 4.0
Discharge
to
Mean 3.0
Discharge
2.0
1.0
C.
Upper Thumb River
A............ n........1 rl..... _ Cn 9 ..Q..
1
1 1 2 2 3 3 4 4 5 5 6 6 7 7 3 S 9 9 0
5 O 5 O 5 0 5 O 5 0 5 O 5 0 5 0 5 O 5 U
O 0 0 O O 0 O O O O 0 U 0 0 0 O O 0 0 U 0
Percent of Time Flow is Equaled or Exceeded
REGIONAL INVENTORY 6 FEASIBILITY STUDY
SMALL HYDROPOWER PROJECTS
ALEUTIAN ISLANDS, ALASKA PENINSULA, KODIAK ISLAND
Figure A-8
Flow Frequency Curve
for Upper Thumb River
(U.S.G.S. 15296550)
ARMY
7.(
6.(
5.0
4.0
Ratio
Discharge
to 3.0
Mean
Discharge
2.0
1.0
1 1 2 2 3 3 4 4 5 5 1
6 6 7 7 8 8 9 9
5 0 5 G 5 O 5 0 5 G 5 G 5 0 5 0 5 O 5 0
b O O O U b O O 0 U O G O O O U 0 O O 0 0
Percent of Time Flow is Equaled or Exceeded
's
REGIONAL INVENTORY 6 FEASIBILITY STUDY
SMALL HYDROPOWER PROJECTS.
ALEUTIAN ISLANDS, ALASKA PENINSULA, KODIAK ISLAND
Figure A-9
now Frequency
Curve for Terror River
(U.S.G.S 15-2957)
DEPARTMENT OF THE ARMY
ALASKA DISTRICT
CORPS OF ENGINEERS
SECTION B
POWERPLANT OPERATING AND COST CRITERIA
Fossil —Fueled Power Generating Analysis
The following assumptions were made in the analysis of community diesel
generating costs:
Installed Capital Cost — The installed cost of diesel generating
sets was based on the cost to put the machine in operation within
isolated villages. The cost of diesel for all communities (but
Kodiak) was assumed to be $575/kW of installed capacity assuming
"Caterpillar" diesel generator sets. The estimate accounts for
machine cost, transportation, installation, engineering, and
contingencies.
Curtis —Wright combustion turbines were assumed for the city of
Kodiak at a cost of $400 per kW for systems requiring less than
10OMW and $350 per kW for systems with more than 100MW of installed
capacity.
The 1980 investment was sized to meet 1990 peak demand.
Investments were calculated in size increments as follows:
1. 0 to 500kW in 50kW increments; and
2. More than 500kW in 1OOkW increments.
Operating and Maintenance — For diesel generating costs, it was
assumed that systems with less than 1000kW capacity would be
operated by 1.5 workers per year; costing $30,000 per year. For
systems in the 1 to 1OMW range, 3 workers per year costing $60,000
per year were assumed. Maintenance costs were estimated at 6
percent of the installed equipment value of $175/kW.
M1
Combustion turbines, 0 and M costs were estimated at 0.5
cents/kwh. Lubricants were excluded in the combustion turbine 0
and M costs.
Machine Replacement Period — It was assumed that new diesel units
would have a useful life of 10 years with no salvage values under
the conditions that would be found in remote Alaska villages in the
Aleutians, Alaska Peninsula, and Kodiak Island. Diesel in these
villages receive maintenance at irregular intervals and spare parts
are at times difficult to obtain. Combustion turbines were
projected to have a useful life of 25 years. No salvage value was
assumed.
Plant Factor — A plant capacity factor of 50 percent was used for
diesel and combustion turbines in arriving at the average annual
cost of power. This value is consistent with values used in other
reconnaissance level studies in Alaska.
Fuel and Lubricant Cost — Fuel and lubricant costs were based on
June 1980 quotes from major fuel suppliers. Fuel costs were
escalated over the life of the project at 2 percent and
alternatively at 5 percent annual real price escalation rate.
Caterpillar indicates a fuel consumption rate of 0.08 gallon per
kWh for its systems. Further, their data show that diesel
equipment can respond to partial loads quite effectively. (This
fuel consumption rate approximates a heat rate of 11,000 BTU/kWh.)
Lubricants costs were assumed to be 10 percent of fuel costs.
For the Curtiss—Wright combustion turbine, the heat rate was about
equal to the diesel system, so fuel consumption was considered
equal to diesel plants.
The analysis of village diesel power cost at the Federal discount rate
of 7-1/8 percent were made for the high load growth scenarios at (real)
fuel price escalation rates of 2 and 5 percent. These analyses are in
Section 5.0 of the main report for each of the 36 communities.
BE
Hydropower Generation Analysis
The average annual cost in mills per kWh at the Federal discount rate
of 7-1/8 percent was calculated for the high load growth scenario for
each project which demonstrated economic power potential as a result of
the revised screening studies. The analyses of energy costs were
conducted for low and high plant factors, a ratio of average energy
used to energy available.
Low Plant Utilization Factor
The value of energy available as determined from the flow frequency
curves must be reduced. To derive the plant utilization factor, the
average annual energy which would be available (if 100 percent of the
average annual discharge could be utilized) would be for the five
drainage basins studied is given in Figure B-1 to B-5 and as follows:
Bridge
Creek
72
percent
Myrtle
Creek
66.5 percent
Upper
Thumb River
67
percent
Eskimo
Creek
80
percent
Terror
River
70
percent
Since the yearly demand will not necessarily track generation
potential, the above percentages were reduced by 15 percent. Since
this implies a 24—hour demand, it was also necessary to account for the
drop in demand in the late night and early morning hours, the plant
utilization factor value was therefore further reduced by 25 percent.
(This reduction in power generation is reasonable when compared with a
reported typical plant factor value of 30 percent for small hydropower
installations [U.S. Depart. of Energy, Alaska Power Administration,
1979]).
W
Plant utilization factors (for the low case) for the communities (see
Table A-2) used to compute average annual cost of hydropower using the
above assumptions were as follows:
Bridge
Creek
46
percent
Myrtle
Creek
42
percent
Upper Thumb River
43
percent
Eskimo
Creek
51
percent
Terror
River
45
percent
High Plant Utilization Factor
A second analysis was conducted assuming 100 percent of the average
annual energy generated would be used in a system. (The maximum
percentage of average annual flow for 2 generating units.) This case
would be representative of those systems where hydropower replaces a
portion of diesel power or where seasonal and monthly load fluctuations
are reduced to a minimum. The value of energy in mils per kwh
(discount rate equal to 7-1/8 percent) represents a lower limit for
average annual cost of power produced by hydroelectric plants. Plant
utilization factors for these cases for communities (see Table A-2)
represented by the flow frequency curves are as follows:
Bridge
Creek
62
percent
Myrtle
Creek
67
percent
Upper Thumb River
67
percent
Eskimo
Creek
80
percent
Terror
River
70
percent
Analyses of the low and high plant utilization factor options are
presented in Section 5.0 of the main report.
Benefit —Cost Comparison
The benefit —cost ratio, for purposes of this analysis, is then defined
by the present worth of the average annual cost of diesel divided by
the present worth of the average annual cost of hydropower.
M
8.0 a
1
7.0
6.0
5.0
Ratio
4.0
co Discharge
Ln to
Mean
Discharge 3.0
2.0
1.5
1.0
0.2
.0
Bridge Creek
1 1 2 2 3 3 4 4 5 5 6 6 7 7 a a 9
5 0 5 0 5 0 5 O 5 0 5 0 5 0 5 0 5 O
U 0 O O U 0 0 0 0 U 0 0 0 O U 0 4 0 O
Percent of Time Flow is Equaled or Exceeded
1
9 O
5 0
0 O
in
REGIONAL INVENTORY b FEASIBILITY STUDY
SMALL HYDROPOWER PROJECTS
ALEUTIAN ISLANDS, ALASKA PENINSULA, KODIAK ISLAND
Figure B - 1
Flaw Frequency
Curve for
Bridge Creek
(U.S.G.S. 15297680)
ARMY
7.0
6.0
5.0
4. 0
Ratio
Discharge
to 3.0
Mean
Discharge
0.2
.O
1
5
1
0
t
5
2
O
2
5
3
0
3
5
4
O
4
5
5
0
5
5
6
0
6
5
7
0
7
5
5
0
9
5
9
0
9 O
5 0
0 O
O
0
O
O
0
0
0
O
0
O
O
O
0
0
0
0
0
O 0
Percent of Time Flow is Equaled or Exceeded
an
REGIONAL INVENTORY & FEASIBILITY STUDY
SMALL HYDROPOWER PROJECTS
ALEUTIAN ISLANDS, ALASKA PENINSULA. KODIAK ISLAND
Figure B - 2
Flow Frequency Curve
for Myrtle Creek
(U.S.G.S. 15297200)
DEPARTMFNT OF THE ARMY
7.0 +
1
6.0
5.0
Ratio 4.0
Discharge
to
Mean 3.0
Discharge
0.2
.0
Upper Thumb River
1 1 2 2 3 3 4 4 5 5 6 6 7 7 8 6
5 0 5 0 5 0 5 0 5 O 5 0 5 0 5 0 5
O O O 0 0 O O O 0 0 0 O 0 0 O 0 0 O
Percent of Time Flow is Equaled or Exceeded
fs
can
1
9 9 0
O 5 0
o u 0
REGIONAL INVENTORY 6 FEASIBILITY STUDY
SMALL HYDROPOWER PROJECTS
ALEUTIAN ISLANDS, ALASKA PENINSULA, KODIAK ISLAND
Figure B - 3
Flow Frequency Curve
for Upper Thumb River
(U.S.G.S. 15296550)
DEPARTMENT OF THE ARMY
ALASKA DISTRICT
CORPS OF ENGINFERS
9.0 +
8.0
7.0
6.0
Ratio
Discharge 5.0
to
Mean
Discharge 4.0
2.0
1.5
1.0
0.2
.0
Eskimo Creek
t
1 1 2 2 3 3 4 4 5 5 6 6 7 7 8 8 9 9 O
5 0 5 O 5 0 5 0 5 O 5 0 5 0 5 0 5 0 5 0
O 0 0 0 0 0 0 O 0 0 0 0 0 0 0 0 0 0 O O 0
Percent of Time Flow is Equaled or Exceeded
n
REGIONAL INVENTORY 8 FEASIBILITY STUDY
SMALL HYDROPOWER PROJECTS
ALEUTIAN ISLANDS, ALASKA PENINSULA, KODIAK ISLAND
Figure 8 - 4
Flow Frequency
Curve for
Eskimo Creek
ARMY
0
7.0
6.0
5.0
Ratio 4.0
Discharge
to
Mean 3 o
Discharge
2.0
1.5
1.0
0.2
.O
1
1 1 2 2 3 3 4 4 5 5 6 6 7 7 8 8 9 9 0
5 O 5 0 5 0 5 0 5 O 5 O 5 O 5 O 5 0 5 0
0 O U O 0 0 O O 0 O O O 0 U O O U 0 0 O 0
Percent of Time Flow is Equaled or Exceeded
s
lean
REGIONAL INVENTORY & FEASIBILITY STUDY
SMALL HYDROPOWER PROJECTS.
ALEUTIAN ISLANDS, ALASKA PENINSULA, KODIAK ISLAND
Figure B - 5 I
Flow Frequency
Curve for Terror River
(U.S.G.S 15-2957)
ARMY
SECTION C
HYDROPOWER STUDIES
Screening Studies
The screening methodology in this study was a continually evolving
process. It was initiated by cataloging potential drainage basins
within the study area, and culminated by the preliminary engineering
and detailed cost estimates of the optimal hydroelectric power
potential at sites at each of the 36 study communities.
The initial inventory of drainage basins containing flowing streams was
made utilizing both United States Geologic Survey (USGS) base maps and
National Oceanic and Atmospheric Administration (NOAA) navigation
charts. Based on previous transmission line and access road cost
experience, a distance limitation of approximately 15 miles from each
community was imposed on this inventory. Sites beyond this 15-mile
radius exhibiting a high power potential as compared with sites within
the 15-mile radius were in some cases studied further. This process
resulted in the delineation of over 650 drainage basins for the 36
community locations.
Approximate power potential was estimated for these 650 basins based on
the formula suggested by the U.S. Army Corps of Engineers (1979):
Average Power Potential (kW) = (0.85) Q H (1)
11.8
where Q is streamflow in cubic feet per second (cfs) and H is the
elevation differential (head) in feet between damsite and powerhouse.
Streamflow values were developed through estimates of drainage basin
area and the runoff isolines reported by the USGS (1976). Heads were
estimated by use of detailed USGS topographic maps, including the 15
minute series maps where available.
C1B1
A screening committee comprised of the Project Manager, Project
Engineer, and Project Hydrologist reviewed information developed for
the USGS maps on the 650 sites, and evaluated the basins associated
with all 36 communities. The committee eliminated streams showing
little or no power potential, as well as distant sites showing
approximately equivalent potential to nearby sites. This evaluation
process reduced the 650 plus basins to approximately 90. A prime
criterion during this review process was to attempt to develop at least
one viable candidate site for each of the 36 communities under study.
This, however, was not always possible and for the communities of
Egegik, Igiugig, King Salmon, Nelson Lagoon, Pauloff Harbor, Ugashik,
and South Naknek, no feasible sites could be delineated.
For the remaining potential sites, more detailed estimates of potential
power were made and values for the cost of energy were developed.
These cost estimates were derived from empirically developed costing
equations of Gordon and Penman (1979)1 and component costing curves
developed by the U.S. Army Corps of Engineers (1979). This procedure
is described in detail below.
Average annual flow estimates were derived via the methodology
previously described with refinement of determining drainage areas
above each damsite by planimetric techniques. Penstock length
(distance from damsite to powerhouse) and static head were calculated
from USGS topographic maps, using 15 minute series maps with 50 or 100
foot contours where available. Net head (Hn) was assumed to be 90
percent of the gross (static) head (Hg). Average power for each site
was then calculated via Equation 1 using net head values and again
assuming an overall efficiency factor of 85 percent.
IThe Gordon and Penman studies provide an analysis of recent North
American small hydropower equipment costs with classification into
unit sizes above and below 500 kW of capacity. For each of these size
classes, a simple, quickly —applied formula provides an approximation
of all project costs with the exception of dam, penstock, and trans—
mission line costs.
C-2
E(kWh) = (0.5)(8760 hours/year)(MC)(3 units) (2)
For cost estimating purposes, a configuration of three units capable of
operating up to 1.5 times the average flow was chosenl. This yielded
a machine capacity per unit (MC) of 0.5 times the average power value.
An average annual energy value (E) expressed in kilowatt—hours (kWh)
was then determined by using Equation 1 assuming a combined load factor
and energy availability factor of 50 percent. (A lower plant
utilization factor was assumed to calculate the electricity which could
be used by a community since the projects, as proposed have no
allowance for storage.)
The capital cost of all equipment (Ce) excluding penstock, dam, and
transmission lines was then calculated using the empirical formula
suggested by Gordon and Penman (1979).
Ce (mid-1980 Dollars) = 9000 S K (MC) 0.7 (H) —0.35 (3)
S is a siting factor which relates actual project cost to equipment
cost and was assumed to be 3.7 for plants below 500 kw capacity and 2.6
for plants above 500kW capacity, as suggested by the authors. The
constant, K, is composed of an Alaskan cost factor, assumed to be 2.0,
the number of units (3) and an escalation factor, (1.08)3, which
updates the author's early 1978 costs to mid-1980 values.
Penstock costs were estimated using a costing curve adjusted to 1980
dollars (Figure C-1) which gave costs in dollars per foot. This factor
was multiplied by penstock length to obtain the total cost in dollars.
Transmission costs were estimated by an approximating formula:
Ct (mid-1980 dollars) = MC (100) (distance in feet) (4)
lThree units were originally chosen in the screening phase of the
study to maximize use of available flow at the damsite, thus opti—
mizing power generation potential. Calculations using the flow
frequency curves performed during the detailed engineering phase of
the study indicate the addition of a third unit did not prove to be
cost—effective, gaining an average of only 2 percent in generation
potential.
C-3
Dam costs (Cd) were estimated by a costing curve, adjusted to 1980
dollars (Figure C-2), which gave the amount of concrete required in
cubic yards. Costs were then determined using a factor of $425 per
cubic yard (mid-1980 dollars) for dam construction (CH2M Hill 1978).
Installation costs (CI) were calculated as the sum of equipment costs
(Ce), penstock costs (Cp), dam costs (Cd), and transmission costs
(Ct). Energy costs in mills/kWh, were then calculated by Gordon and
Penman's empirically determined equation which assumes that the annual
cost of a hydroelectric plant is 12.5 percentl of the total project
cost:
Cost of energy (mills/kWh) = (0.125) (CI) (1000 mills/$) (5)
E
Using this developed cost of energy and preliminary estimates for the
cost of diesel, a benefit cost comparison based on the cost of diesel
power generation and the cost of hydroelectric power generation were
then calculated for all candidate sites. Communities having sites with
ratios greater than one and which were not previously studied were
included in the itinerary of the scheduled field trips.
During the field trip, as many of the candidate sites were observed as
was possible, either by air or from the ground. Elevation differen—
tials and streamflows were checked, and damsite and powerhouse loca—
tions were evaluated.
lIncluded in this cost is an allowance for interest and amortization
at a discount of 7-1/8 percent and operation and maintenance at 5.375
percent.
C-4
Following the field trip, the data collected were again evaluated by
the committee. Dam and powerhouse locations were revised, resulting in
modifications to basin area, penstock length, and head. Based on
observations from the field trip, sites which showed poor potential or
which were extremely costly were eliminated from further considera—
tion. Also some sites were reinstated, as their power potential
appeared greater than original estimates developed from the map study.
Revised estimates of power potential and energy costs were then made
for these remaining 68 sites utilizing the same procedure as described
above with the following modifications: 1) Site specific runoff and
streamflow values were developed (refer to Section A, Hydrology); and
2) transmission costs were determined with revised formulae. New
benefit —cost comparisons were then developed using the revised energy
and revised diesel costs as given in C-1. For those communities having
potential hydropower sites showing benefit —cost ratios greater than
one, more detailed engineering and cost estimates were performed for
the most promising damsites.
Detailed Studies — Layouts and Costs
Detailed studies were conducted at each location demonstrating economic
(or potentially economic) hydropower development potential. The
studies consisted of identifying streamflow potential (Section A) as
well as selecting a damsite and appropriate layout, penstock material
and route, turbine, powerhouse site, transmission type and route,
access, and mobilization estimate.
Dam:
The type of dam site selected depended upon soils and foundations
conditions found in the project site. Soils and foundations
information was obtained from detailed soil classification data of the
U.S. Department of Agriculture Soil Conservation Service (1973). The
classification data describes soil types, terrain slope, erodibility
and stability for roads, and other types of foundations.
C-5
The SCS data helped to identify areas of coarse volcanic ash soil and
the limited areas of impervious soils. (The use of canals (flumes) was
decided against because preventing erosion and ensuring water —tightness
in many cases was difficult). Soils maps aided in the further
identification of rocky and steep mountainous areas where access,
penstock, and transmission line construction would prove to be
difficult and more costly.
Sheetpile dams were utilized where unconsolidated material allowed for
the driving of sheetpile. In those cases where bedrock was exposed, a
concrete dam was selected for estimating purposes.
The cost of dam is based on the crest length of the dam and dam type.
Crest length was determined by utilizing the graph in Figure C-3. The
crest length for reconnaissance purposes was assumed to be a function,
of the valve assigned to penstock design discharge (field observations
generally substantiated this relationship which depends on some
consistency between sites). Costs were then assigned for both types of
dams of varying crest length assuming the configuration of dam as
illustrated by Figures 2 and 3 (main report).
Costs were based on quantity takeoff from the typical drawings (Figures
2 and 3). As a base, the abutment sections were costed out together
with a 30—foot minimum wide creek bed section. Additional costs per
foot of widening of dam overflow section were developed as a separate
subitem.
C-6
The quantities developed and the unit rates assumed were as follows:
1. Sheetpile Dam:
— Base Structure (for 30—foot wide creek)
Item Quantity Unit Cost ($) Total $)
Sheetpiling (8 gage) 2,435 s.f. 12.151 29,505
Backfill 320 20 6,400
3 9 ,985
say $40,000
— Incremental cost for each 10—foot widening of overflow
Section
Sheetpiling 340 12.51 $4,500
say $5,000
2. Concrete Dam:
— Base Structure (for 30—foot wide creek)
Item Quantity Unit Cost ($) Total ($)
Concrete 150 500 37,500
Excavation 8 50 400
Backfill 132 20 2,640
Valves and Grating L.S. 5,000
$80,540
say $80,000
— Incremental cost for each 10—foot widening of overflow
Section
Concrete 20 500 10,000
Excavation 3 150 150
0,150
say $10,000
lBased on assumed cost of $20/linear foot of 10-3/4" wide section.
C-7
Penstocks:
Penstock diameter was based on the design flow, head, and length of
penstock. Minimizing the costs of the penstocks was accomplished by
limiting the design pressure and by reducing the roughness of the pipe
to effectively decrease pipe diameter.
The costs of plastic and steel pipe were for a range of diameters and
operating heads. Curves used to obtain penstock costs are provided in
Figure C-4. Sea freight, ground transportation (beach to site), and
support and installation costs are included. Costs were developed from
discussions with manufacturers and are based on 1980 price quotations.
Turbines:
Impulse —type turbines were selected for all projects. These turbines
have an inherent flexibility in terms of the number nozzles per wheel
unit speed, and the drive interface between turbine and generator.
Each turbine has been assumed to be able to operate with negligible
loss in efficiency until flow has decreased to 27 percent of design
capacity or one—half the penstock capacity as given by the following
equation:
0.5 x 1.5Q average = 0.75Q average streamflow
Estimates of the cost of powerplants (including turbine generator,
generator, and control equipment) were obtained from manufacturers.
Costs for the turbine generator package are given by the curve in
Figure C-5.
RN
Transmission
Transmission line cost studies were undertaken to assure representative
transmission costs as project sites were identified that were as far as
17 miles from the load center (isolated villages). Cost studies
indicated that the single -wire ground return (SWGR) was the most
economic for most communities.
Since none of the communities that were studied (that had economic
development potential) were in permafrost areas, the SWGR support
system recommended in the Bristol Bay Energy and Electric Power
Potential Study (Retherford 1979) was modified to a single wood pole
type that would be suitable in non -permafrost areas.
Transmission distances and increased generator unit capacity in some
cases increased to the extent that they precluded the use of SWGR
systems. For those cases where the combined effect of increasing
generator unit capacity and/or increased distance caused line power
losses to exceed five percent, a four -wire transmission line would be
used.
Costs were then developed for the 7.2kv SWGR and for both the 7.2 kv
and 14.4 kv four -wire transmission lines. Costs for each transmission
line are provided in Table C-2 and C-3.
Mobilization and Access:
Several reports prepared for hydropower development in the State of
Alaska were reviewed to provide an estimate of mobilization and access
costs. Mobilization costs were assumed to vary between $100,000 and
$500,000 based on report review. Track costs were estimated to be
$25,000 per mile.
C-9
It was assumed that mechanical equipment, including turbine generation
components, penstock transmission materials, sheetpile, and concrete be
transported by barge or be off—loaded by freighter. Less conventional
systems which were considered and dismissed include:
1. Air cushion barges — Barges of this type have been used to
cross the Yukon River in 8—knot currents.
2. Cross—country track crane — A tracked vehicle capable of
handling payloads up to 20,000 pounds has been developed to
operate over extended distances and steep terrain. This unit
has been used to erect transmission lines on slopes up to 50
percent.
[9BU
TABLE C-1
IIIOR,IPWLA SWEEI1016 PROJECT "A !MnwtE l )
Lotion
Stvem
Distance
Avenel
Dr.,....
Area
Penstock
Langan
Penit.tk
Flevatlws
a."
Was
AYerew Net
Flax Read
Avenge
merle
He Ca0ltal
Penstock
Om
innmif
Nytlnw.er
Mefel
$l to Me.
Aame
(III
t( fs/nit)
el ail
ft.
ft.i
It.)
Cfs
fft.I
Poxer
(kw)
NeCM1Iw
Par Wt
G D- Fne ny
XeaJ
Lps[
Cast
Cost
saw
Cost
Lost
Insta166
Ene
CDMY
[Emi) I61
BLOet�t
Eky
1f_
aol tars
(dollars) (dollars)
eo11ers1 dollars
hills Yu6
mllspxa.
c_N.i__
"AY
I
1.2
8.0
4.3
1.2
1.9
7500
1101,400
600
5.2
HO
201
IW
1.310.00
165
I,O60,W]
253,OW
85.wo
as,WD
I.5W,00D
142
54
1
2.3
4.1
3.6
4.2
!SW
19W
fiW-W
3W-1W
fiW
200
),9
11.8
510
3W
151
1,980,OW
165
1.41D,OW
80,WD
85,OW
36o,W0
1,9)O,OW
11l
123
61
.45
I
3.0
].5
].176
25W
250-50
200
12.8
I80
IN
192
96
1.260.ow
55
I, S10.OW
56.W0
as No
12Y.W0
1.970.OW
64
.Si
IN
83
%ogo.OW
55
1,3)0,W0
IW,000
as am
12D,W0
1,6)O,OW
193
61
.33
.3]
AYu[an
1
130
6.2
1.]
0-3
WW
60D40
us
26.6
SW
no
am
6.310.Wp
@2
2.290,W0
2W.DW
aS.NW
LJW.WD
4,280,Wp
05
22B
3
1.0
0.2
6.]
6.2
0.5
IWO
61D-50
am
1.8
$20
fill
31
441,000
158
505.OW
35.DW
B5.OW
so.M
)66.000
191
228,
1.68
1,16
2.5
]OW
600-40
5fi0
3.1
SW
112
5fi
136.000
152
126.OW
105.0W
85,ow
4B4OW
961.Wp
164
228
1.39
4
6.2
3W0
6W-20
SBO
3.1
52D
11)
58
I62,0W
I58
7M.om
ID5.W0
85,0W
140,000
I,OW,WO
111
228
1.31
Alle
1
2
4.0
3.6
4.4
4.0
BWO
6000
580.80
BM-200
NO
fiW
14.5
450
469
235
3.090,W0
137
2.050,0W
320.0W
1
8.5
0.5
4A
4.0
1.0
NW
I0W-2W
800
8.1
1).5
540
720
311
9W
Iw
2,080,W0
165
1,160,000
210,OW
85.W0
BS 00g
RW.WO
2,6fi0,OW
IW
220
2.11
5
0.7
3.2
2.9
42W
225-25
2W
9.3
10D
I
453
60
$.950,OW
180,000
_
20
I,HO, WD
315,oW
BS,OW
280,OW
850,0M
2,0]O.OW
3.030.OW
122
i2B
Le)
1
0.1
3.2
2.0
IOQO
110-10
IW
6.l
W
11
20
26].WD
1]S,oW
68,Wo
1,390,W0
6J
21
1,440, WO
85,N
I8.W0
BII,WU
220
Us
228
1.04
81elu
1
6
3.3
2.4
1SW
Nonage
200
7.8
180
101
SOfiH,WO
55
228
0.59
4elkoraNES)
958, 000
52,gW
IIIIII280.
WD
1,180,W0
262
Ito
.12
1
2
5.3
2.3
4W0
300-00
220
IZ.3
20
17e
89
1,170,000
61
1,380,000
160,OW
96,0W
110.000
1,790,0W
191
319
NA(6)
a 19n1k BaY
3 Negro [L
3
9.0
2.6
4200
2W-50
"a
23.6
135
2;9
IIS
4
In61en U.
1
9.2
3.4
35W
RW-20
E30
jp,8
210
466
23]
LSIO.oW
],p6D,000
41
am DW
210.WD
85,CW
160,0W
2.350.W0
195
Mania
fi4
2,6)O,OW
192,OW
85, 000
80,0W
3,020.WD
124
168
1.15
Lesson
bray G.
9.1
12W
2W
58.9
180
48
49
j
@rouek U.
3.1
].S
10.]
1.8
1
6000
Aa.
620-IW
440
10.9
400
543
272
518, 000
3,5)O,aW
55
6I6.OW
42,W0
BS,WO
We
IW,OW
Mom(21
1,1100W
11110,am
240
LI2
n
IZZ
1,6)O,000
210,W0
85
86
268
268
l.R
1
I --A
9--s
Loca tf.r/
Sll�tb.
Strav
Oaf_
Dfetance
As vfJ
Orain19e
area
Pen, We
Lengln
Penstock
Elevat40n
finis
NeeO
Avenge
Flpr
Net Average
Neetl
Metric
Neln UDitJ
Penstock
Dan
TraGsts,ton
NyNron.wr
Metal
L1)
cfs/n1 i
(nl2)
Eft.)
f0.
ft.)
cfs
Poxer
ft. (41)
Hi:M1lne Uy.
Per
`il`In
xstl
COst
fast
Cos[
fast
Installed
Energy
Energy
6eneflt
0lgnik
lake
wit
(al
sellers
sell4rs
L�
tlol tars
L�
sellers
tlollers
0111/MlM1 '
.Ills Min
Canost
,,i,a.
g
1
Bear G.
Nuce Ch.
1.8
2.4
9.9
10.5
1.3
O.S
26M
24M
500.2W
1W
12.4
270
242
tat
1,590.000
I,HO,WO
1
Cutu cer a.
3.0
9.0
8,0
WW
600-180
300-IS
WO
185
5.0
I50
42
5,OOD,O
37
Iw
98l 000
ID4,OW
09,OW
as am
112,OW
1.BIp,WO
115
250
LR
12.1
110
AD
89l
442
5.610.W0
o
52
3,160,000
6)5.000
5, 000
AS,:,
05,000
Il6,WD
300.ow
1,290,000
191
150
1.66
U16 BaY
1
2
5.0
3.0
6.2
1.9
1.5
11
am
3I00
600-200
IOW-25D
AM
9.6
360
249
125
2.640,000
110
1,150,000
280,OW
4,22D,oW
91
250
2.)5
A
3
ISA
6.2
3.2
35W
fiW-2W
150
fiW
9.2
26.2
6)S
HO
99J
2I1
2, 943, WO
2W
IdI0,W0
I3D,DW
05,OW
85,000
i10,W0
I60,OW
1150,D0D
133
US
1.M
J.0
6.2
6.9
160W
600-110
430
43.1
3W
982
IN
194
6,150,bW
),9W.OW
]AN
2,270.M
135,OW
B5,000
I.SW,WD
1'100 OW
1,03, ago
89
I)5
1.9)
a06
119
2,950,OW
960.000
BS,WD
3W,0W
4.2W.000
).
61
IJ5
175
2.)4
2.61
a Paia
2
2
1
3.0
10.0
5.6
6.2
20.7
2.9
45W
10500
60-I0
4W- IW
500
IW
116.E
IDW
1MIN
24,9W,000
196
6.220.00
450,OM
Illlewa
10.1
315
315
416
2W
2,130,OW
96
2,IIO,OW
1>2,oW
85,OW
85,000
]W,WO
),WO,OW
Ifi
173
4.80
1
910,W0
3,1 W,oW
113
III
111
3.0
1.1
2.5
20D
200-150
50
2.7
45
9
4
52.6W
14
leaner a,
266,W0
31.W0
85.000
160.00
602,000
1.430
103
3
0.7
9.0
4.5
10W
155-35
I'D
40.7
145
425
212
2,790,00
H
2.H6.W0
0.01
[In9 Cove
420,000
W
"'WOBS"'WO],IIO,OW
153
IR
1.78
fi
S
5,0
4.5
5,4
5.1
1.4
1.0
45W
SOW
1620
400-IW
]W
30D
25,5
5.6
230
195
248
3.260,0W
A2
2.550.OW
225,000
270
110
55
)23,OW
82
881.000
1 )S.WO
as GOO
fiS,OW
lIO,OW
1,1W,OW
119
163
1.])
MYnek
220.W0
1.]60,p00
2]5
0.49
1
2.8
0.8
1.0
2oW
50-15
l5
0.9
32
2
1
13.1W
10
I13.000
)b,oW
flS,OW
153.000
420.0W
4,000
161
0.61
Drainage
Loh[lesf
Stream
Wit...
A-.ff
Area
Sue So.
"area
ME)
cfs mR
n( 121
Nlkolikl
2
12.5
5.2
2.8
1
Sheep Ck.
1.4
4.3
4.3
Perryr117e
1
10.0
12.4
6.2
2
4.0
10.5
1.5
Pilot point
1
10.0
0.8
e.a
Port Held..
2
0.rebara h.
0.0
2.1
10.8
I
Pelndeer h.
13.0
1.0
26.6
Sam Point
2
4.9
5.3
0.4
Sauau Harbor
I
1.5
6.3
1.5
mlaaea
1
Shalahn1k0f
A. 5.5
10.2
9.3
2
2.0
9.)
4.4
Akhfak
.0
9.6
0.7
1
11.8
19.1
.
]
LB
9.1
1 .1
O aina9e
Lacatl0n/
3[rean
Ois[anee
IW,wT2
An
Site So.
!law
(.I)
cfs nit
n( 1 )
hP. hinlal
i
myrtle h.
9.0
9.0
4.1
2
N. fork Tel. Ck. 6.5
9.3
1.1
Narlok
2
3.0
4.6
0.9
2
3.6
4.0
1.9
1
5.6
4.0
3.9
Kodiak
6
15.0
10.7
1.9
1
7.0
10.2
3.2
9
YIr9lnla h.
3.7
- 9.6
1.3
m Bay
3
1.7
4.3
1.5
1
2.8
5.0
1.9
2
0.7
4.1
5.9
Old sprier
2
J.5
11.1
0.4
3
3.7
9.6
2.0
1
7.0
10.2
5.4
Part Site,
1
1.3
6.7
0.4
2
4.1
6.2
8.3
3
1.1
8.3
0.7
Outlnkle
2
1.0
9.1
1.3
1
2.7
9.9
2.3
Penstock
Len9[h
5000
low
SSW
4000
750
75W
saw
2000
30W
3700
380
TWO
2100
260
Penstock
Length
e.
2600
4WD
4000
SSW
5300
)000
45W
4WD
290D
4WD
25W
2400
32W
4500
220
40W
May
SSW
SSW
THOLE C-1
(mnt'd)
Penstock
Gros
Ares,.
Net
Anrage
Netrlc
Main Capital
Ell ... ties
(lead
Flom
head
POuer
Machine Cap.
Energy
Headmetifc.t
USAch
ft.
�_
yer umt
�h
in)
(do)lara)
o0-IOD
IN
14.6
630
652
331
4,350,000
192
1,630,000
05-15
70
18.5
0
84
42
552,Oo
19
1.220.W0
1310-710
60
76.2
NO
2964
14W
19,500.000
165
4,9m,000
700-130
570
15.3
515
56,
263
3.720,000
157
1,570.Oo
M-100
list
7.3
90
47
24
315,00
27
731.00
490.200
2W
22.9
250
41D
WS
2,69D,OOD
76
2,290,000
280-205
75
48.3
70
NI
IN
1.6W.0W
21
2.400.000
300-20
280
2.1
250
39
19
250,Oo
76
434,000
300-IN
2W
8.0
180
IN
52
603,000
55
985.=
500-700
400
94.4
360
2450
1225
16,10010W
110
4,960,00
200-50
ISO
41.0
135
399
199
2,61a.o0
41
2,790,0110
400-50
350
6.6
315
149
)l
972,000
96
1.040,00
650-W
am
5.5
"a
214
107
1,410.000
165
1.110.000
220-20
NO
9.7
IN
126
6l
, 828.000
55
111301"
Penstock
Grvsa
Average
Net
Peerage
Nachipe hp.
Eaer
Patric
Head
Main Capital
Cost
Elevation
fq
Head
h.
Plmr
105)
Brad
ft.
Pouer
Ibl
Per Unit
Nn
(ml
(doure)
N0.100
1W
36.7
90
236
N
119
1,560.000
27
2,240,000
290.190
100
13.0
90
42
552,000
27
1,W0.0W
600-40
100.40
460
260
4.1
7.1
415
235
122
121
61
Bo.Oel
126
822,000
290.20
270
15.4
240
20
60
133
708,000
1,750,000,
72
73
992,000
1,720,0so
760.60
600.300
7W
300
20.4
32.3
630
27D
124
6El
462
6,070.OW
192
2,60.000
350.20
I50
12.1
l75
120
311
0
1,120,000
78e.000
62
41
2,110,00
1.20.00)
390.20
650-50
370
60
6.4
9.4
335
540
1"
3N
77
1.010.000
102
I,D40.Oo
350.50
300
24.5
270
477
182
239
2.39D.OW
3,140,00
I65
02
1,610.000
2,490'am
Notes
820
4.2
740
375
us
475
13
1,480.00
226
1.030,000
590-I80
$90-18
IIO
410
0.3J98
55.3
370
ills
224
737
1940.00
9.680,00
96
113
2,250.000
3.440.000
no -so
ISO -SO
30
1W
2.5
51.5
270
90
48 '
334
24
31S.W0
82 '
491,00
90-5W
am
5.4
30
I40
167
70
2.190,m0
920,0W
2)
110
2,840,00D
952,OW
2)0.20
190
12.1
170
148
74
972.0m
52
1,290,W0
So-so
450
22.4
405
153
326
4,280,0041
123
I,BW,OW
(I)Sltes .Ih h1drel-.1 denl0pment PheM.11.1 1d.nt111 ea Irhm the prel BpiN, s.r... IRS of .Ppn.le.tHY 6% drtln19. b„Int.
(illnttua. aO.-M. cable.
"Mai ultl.n eurbleal uq ..creed br USERS.
Islruia9e to. I..T1 for "matfalpasames s percent mel prone ncatau0n.
re,., 1. 1. be .Gnd..I.
Nyer
01sei
pmatock
Man
Tr, .... Iisio.
Cost
Eceray
Energy
Fner9y
8...
Lost
Cost
Cost
installed
Cost
Not
h.t (6) his
(dollars)(Sellers)(aollartl
• d011n�
mil is Yon mllb kun
n
240.000
85.000
1,250,000
3,210,000
92
225
2.44
72,00
85,00
96,W0
1,480.000
335
225
0.67
305,000
85,0W
1,OJJ,No
4,nq, 'M
41
224
5.45
1W.00
85,IXil
40D.W0
2.210,W0
74
N4
1.03
262,OW
as.=
760,Oo
1.840.000
729
294
0.39
325,000
85.000
360,000
3,110,000
144
239
1.65
552.00
05.0m
IN.=
3.690.000
2W
23.
0.83
70.0W
05.Wo
NSOOD
789,OW
395
169
0.43
105.way
85'em
Io,Oo
1,270,000
233
WO
us(.)
370.000
85.OW
550,0011
5-960,000
46
722
2.11
2N.000
85,OW
1N.OW
3,220,000
IN
127
0.62
105,00D
85,W0
20,oW
1,430,00
Ie3
271
),h
M.OW
85,000
440,OW
1,710.000
152
271
1.78
91.000
85,000
112.000
1.410.01y)
214
271
2.27
Hydmp0.er0.... I
Penstock
Me
Tranmoissies
Cast
Energy
Energy
Benefit
Cost
Cost
Cost
Installed
Lot
Lott
hit
doll.,I
dollars
(dollan)
WINrs
In111s8Hh'd
ill 7Bh) Cm�ai...
ISO,=
85,000
401,00(1
2.BW.000
230
198
.86
160,Oo
es.wo
300.000
1.630.000
368
190
.54
140,000
85,000
160,000
1.2101001
in
217
1.15
122,OW
85,000
184.00
1.380,am
219
211
0.99
N2,OW
85,000
264,000
1,280 WO
163
717
1.33
315,000
85,Oo
1.500,W0
3.960.000
82
114"'
1.51
284,00
85,OW
7m.wa
3,150.W0
95
lil
I.2B
ISO,=
05,00
les.WD
1,660.000
1.3
I21
1 ,
102.OW
05.W0
1W.Oo
1,340,000
165
168
1.02
I6B4O00
55,000
152.000
2,02G.San
10
118
1.6a
UNDER)
05.000
60,000
2,790,000
11D
168
1.53
B/,o0
Bs,oO
180,am
1.380,Om
116
205
1.77
144,am
85,00
IB0,000
2,67000
113
206
1."1
2 oody
B5.Om
TOO,=
4.520,00
SB
.5
3.51
n.WO
85.0110
92.oO
751.00)
298
IB)
0.62
260.000
85,o0
WI.=
3.390,W0
193
10>
0.97
122.010
, BS,oO
ICON)
1,240,00
169
1.7
I'll
IOO,OW
BS,OW
80,W0
1,61D,000
210
I85
a.BB
J25.00
BS,OW
140,OW 121
2,)J0,0W
80
185
2.31
TABLE C-2
ESTIMATED COST PER MILE OF TRANSMISSION LINE
(1980)
Type 1 — 14.4KV or 7.2KV, 3 Phase, 4
Average Span: 300
Wire Transmission Line
Feet
—
Item
Cost
Cost
Site
No.
Item Quantity
Unit
Seattle
Multiplier
Cost
1
Wood Poles, 40 feet high 17
Each
Conductor, 266.8 ACSR 24,000
Linear
Feet
Line Hardware and Insulators 17
Poles
Neutral Grounding 9
Poles
24,000
1.0
24,000
2
Survey, Clearing
Relocations and Freight
--
--
6,000
3
Contract Labor 80
Work—
28,000
hours
4
Site Multiplier
2.0
Installational Multipliers
1.25
— Rolling terrain, with
some soft ground
70,000
Total Cost per Mile
$100,000
Note: Cost per mile does not include: Right of Way, Site Access (Roads
and Trails), Mobilization/Demobilization, River Crossings Substation,
Distribution and Terminal Point Equipment, Engineering/Construction
Services Cost, Contingencies and Escalation.
C-13
TABLE C-3
ESTIMATED COST PER MILE OF TRANSMISSION LINE
(1980)
Type 2 — 7.2KU, Single Wire Ground Return (SWGR)
Transmission Line — Average Span: 300 Feet
Cost Cost Site
Item Quantity Unit Seattle Multiplier Cost
1 Wood Poles, 40 feet high 7 Each
Conductor 7/a8 Alumoweld 6,000 Linear
Feet
Line Hardware and Insulator 7 Poles
2 Survey, Clearing
Relocations and Freight
3 Contract Labor 300 Work —
hours
4 Site Multiplier
Installational Multipliers
— Rolling terrain, with
some soft ground
Total Cost per Mile, Less Take —off Terminal
SWGR Take —off Terminal
7,500 1.0 7,500
10,500
3,500
2.0
1.25
26,250
37,250
Round to $40,000
$40,000
Note: Cost per mile does not include: Right of Way, Site Access (Roads
and Trails), Mobilization/Demobilization, River Crossings Substation,
Distribution and Terminal Point Equipment, Engineering/Construction
Services Cost, Contingencies and Escalation.
C-14
250
m
Cost per 150
Foot of
Penstock,
Dollars
100
0
0 50 100 150 200 250 300
Flow (cfs)
Source: U. S. Army Corps of Engineers (1979)
C-15
REGIONAL INVENTORY & RECONNAISSANCE STUDY
SMALL HYDROPOWER PROJECTS
ALEU IAN ISLANDS, ALASKA PENINSULA, KODIAK ISLAND
Penstock Costs
Figure C - 1
DEPARTMENT OF THE ARMY
ALASKA DISTRICT
CORPS OF ENGINEERS
300
Cubic Yards 200
of
Concrete
100
A
Diversion Length (feet)
Source: CH2M Hill (1979)
C-16
REGIONAL INVENTO7&RECONNAISSANCE STUDYSMALL HS
ALEUTIAN ISLANDS, AOOIAK ISLAND
Diversion Dam Material Requirements
Figure C - 2
DEPARTMENT OF THE ARMY
Nlna ALASKA DISTRICT
CORPS OF ENGINEERS
120
100
80
Width of
Streambed
60
r,
(ft.)
V
40
20
F
2
✓�
c
N r
rN
�
D3z
N
Nrzy
N r!
C Y
rCy
Y fD
fail 9 �
m a
n v
soQ.
aon
�nm
� n
zmo
9
TD3
v m
n
coa
rn
�cw
mmy
s
zqr
�ma
Qym
m
a N
N m
s
r <
�
z
�
v
9
0 20 40 60 80 100
Penstock Flow (cfs)
120
140
160
300
00%
220
:n
160
Dollars per
Linear foot
(50 ft.lengths)
120
ff
ELI
M
Steel Pipe /
400-800 ft. head
(174-347 psi.) /
Steel Pipe
150-350 ft. head
(67-152 psi.)
10 20 30 40
Pipe Diameter (in.)
C-18
Plastic Pipe
150-250 ft. head
(67-110 psi.)
50 60
REGIONAL INVENTORY & RECONNAISSANCE STUDY
SMALL HYDROPOWER PROJECTS
ALEUTIAN ISLANDS, ALASKA PENINSULA, KODIAK ISLAND
Assumed Penstock Costs
Installed Alaska
Figure C - 4
DEPARTMENT OF THE ARMY
ALASKA DISTRICT
CORPS OF ENGINEERS
C7
I
LID
•
■m■®�n■�.®
11
�n
���■n
11
■■■■■®MIVAN
■
111
■■■n®gin■
■
■■■®
:„
u 7uv '""" UNIT SIZE IW 'J'-
IMPULSE TURBO -GENERATORS
COST -FOB FACTORY -COMPLETE INTEGRATED UNITS
0
REGIONAL INVENTORY & RECONNAISSANCE STUDY
SMALL HYDROPOWER PROJECTS
ALEUTIAN ISLANDS, ALASKA PENINSULA, KODIAK ISLAND
FIGURE C-5
TURBINE GENERATOR COSTS
Note: Includes Cost of Turbine Generator,
Valves, and Switchgear
DEPARTMENT OF THE ARMY
SECTION D
FEDERAL AND STATE PERMITS
A Federal Energy Regulatory Commission (FERC) License will be necessary
for most of the projects proposed if federal lands become part of a
project site and transmission facilities (Harza 1979). If a project is
located entirely on native land, the FERC may not have jurisdiction but
will be required to determine jurisdiction.
Other factors which may effect a FERC ruling on jurisdiction include
whether a stream is navigable or affects interstate commerce. The FERC
makes jurisdictional decisions after receiving a "Declaration of
Intention" which fully describes the project, land ownership, and
stream. The contents of a typical application are provided in Figure
D-1.
Other Federal and State permits are required regardless of FERC
jurisdictional rulings. These include:
Federal
I. U.S. Army Corps of Engineers (USACE) — Section 404 Federal
Water Pollution Control Act (FWPCA) permit for discharge of
dredge and fill material into U.S. waters: Section 10, Rivers
and Harbors Act Permit, if the stream is determined to be
navigable; and
2. U.S. Environmental Protection Agency (USEPA) — Section 402
FWPCA National Pollutant Discharge Elimination System (NPDES)
permits for point source discharges. Construction phase and
powerhouse sump pump discharge NPDES permits will be necessary.
D-1
Other Federal agencies which would probably review a FERC license
application and the applications for other Federal permits include U.S.
Fish and Wildlife Service, National Marine Fisheries Service, USFS, the
Heritage Conservation and Recreation Service, and Alaska Power
Administration, and the Bureau of Indian Affairs.
State of Alaska
Permits and review concerning environmental aspects of the project
which would be required from state agencies include:
1. Department of Environmental Conservation — Certificate of
Reasonable Assurance for Discharge into Navigable Waters (in
compliance with Section 401 of the FWPCA); Waste Water
Disposal Permit (the Department may adopt the NPDES permit
issued by USEPA as the required State permit);
2. Department of Fish and Game, Habitat Protection Service —
Anadromous Fish Protection Permit. Required of any hydraulic
project located on a catalogued anadromous fish stream, this
permit may impose stipulations on construction timing, project
design and operation requirements, and other mitigation
measures;
3. Department of Natural Resources, Divison of Land and Water
Management — Water Use Permit (authorizes dam construction and
appropriation of water); and
4. Office of the Governor, Division of Policy Development and
Planning, Office of Coastal Management — review of development
projects in Alaska's coastal zone to insure compliance with
coastal management guidelines and standards (AOCM and USOCZM
1979).
REA
To assist those who must obtain permits from one or more Federal, State
of Alaska, or local agencies, the applicant may submit a single master
application to the Alaska Department of Environmental Conservation
(ADEC), who will then circulate the application to the other
appropriate State agencies for comment and review. The State permits
and review listed above are all included in this process which is not
mandatory but rather intended to aid the applicant.
In addition, the Division of Policy Development and Planning (DPDP) of
the Office of the Governnor, through the A-95 Clearinghouse System,
acts as lead agency in the coordination of the review of environmental
reports, environmental impact statements, Federal assistance programs,
and development projects.
D-3
Figure D-1
Order No. 11
Docket No. RM79-9
9131.6
APPLICATION FOR SHORT -FORM LICENS-c (MINOR)1/
1. Applicant's full name and address:
2. Location of Project: (Zip Code)
State: County:
Nearest town: Water body:
3. Project description and proposed mode of operation
(reference to Exhibits K and L, as appropriate):
(continue on separate sheet, if necessary)
4. Lands of the United States affected (shown on Exhibit K)
(Name) (Acres)
a. National Forest _
b. Indian Reservation
C. Public Lands Under
Jurisdiction, of
d. Other _
e. Total U.S. Lands
f. Check appropriate box:
Surveyed / i Unsurveved land in public -land
state:
(1) If surveyed land in public -land state provide the
following:
Sections and subdivisions:
Range _ Township:
Principal base and meridian:
(2) If unsurveyed or not in public -land state, see
Item 8 of instructions:
Purposes of project (use of power output, etc.)
1/ See Sections 3.114, 4.60 and 16.12 of this Chapter,
page 60
order No. 11
Docket No. RM78-9
Figure D-1
6. Construction of the project is planned to start
it will be completed within months from the date of
issuance of license.
7. List here and attach copies of State water permits or other
permits obtained authorizing the use or diversion of water,
or authorizing (check appropriate box):
the construction, operation, and maintenance
/_7 the operation and maintenance
of the proposed project.
8. Attach an environmental report prepared in accordance
with the requirements set forth in the Instructions for
Completing Application for Short -Form License (Minor),
below.
9. Attach Exhibits K and L drawings.
10. State of
County of _ ss:
being duly sworn, depose(s) and say(s) that the contents of
this application are true to the best of knowledge or
belief and that (check appropriate box)
% is (are) a citizen(s) of the United States
all members of the association are citizens of the
United States
is (are) the duly appointed agent(s) of the
state (municipality)(corporation) (association)
and has (have) signed this application this _ day of
19
(Applicant(s))
order No. 11
Docket No. RM78-9
Figure D-1
By
Subscribed and sworn to before me, a Notary Public of the
State of this _ day of
/SEAL/
(Notary Public)