HomeMy WebLinkAboutRegional Inventory and Recconnaissance Study for Small Hydro Project 1981REGIONAL INVENTORY AND RECONNAISSANCE··sTUDY
FOR SMALL HYDROPOWER PROJECTS
NORTHWEST ALASKA
DEPARTMENT OF THE ARMY
ALASKA DISTRICT, CORPS OF ENGINEERS
PROPERTY OF:
Alaska Power Authority
334 W. 5th Ave.
Anchorage, Alaska 99501
MAY 1981
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OTT WATER ENGINEERS, INC.
:.~~~~~~~~...;::;;so""~~~,....-:~~
4790 Business Park Blvd., Suite 4, Bldg. 0
Anchorage, Alaska 99503 (907) 277-8255
Mr. Loran Baxter
U.S. Army Corps of Engineers
P. C. Box 7002
Anchorage, Alaska 99510
Su)ject: Galena Hydropower
Jc :J No. f\339. 00
ar Loran,
June 9,1981
Since como 1 eting our Northwest Alaska hydropower survey and report,
we nave evaluated the Galena hydropower site proposed in the report
usi,g recently gathered geologic reconnaissance information. We
fir.d that : unfeasible run-of-the-river proj outlined in the
~ecort rna) be restructured into a feasible proj by analyzing ~he
~iect a<: a storage project, with a 1:.10' 300' dam. Storage ca,,
be ~n excess of 150,000 acre-feet. At 140 regulated average
anr:.;a 1 f' ~J'I.', a power yi e 1 d of 1. 2 to 2.1 megawatts may be generated
on 2 co~s:·tant annual basis.
Positive as~ects of the project include apparent rock abutments and
rock strea~ channel for dam foundations and dam construction material.
The reservoir appears to have a good elevation/storage ratio. The
site is re~atively free of environment~l constraints and is near
a good point of use and access. In addition, the community leaders
and present electric utility operator are all active, highly motiv~ted
inr.ividu2ls who would likely work agressively t make the project
a success. They have expressed such an attitude based upon the
tec~ative s~te analysis.
In summary. the storage/generation project discussed in this letter
rna) be one of the better hydro sites we are familiar with in Alaska.
We urge the study rc this site's feasibility be initiated. Such
a rroject would be located within a realistic di ance of a comm~nity
anc airpo~t facility that could utilize the power. Present domestic
dem2nd is rrom 300 to 800 kw. The military, FAA, and BLM facilities
at the Galena airport are presently discussing use the local power
gr~d inste2d of maintaining separate facilities. This could utilize
th~ remai~i~g power generating capacity.
During a recent field trip to Galena, considerable interest was 2X-
pressed in a hydroelectric project that would deliver in excess of
one megawatt. The project discussed herein, though only very roughly
evaluated, appears to warrant further analyses and, if feasible,
construction.
Environmental issues would center anound the "occasional" King Salmon
use of the river. However, by increasing base flows and enhancing
spawning areas below the dam site, these may be mitigated.
Based on discussions with various potential power users around the
State, Galena appears to be one of the most responsive and interested
communities with nearby hydropower potential. We would urge your
support of a further detailed evaluation of their specific needs
and site capabilities, with construction as an ultimate goal.
If we can be of further assistance or provide additional information,
please do not hesitate to contact us.
cc: City of Galena
Alaska Power Authority
M & D Electric, Galena
Sincerely,
Gene R. Crook
Civil Engineer
REGIONAL INVENTORY AND RECONNAISSANCE STUDY
FOR SMALL HYDROPOWER PROJECTS
IN NORTHWEST ALASKA
DEPARTMENT OF THE ARMY
Alaska District
Corps of Engineers
OTT WATER ENGINEERS, INC.
Anchorage, Alaska
May, 1981
TABLE OF CONTENTS
1.0 INTRODUCTION
1.1 STUDY AUTHORITY
1.2 STUDY DESCRIPTION
1.3 OTHER STUDIES
2.0 SUMMARY
2.1 EXISTING CONDITIONS
2.2 PROJECTED ELECTRICAL POWER REQUIREMENTS
2.3 HYDROELECTRIC POTENTIAL .•...
2.4 SUMMARY TABLES
2.5 CONCLUSIONS AND RECOMMENDATIONS
3. 0 EXIST! NG CONDITIONS
3.1 COMMUNITY CHARACTERISTICS ....... .
3.2 EXISTING ELECTRICAL GENERATION SYSTEM .
3.3 EXISTING ELECTRICAL POWER REQUIREMENTS
4.0 PROJECTED ELECTRICAL POWER REQUIREMENTS
4.1 LOAD GROWTH PROJECTIONS METHODS
4.2 PROJECTED DEMANDS FOR EACH COMMUNITY
4.3 PRESENT VALUE OF PROJECTED ENERGY
DEMANDS . . . . . . . . . . . . . . . . . .
5.0 PRELIMINARY REVIEW OF COMMUNITY HYDROELECTRIC
POTENTIAL
1
1
2
4
4
5
6
12
13
20
21
22
28
29
5.1 REVIEW METHODS . . . . . . . . . . . . . 35
5.2 DEVELOPMENT COST ESTIMATES . . . . . 36
5.3 COMPARISON OF COSTS OF HYDROELECTRIC AND
EXISTING ELECTRICAL GENERATION . . . . 41
6.0 POTENTIAL HYDROELECTRIC SITES AT SELECTED
COMMUNITIES
6.1 COMMUNITY SELECTION CRITERIA
6.2 FIELD RECONNAISSANCE
6.3 HYDROLOGIC ANALYSIS
- i -
45
45
47
TABLE OF CONTENTS
(Continued)
6.4 ENVIRONMENTAL CONSTRAINTS
6.4.1 Fish ....... .
6. 4. 2 Biological Concerns
6. 4. 3 Archaeology
6.5 DESIGN CONSIDERATIONS
6. 5. 1 Dam and Foundation
6. 5. 2 Transmission line
6.5.3 Penstock
6.5.4 Turbine and Generator
6.5.5 Fisheries Considerations
6.6 COST ESTIMATES
6. 6.1 Unit Prices and Cost Basis
49
50
50
52
58
63
65
67
72
6.6.2 Design Capacity . • • . . 76
6.6.3 Quantity Takeoff . . . . . 79
6. 7 CONCEPTUAL HYDROELECTRIC DEVELOPMENT PLAN
FOR EACH COMMUNITY
6. 7.1 Allakaket 81
6.7.2
6.7.3
6.7.4
6.7.5
6.7.6
6.7.7
6.7.8
6.7.9
6. 7.10
6. 7.11
6.7.12
6.7.13
6.7.14
6.7.15
6. 7.16
Ambler
Anaktuvuk Pass
Bettles
Brevig Mission and Teller
Buckland
Elim .
Galena
Golovin
Hughes
Kaltag
Kiana --
Kobuk
Ko1:_ukuk
Manle~ Hot S~rings
Nome . .
-ii -
94
100
106
115
131
140
153
161
183
194
205
212
220
228
236
TABLE OF CONTENTS
(Continued)
6. 7.17 Nulato
6. 7.18 Point Hope
6. 7.19 Shungnak
6.7.20 Tanana
6.7.21 Wales
6.7.22 White Mountain
6.8 PRESENT VALUE OF HYDROPOWER
7.0 CONCLUSIONS AND RECOMMENDATIONS
BIBLIOGRAPHY
APPENDIX A: COST INDICES
APPENDIX B: HYDROLOGY
APPENDIX C: GEOTECHNICAL CONSIDERATIONS
-iii -
261
268
274
281
294
300
303
311
315
Number
3.1
4. 3.1
5.2. 1.1
5.2.2.1
5. 3.1
6.6.1.1
6.6.1.2
6.6.3.1
LIST OF TABLES
SUMMARY TABLE 1
SUMMARY TABLE 2
EXISTING CONDITIONS
Title
PROJECTED ELECTRICAL DEMANDS AND PRESENT
GEOGRAPHIC COST INDEX FOR VARIOUS COMMUNI-
TIES . . • . . . . . . . . · · • · · · · · • · • · ·
FAIRBANKS BASE UNIT COSTS USED FOR PRELIMI-
NARY COST ESTIMATES ...••..•.•.•..
COMPARISON OF COSTS OF HYDROELECTRICAL AND
EXISTING ELECTRICAL GENERATION .••....
UN IT COSTS AND BASIS FOR CONCEPTUAL PLAN
TOTAL PROJECT COST ESTIMATES
DIVERSION DAM COST MATRIX
POWERHOUSE COSTS . . . . . • . • . . .
6.8.1.1 MAXIMUM POTENTIAL PRESENT VALUE OF HYDRO-
7
10
14
32
37
39
42
74
75
80
POWER PROJECTS . . . . • . . • • • . . • • . 305
6.8.2.1 PRESENT VALUE OF FUEL DISPLACEMENT AND
OPERATION MAINTENANCE REDUCTION BY EACH
HYDROPOWER PLANT PASSING THE SECOND STAGE
SCREENING . • . . . . . . • . . • • . • . . . . . 310
7.1 COMMUNITIES WITH POTENTIALLY ECONOMICAL
HYDROPOWER SITES IF CONSTRUCTION COSTS ARE
REDUCED BY 40 PERCENT • • . . . • . . . • . . . 313
7.2 COMMUNITIES WITH POTENTIALLY ECONOMICAL
HYDROPOWER SITES IF DIVERSION STRUCTURE COSTS
ARE ELIMINATED . . . • . . . . . . . • . • • . . . . . 314
-iv -
Number
5.2.2-1
6.6.2-1
6.7.1-1
6.7.1-2
6.7.1-3
6.7.2-1
6.7.3-1
6.7.3-2
6.7.4-1
6.7.4-2
6.7.5-1
6.7.5-2
6.7.5-3
6.7.5-4
6.7.6-1
6.7.6-2
6.7.7-1
6.7.7-2
6.7.8-1
6.7.8-2
6.7.9-1
6.7.9-2
6.7.9-3
6.7.9-4
6.7.9-5
6.7.10-1
LIST OF FIGURES
Title
WATERWAYS COST
ANNUAL LOAD CURVE .
ALLAKAKET HYDRO SITE
CREEK SOUTH OF ALLAKAKET
UNNAMED CREEK NORTHWEST OF ALATNA
AMBLER HYDRO SITE
ANAKTUVUK PASS HYDRO SITE .....
INUKPASUGRUK CREEK NEAR ANAKTUVUK PASS
BETTLES HYDRO SITE ....
JANE CREEK NEAR BETTLES
BREVIG MISSION HYDRO SITE
DON RIVER NEAR BREVIG MISSION
RIGHT FORK BLUESTONE RIVER NEAR BREVIG MISSION
AND TELLER ............ .
BLUESTONE RIVER NEAR BREVIG MISSION AND
TELLER ............•.
BUCKLAND HYDRO SITE
HUNTER CREEK NEAR BUCKLAND
ELIM HYDRO SITE
PETERSON CREEK NEAR ELIM
GALENA HYDRO SITE
KALA CREEK AND TRIBUTARIES NEAR GALENA
WHITE MOUNTAIN AND GOLOVIN HYDRO SITES
EAST TRIBUTARY OF CHEENIK CREEK NEAR GOLOVIN
AND WHITE MOUNTAIN .............. .
UPPER CHEENIK CREEK NEAR GOLOVIN AND WHITE
MOUNTAIN .................... .
EAGLE CREEK NEAR GOLOVIN AND WHITE MOUNTAIN
WEST TRIBUTARY OF KWINIUK RIVER NEAR GOLOVIN
AND WHITE MOUNTAIN
HUGHES HYDRO SITE
- v -
40
78
84
88
90
97
102
104
109
113
118
123
125
127
134
138
143
147
155
159
164
168
170
172
174
185
Number
LIST OF FIGURES
(Continued)
Title
6. 7.10-2 TWO CREEKS WEST OF HUGHES
6. 7.10-3 CREEK NORTHWEST OF HUGHES
6.7.11-1 KALTAG HYDRO SITE
6.7.11-2 SOUTH TRIBUTARY OF KALTAG RIVER NEAR
KALTAG ...••.......••....•
6.7.11-3 NORTH TRIBUTARY OF KALTAG RIVER NEAR
KALTAG . ~ .....•...
6. 7.12-1 KIANA HYDRO SITE .•••..
6. 7.12-2 CANYON CREEK NEAR KIANA ••..
6. 7.13-1 SHUNGNAK AND KOBUK HYDRO SITES
6.7.13-2 DAHL CREEK NEAR KOBUK .•••..
6. 7.14-1 KOYUKUK AND NULATO HYDRO SITES
6.7.14-2 EAST TRIBUTARY TO NULATO RIVER NEAR
NULATO •...•••..•..•...
6. 7.15-1 MANLEY HOT SPRINGS HYDRO SITE ..
6. 7.15-2 McCLOUD RANCH CREEK NEAR MANLEY
HOT SPRINGS •.••..
6. 7.16-1 NOME HYDRO SITES ••..
6. 7.16-2 PENNY RIVER NEAR NOME .
6. 7.16-3 OSBORN CREEK NEAR NOME
6. 7.16-4 BUSTER AND L1 LLIAN CREEKS NEAR NOME
6.7.16-5 BASIN CREEK NEAR NOME .
6.7.16-6 ALFIELD CREEK NEAR NOME
6. 7.16-7 DAVID CREEK NEAR NOME .
6. 7.17-1 WEST TRIBUTARY TO NULATO RIVER NEAR
6. 7.18-1 POINT HOPE HYDRO SITE ..... .
6.7.18-2 AKALOLIK CREEK NEAR POINT HOPE.
6. 7.19-1 COSMOS CREEK NEAR SHUNGNAK
6. 7.20-1 TANANA HYDRO SITES
6. 7.20-2 BEAR CREEK NEAR TANANA ...
-vi -
NULATO .
189
191
196
198
200
208
210
214
218
222
226
230
234
240
245
247
249
251
253
255
265
270
272
279
284
288
Number
LIST OF FIGURES
(Continued)
Title
6. 7.20-3 JACKSON CREEK NEAR TANANA
6. 7.21-1 WALES HYDRO SITES
6. 7.21-2 KANAUGUK RIVER NEAR WALES
-vii -
290
296
298
INTRODUCTION
1.0 INTRODUCTION
1.1 STUDY AUTHORITY
The Corps of Engineers was authorized by the United States
Congress in 1976 to undertake an evaluation of the nation's
hydropower resources at existing dams and previously identified
but undeveloped sites. As one part of this effort, the Corps of
Engineers, Alaska District, has been conducting a study of the
potential for small hydropower development at isolated commun-
ities throughout the State of Alaska. The Northwest Alaska area
represents one of four subregions which have been or are under
study. To date, Southeast Alaska; the Aleutian Islands, Alaska
Peninsula, and Kodiak Island; and Southwest Alaska have been
studied.
1.2 STUDY DESCRIPTION
The study evolved from the completion of four major stages be-
tween July and November 1980. The first stage involved litera-
ture and information review, a mail-out of community information
questionnaires, and a review of topographic maps to identify
drainage basins with potential hydropower sites proximal to each
of the 50 communities studied. The second stage involved a
field reconnaissance to selected sites which illustrated some
development potential. The visits were designed to provide
individual community leaders with an overview of the sites and to
provide study participants with first-hand site conditions, and
individual community needs and resources. During the third
stage existing information was evaluated. Community load
growth was projected, and hydropower construction costs were
estimated. Twenty-two of the original fifty communities were
screened out to be studied further.
-1 -
The fourth and final phase included the preparation of more de-
tailed layouts and cost estimates for each of these twenty-two
communities. Hydrologic analyses were conducted to assess the
hydroelectric generating potential of each site. Specific benefit-
cost ratios were computed for each projected hydropower project
by comparison of the present value of hydropower costs to the
present value of energy produced by existing generating plants.
- 2 -
1.3 OTHER STUDIES
In December 1979, the United States Department of Energy,
Alaska Power Administration published a report entitled 11 Small
Hydroelectric Inventory of Villages Served by Alaska Village
Electric Cooperative 11 • Included in this report are discussions of
village hydroelectric potential for Ambler, Elim, Kaltag, Kiana,
Shungnak, Wales, Huslia, Nulato, Koyuk, Shaktoolik, Kivalina,
Noatak, Noorvik, Shismaref, Selawik, And Buckland. The
report indicated that the villages of Ambler, Elim, Kaltag, Kiana
and Shungnak offered the best hydroelectric development poten-
tial. In 1979 the Department of Commerce and Economic Develop-
ment, Division of Energy and Power produced a community
energy survey which included information on fuel use and cost,
bulk storage, transportation, construction and electrical use, as
reported by villages in Alaska. This same agency produced a
waste heat capture study for Alaska which includes some back-
ground information on Northwest Alaska village energy require-
ments. In July of 1975 the U.S. Department of Interior, Alaska
Power Administration produced a report entitled 11 A Regional
Electric Power System for the Lower Kuskokwim Vicinity 11 • A
number of other reports and publications relevant to this study
are included in the bibliography at the end of this report.
- 3 -
AHVWWnS
2.0 SUMMARY
The results of this report are tabulated in Summary Table 1 and
Summary Table 2.
2.1 EXISTING CONDITIONS
The existing electrical generators, capacity, peak demand,
annual electrical use and cost, and expected life for each of the
50 communities studied are described in Table 3.1. Community
characteristics are presented in two general classifications: re-
gional centers and villages. The economic and cultural charac-
teristics of the two classifications are distinctly different.
The majority of the communities rely upon 50 to 800 kW diesel
generators for their electrical power. The primary village elec-
trical energy requirements are for lighting and appliances, in-
cluding space heaters, television, freezers and battery chargers.
2.2 PROJECTED ELECTRICAL POWER REQUIREMENTS
Load growth in NW Alaska is difficult to predict and is quite de-
pendent on State and Federal government pol icy shifts. Load
growth was estimated for each community by reviewing population
growth trends, levels of income, and local infrastructure. In
addition, Alaska legislative policy on energy use was investi-
gated. In general, a base annual load growth rate of two per-
cent was adopted for the 50-year period of this study. How-
ever, significantly higher load growths were projected for the
next ten years if the community had specific plans for construc-
tion of new facilities.
The present value of projected energy demands was computed for
each community over a 50-year period at a discount rate of 7-3/8
percent. The projected electrical demands and their present
value are displayed in Table 4.3.1.
- 4 -
2.3 HYDROELECTRIC POTENTIAL
Sites with hydroelectric generating potential were initially identi-
fied by interpreting U.S. Geological Survey topographic maps.
The generating capacity of each selected site was approximated,
and costruction costs roughly estimated. Geographic cost indices
were used to account for variation of costs throughout the re-
gion and escalation from Fairbanks-based costs. The present
value of projected energy use was compared to preliminary
hydroelectric project construction costs in Table 5.3.2. Those
communities which exhibited unfavorable development potential
were screened out from further study.
After the initial screening, a more detailed study of hydropower
potential was conducted. A reconnaissance survey was per-
formed at communities which exhibited a favorable present value/
construction cost ratio and which had not been previously visited
by persons studying the communities for hydropower potential.
Hydrologic analyses for all communities passing the screening
were conducted. 50 and 80 percentile monthly flows and mini-
mum low summer flow values were estimated.
Conceptual hydroelectric project plans were developed in har-
mony with environmental constraints. Fish species, endangered
peregrine falcon nesting areas, and known archeological and/or
historic sites were identified at each planned hydroelectric proj-
ect. The conceptual plans which were developed are not de-
tailed. Therefore, some of the constraints, parameters, and
problems that should be considered during final design of a
project are presented. Costs were estimated in more detail than
during the preliminary screening.
The results of the conceptual planning are presented in Section
6. 7 for each community passing the preliminary screening. In-
formation presented for each community includes community loca-
- 5 -
tion, community description, population, economic base, existing
electric power equipment, projected electrical demands, potential
growth factors, land use, hydropower plans, site map, stream-
flow information, and conceptual design information, including
project cost estimates.
The present value of hydroelectric energy produced by each of
the conceptual plans presented was compared to the present
value of the cost of construction of the project and its associated
operation and maintenance. After a secondary screening, seven
hydropower plans were analyzed for their true present value.
Present value was based on displaced diesel fuel costs and re-
duced operation and maintenance costs.
2.4 SUMMARY TABLES
Existing conditions and projected annual electrical demands for
all fifty communities studied are tabulated in Summary Table 1.
Shown in Summary Table 2 are conceptual design information,
hydroelectric potential, and development cost estimates for each
of the communities passing the initial screening.
- 6 -
SUHHARY TABLE 1
Present
Annual
Power
Latitude & 1980 Existing
lnatalled
Capacity
(kW)
Generation
Consumer
Cost/kWh
($) Co11101unity Name Longitude Population Power Gen. Utility Ownenhip (HWh)
Alatna 66°34'N
152°40'W
Allakaket 66°34'N
152°52'W
Ambler 67°05'N
157°52'W
Anaktuvuk Pasa 68°08'N
151°45'W
Barrow 71°15'N
156°47'W
Bettles 66°54'N
151°4l'W
Brevia Hiasion 65°20'N
166°29'W
Buckland
Candle
Cape Liaburoe
Council
Deadhone
Deedng
Galena
Golovin
Hughes
Huslia
65°59'N
161°08'W
65°55'N
161°56'W
68°52'N
166°05'W
64°54'N
163°40'W
70°12'N
148°28'W
66°04'N
162°42'W
64°37'N
162°15'W
64°44'N
156°56'W
64°33'N
163°02'W
66°03'N
154°15'W
65°4l'N
156°24'W
lgnalik (Little 65°45'N
Diomede) 168°56'W
35
160
250
173
2, 715
84
144
174
5
104
35
212
120
196
Diesel Village Council Native
Diesel School & State & Native
Village Council
Diesel AVEC Cooperative
Diesel NSB & P&L Public
Gaa Turbine Barrow Utility Public
Dieael Bettlea L & P Public
Diesel School & Clinic Federal
4
200
420
500
6,950
900
148
20 0.37
1,121 0.37
268 0.37
1,000 0.15 < 600 kWh
0.45 > 600 kWh
11,693 0.15
1,010 0.37
400 0.35 (E)
Diesel IRAC, School State & Native 360 350 0.65
Gaa/Diuel None Private 10 7 0.50 (E)
Diesel U.S. Air Force Federal 1,868 3,000 0.12
Diesel School & State and 11.5 62 0.50 (E)
Tradina Poat Pdvate
Gas & Arctic Util. & NANA & Private 2,650 20,000 (E) 0.25
Diesel Oil Coapanies (Arctic Ut)
Dieael IRAC Native 150 175 0.35 (E)
Diesel AVEC Cooperative 285 228 0.37
750 (Galena) Diesel
300 (AFB)
H&O Enterprise P~ivate & Fed.
U.S.A.F.
2, 75~ 8,332 0.33
118 Diesel
95 Diesel
225 Diesel
139 Diesel
Olaon, BIA, Fiah Private, State
Procesaor, s·chool & Federal
Village Council Native, Federal
BIA
AVEC Cooperative
US BIA Federal
768 608
25 159
350 224
50 169
0.35 (E)
0.50 (E)
0.37
0.09
(Fuel only)
Projected Annual Electrical
Demand, kWh
1990 2000 2030
137 171 307
1,356 1,670 3,015
445 560 1,007
1,745 2,340 7,030
18,712 23,350 42.101
1,212 1,515 2,127
480 600 1,080
988 1,235 2,223
8.4 10.5 18.9
1,500 1,500 1,500
74 93 167
20,000 20,000 20,000
210 263 472
769 962 1, 731
8,865 9,664 12,859
730 912 1,641
190 239 429
464 581 1,045
203 254 456
SUHHARY TABLE
Continued
Present
Annual
Installed Power ConaWIIer Projected Annual Electrical
Latitude & 1980 Ex is tina Capacity Generation Coat/kWh Demand 1 kWh
Community Name Longitude Po(!ulation Power Gen. Utilitf Ownenbi2 {kW) ~HWh) !~) 1990 2000 _ _ill.Q_
kaltaa 64"20'H 240 Diesel AVEC Cooperative 455 399 0.37 533 666 1,199
158"43'W
Kiana 66"58'N 314 Diesel AVEC Cooperative 650 645 0.37 864 1,037 1,296
160"26'W
kivalina 67"44'N 209 Diesel AVEC Cooper:ative 510 368 0.37 506 633 1,139
164"33'W
Kobuk 66"55'N 49 Dieael School State 100 122 0.50(E) 146 183 329
156"52'W
kotzebue 66"54'N 2,431 Dehel Kotzebue Elect. Public 3,420 5,494 0.25 12,636 30,217 54,391
162"35'W Association
koyuk 64"56'N 127 Dieael AVEC Cooperative 200 196 0.37 235 294 529
161"09'W
Koyukuk 64"53'H 124 Diesel School State 205 750 0.37 (E) 900 1,125 2,025
. (10 157"42'W
Lonely 70"51'N 113 Diuel Husky Oil Private 1,550 164 0.17 (E) 164 164 164
153"46'W
Hanley Hot 65"00'N 74 Diesel Hanley Hot Private 110 131 0.37 (E) 157 197 354
Sprinas 150"38'W Sprinaa Ent.
Hinto 65"53'N 199 Diesel AVEC Cooperative 215 224 0.37 269 336 605
149°11 'W
Nenana 64"34'N 508 Coal-Fired Golden Valley Public 9,500 0.15 19,000 37,000 88,800
149"05'W Electric
Noatak 67"34'N 291 Diesel AVEC Cooperative 310 337 0.37 468 585 1,053
162"58'W
Home 64"30'N 2,585 Diesel NOllie Joint City 6,850 14,000 0.19 31,900 72,900 )76,515
165"25'W Utilitlea
Noorvik 66"50'H 531 Diesel AVEC Cooperative 600 732 0.37 878 1,098 1,976
161°03'W
Nuiqaut 70"12'N 182 Dieael NSB P & L Public •240 526 0~ 15 < 600 kWh 631 789 1,420
15I"OO'W 0.50 > 600 kWh
Nulato 64"43'N 365 Dieael AVEC Cooperative 550 543 0.37 698 867 1,571
158"06'W
Point Hope 68"21'N 507 Diesel HSB P & L Public 510 1,590 0.15 ( 300 kWh 1,907 2,212 4,195
166"47'W 0.35 > 300 kWh
Point Lay 69"46'N 57 Dieael NSB P & L Public 80 408 0.15 < 600 kWh 490 612 1,102
163"03'W 0.45 > 600 kWh
Prudhoe Bay 70"15'N 2,000 Gaa-Fired ARCO, SOHIO, Private 159,000 120 Hil. 0. 15 (E) 120 Hil. 120 Hil. 120 Hil.
184"21'W Turbines B.P., etc.
SUHHARY TABU: 1
Continued
Present
Annual
Installed Power: Conswqea: Projected Annual Electrical
Latitude & 1980 Exiatioa Capacity Gene cation Cost/kWh Demand, kWh
Communitl£ Name Longitude ~ulation Power Gen. Utilitl£ OwnerahiJ! (kW} ~tiWb! (U 1990 _£Q!!L 2030
Rampart 65°30'N 58 Diesel Villaae Council Public 32.5 139 0.37 (E) 167 209 316
150°10'W & School
Selawik 66°36'N 525 Diesel AVEC Cooperative 650 647 0.37 830 1,038 1,868
160°00'W
Shaktoolik 64°20'N 160 Diesel AVEC Cooperative 195 200 0.37 1,196 1,496 2,692
161°09'W
Sbismaref 66°15'N 309 Diesel AVEC Cooperative 705 539 0.37 647 809 1,455
166°04'W
Shungnak 66°52'N 226 Diesel AVEC Cooperative 705 337 0.37 440 551 991
157°09'W
Solomon 64°34'N 10 Diesel None Private 10 (E) 8 0.50 (E) 10 12 22
164°26'W
Tanana 65°10'N 499 Diesel Tanana Power Private 1,000 1,489 0.11 1,787 2,234 8,020
152°04'W Company
CD Teller 65°16'N 219 Diesel Teller Power Public 465 441 0.35 529 661 1,190
166°22'W Coapany
U.iat 69°22'N 5 Diesel None Private 10 (E) 5 (E) 0.50 (E) 6 7.5 13.5
152°08'W
Walnwriaht 70°38'N 429 Dieael NSB P & L Public 600 1,300 0.15 < 600 kWh 2,782 5,902 14,300
160°02'W 0.35 > 600 kWh.
Wales 65°37'N 134 Diesel AVEC Cooperative 185 127 0.37 154 191 343
I68°05'W
White Hountain 64°41 'N 112 Diesel School Federal 300 60 0.37 (E) 436 545 980
163"24'W
.....
0
Community Name
Allakaket
Allakaket
Allakaket
Ambler
Anaktuvuk Pass
Bettles
Brevig ltili&ion
& Teller
Brevi 8 lti ss ion
& Teller
Brevig ltiuioa
& Teller
Buckland
Elim
Elim
Eli•
Elim
Galen•
Golovin
Golovin
Golovin
Golovin
Golovin
Golovin
Plan
No.
1
2
3
1
1
1
2
3
1
1
2
3
4
1
2
l
4
5
6
Name of
Potenti•l Hydro Site
Unnamed Stream South
Unaamed Strea111 N\1
Both Streams
E. Fork Jade Creek
Inukpasugruk Creek
Jane Creek
Don River
Right Fork Bluestone
ltain Stea Bluestone ·
Hunter Creek
Creek at El ill
Quiktalik Creek
Both Creeks
Both Creeks &
Peterson Creek
Kala Creek
E. Trtb. Cbeenik Cr.
E. Trib. & Upper
Cbeenik
Same as 2, Except
Powerhouse
Eagle Creek
Sa•e as 4, Intertie
White !fountain
Iwiniuk River
Latitude &
Longitude
66"31'11
152"39'W
66"34'11
152"42'W
67"11'2l"N
158"06'W
68"02'24"N
151"45'W
66"55'12"11
151"52'12"W
65"31'11
166"48'W
65°06'11
166°15'W
65"06'11
166"15'W
65"45'11
161°3l'W
64"38'11
162"16'W
64°36'11
162"21'W
64°33'11
156"45'W
64"36'11
162"5B'W
Slll1HARY TABLE 2
Transmission
Diat. (•i.)
2.3
2.5
9.0
1.3
4.3
24.0
11.0
11.0
23.5
o.o
1.5
1.9
(Petenon)
9.8
4.7
Drainaae
Area (ai. 2 )
9.4
18.9
4.3
46.5
32.8
49.8
28.9
77.4
70.1
2.5
6.0
Net Head
__!!t:..L
100
70
350
200
100
30
100
100
200
40
80
He dian
Flow
(CFS)
8.0
15.8
6.6
20.3
26.8
32.0
27.7
73.4
26.4
6.8
16.3
Power
Capacity
(kW)
82
105
187
106
414
276
119
240
276
238
28
131
159
4.14 200 3.1 211
(Petersoa) (Peterson) (Peterson)
21.8 60 14.3 761
8.9 60 14.3 99
2.4 3.5 100 5.6 164
(U.Cbeenilt) (U.Cheentk) (U.Cbeenik) (U.Cbeenik)
12.0 30.3 90 67.8 200
319
16.4 16.9 50 35.3 204
Ava Annual
Power
Production
(ltWh)
286
333
530
252
912
608
287
565
581
556
118
374
411
444
1, 729
328
392
392
427
670
578
llydro
Development
Cost
.{il ,ooo,ooo~
3.55
3.80
7.36
4.01
4.69
5.45
9.41
4. 73
5. 77
12.67
2.75
3.3~
5.55
8.07
15.86
4.22
7.47
8.10
5.43
8.52
5.45
Equiv.
Annual Cost
Cotit ($)/
ill...QQQ! i!<.\o/h)
269 0.94
288 0.86
559 1.05
304 I. 21
356 0.39
414 0.68
114 2.49
359 0.64
438 0.75
946 J. 70
209 1.77
252 0.67
421 1.02
613 I. 38
1,204 0.70
320 0.911
567 1.45
615 1.57
412 0.97
414 o. 72
Community Name
Hughes
Hughes
Kaltag
Kaltag
Kaltag
Kiana
Kobuk
Koyukuk
Manley Hot
Springs
Nome
Nome
Nome
Nome
Nulato
Nulato
Point Hope
Shungnak
Tanana
Tanana
Tanana
Wales
Plan Name of
No. Potential Hydro Site
1 Two Creeks West
2 Creek Northwest
1 S. Trib. Kaltag River
2 N. Trib. Kaltag River
3
1
1
1
2
3
4
2
1
1
1
2
3
1
Both Rivers
Canyon Creek
Dahl Creek
E. Trib. Nulato River
McCloud Ranch Creek
Penney River
Osborn Creek
Buster & Osborn Creek
Numerous Creeks
W. Trib. Nulato River
E & W Trib. Nulato
Akalolik Creek
Cosmos Creek
Bear Creek
Jackson Creek
Bear & Jackson Creeks
Kanauguk River
Latitude &
Longitude
66"04'N
1S4"19'W
66°06'N
154°19'W
64°18'N
1S8°53'W
64°21'N
1S8°42'W
67°0S'N
160°08'W
66°57'N
156°50'W
64°52'N
158°10'W
6S 0 00'N
150°45'W
64°36'N
165°34'W
64°36'N
165°06'W
68°29'N
166°10'W
67°00'N
157°09'W
6S 0 16'N
t52°00'W
65°16'N
1S1°48'W
SUHHARY TABLE 2
Continued
Transmission Drainage
Dist. (mi.) Area (mi.2 )
0.5 5.4
s.s
4.2
1.9
8.4
3.S
14.4
2.2
6.8
8.1
5.1
16.4
25.8
9.5
9.6
23.3
2.3
16.0
21.1
Net Head
(Ft.)
80
100
100
150
150
200
70
300
50
100
Hedian
Flow
(CFS)
4.9
4.7
9.0
14.7
12.9
11.1
23.3
1.7
36.9
40.9
Avg Annual
Power Power
Capacity Production
(kW) (MWh)
45 85
45 100
115 262
127 300
146
205
140
157
37
219
479
311
387
328
440
84
827
1,824
3.6
(Buster Cr)
4.9 50 9.5 534 ~.035
11.5
18.7
6.8
3.4
8.4
23.0
(BusterCr) (BusterCr) (BusterCr)
25.3
50.9
11.7
35.5
34.2
7.5
100
63
•200
75
75
50
24.1
56.3
13.9
20.1
18.8
7.6
724
166
381
454
144
185
174
359
36
2, 750
390
871
1,006
331
624
594
889
124
Hydro
Development
Cost
($1,000,000)
3.40
3.43
4. 79
4.81
7.76
4. 70
2.95
7.79
1.32
4.24
5.43
7.52
12.47
6.58
14.98
11.27
4.03
5.11
4.06
9.17
6.00
Equiv.
Annual Cost
Cost ($)/
($1,000) (kWh)
258 3.04
260 2.60
364 1.39
365 1.22
589
357
224
591
100
322
412
571
946
499
1,137
855
306
388
308
696
455
1.89
0.92
0.68
1.34
1.19
0.39
0.23
0.28
0.34
1.28
1.31
o:85
0.92
0.62
0.52
0. 78
3.67
2.5 CONCLUSIONS AND RECOMMENDATIONS
0
0
0
0
0
Of the fifty communities studied, only the communities of
Allakaket, Alatna, Anaktuvuk Pass and Nome have potentially
economical sites in their vicinity.
Sites at lnukpasugruk Creek near Anaktuvuk Pass and
Osborn Creek near Nome offer the potential of producing
energy at a present value in excess of the cost of construct-
ing the hydroelectric facilities.
It is recommended that political, legal and institutional frame-
works be developed to reduce the use of imported skilled
labor for the communities of Allakaket, Alatna, Bettles,
Brevig Mission, Teller, Elim, Galena, Golovin, Kiana, Kobuk,
Shungnak, Manley Hot Springs, and Tanana. If use of im-
ported skilled labor is reduced in these communities, hydro-
power projects may be economical.
It is recommended that reconnaissance geotechnical investiga-
tions be performed at the hydropower sites in Allakaket,
Alatna, Bettles, Elim, Manley Hot Springs, and Tanana. If
diversion structure construction costs can be significantly
reduced below those estimated in this study, the potential
benefit to cost ratio of the hydropower project should be re-
evaluated.
It is recommended that a feasibility study of small hydropower
sties in the vicinity of Anaktuvuk Pass and Nome be initiated.
A larger hydropower project studied by General Electric in
1979, involving a low dam across the Nome River, also ap-
pears to warrant further study.
-12 -
EXISTING CONDITIONS
3.0 EXISTING CONDITIONS
For each of the 50 communities studied, the existing generators, cap-
acity, peak demand, annual electrical use and cost, and expected life
are described in Table 3. 1.
3.1 COMMUNITY CHARACTERISTICS
Communities in Northwest Alaska can be described by two gener-
al classifications: regional or sub-regional centers, and villages.
Regional or sub-regional centers are characterized by the pre-
sence of jet air service to major population centers, facilities for
the storage and transfer of bulk commodities by barge, and
retail outlets for consumer and durable goods. They are the
location of governmental and private enterprise administrative
and service systems for large, sparsely populated geographic
areas. The people in the centers in the study area are predom-
inantly Alaska natives but also contain the majority of the non-
natives living in the northwest region.
3.1. 1 Regional Centers
A disproportionate number of the year-round high-pay-
ing jobs in the study are located in the regional centers.
This accounts for the concentrations of non-natives, al-
though an increasing number of native people are en-
gaged in administrative jobs, especially in connection
with the regional profit and non-profit corporations.
Residents holding full-time employment live in a style
similar to that in Anchorage or other major population
centers in Alaska. The remainder of the population may
be described as seasonal workers who are employed in
fishing, construction, or, to varying degrees, subsist-
ence hunting and fishing. Many in this category are
eligible for unemployment or transfer payments on an
-13 -
TABLE 3.1
EXISTING CONDITIONS
Peak Annual Consumer Expected
Type of Demand Capacity Use Cost Life
Communitl: Generator (kW) (kW) (MWh) {$/kWh) (Years)
Alatna Diesel 4 (E) 4 (E) 20 0.37 10
Allakaket Diesel 150 (E) 200 1,121 0.37 10
Ambler Diesel 77 420 268 0.37 15
Anaktuvuk 0.15 < 600 kWh
Pass Diesel 288 500 1,000 0.45 > 600 kWh 25
Barrow Gas Turbines 2,000 6,950 11,693 0.15 15
Bettles Diesel 225 900 1,010 0.37 15 .....
~ Brevig Mission Diesel 100 (E) 148 400 0.35 (E) 10
Buckland Diesel 100 360 350 0.65 10
Candle Gas/Diesel 10 10 7 0.50 (E) 10
Cape Lisbourne Diesel 950 1,868 3,000 0.12 20
Council Diesel 11.5 11.5 62 0.50 (E) 10
Dead horse Gas/Diesel 1,800 2,650 20,000 (E) 0.25 25
Deering Diesel 110 150 175 0.35 (E) 5
Elim Diesel 60 285 228 0.37 15
Galena Diesel 1,325 2,750 8,332 0.33 5
Golovin Diesel 177 768 608 0.35 (E) 10
Hughes Diesel 63* 25 159 0.50 (E) 10
Huslia Diesel 110 350 224 0.37 15
lgnalik (Little Diesel 50 50 169 0.09 6
Diomede) (fuel only)
* After Electrification
TABLE3.1
EXISTING CONDITIONS
Continued
Peak Annual Consumer Expected
Type of Demand Capacity Use Cost Life
Communit~ Generator (kW! (kW) (MWh) ($/kWh) (Years)
Kaltag Diesel 92 455 399 0.37 15
Kiana Diesel 144 650 645 0.37 15
Kivalina Diesel 89 510 368 0.37 15
Kobuk Diesel 25 100 122 0.50 (E) 10
Kotzebue Diesel 1,568 3,420 5,494 0.25+ 10
~ Koyuk Diesel 68 200 196 0.37 15 (.11
Koyukuk Diesel 80 205 750 0.37 10
Lon ley Diesel 750 1,550 164 0.17 (E) 10
Manley Hot Springs Diesel 37.5 110 131 0.37 (E) 10
Minto Diesel 68 215 224 0.37 15
Nenana Coal-Fired 1,950 9,500 0.15 25
Noatak Diesel 86 310 337 0.37 15
Nome Diesel 3/100 6,850 14,000 0.19 20
Noorvik Diesel 192 600 732 0.37 15
Niuqsut Diesel 150 240 526 0.15 < 600 kWh 1
0.50 > 600 kWh
Nulato Diesel 167 550 543 0.37 15
Point Hope Diesel 300 510 1,590 0.15 < 300 kWh 15
0.35 > 300 kWh
Point Lay Diesel 35 80 408 0.15 < 600 kWh 15
0.45 > 600 kWh
TABLE 3.1
EXISTING CONDITIONS
Continued
Peak Annual Consumer Expected
Type of Demand Capacity Use Cost Life
Communit~ Generator (kW) (kW) (MWh) ($/kWh) (Years)
Prudhoe Bay Gas Turbine 70,000 159,000 120 Million 40
Rampart Diesel 32.5 32.5 139 0.37 (E) 10
Selawik Diesel 206 650 647 0.37 15
Shaktoolik Diesel 500 195 200 0.37 15
Shishmaref Diesel 144 705 539 0.37 15
Shungnak Diesel 96 705 337 0.37 15
..... Solomon Diesel 10 10 8 0.50 (E) 10
0"1 Tanana Diesel 425 1,000 1,489 0.17 10
Teller Diesel 130 465 441 0.35 20
Umiat Diesel 10 10 (E) 5 (E) 0.50 (E) 10
Wainwright Diesel 315 600 1,300 0.15 < 600 kWh 15
0.35 > 600 kWh
Wales Diesel 39 185 127 0.37 15
White Mountain Diesel 20 300 60 0.37 (E) 6
annual cycle. A significant proportion may consider
themselves temporary residents for the purpose of earn-
ing money to return to their home villages. The native
cultural attributes of the lnupiat Eskimo and Athabascan
Indian are present but not predominant in the regional
centers. English is spoken almost exclusively and dress
is western. The strongest remaining link to the native
culture is the preference for subsistence foods in the
daily diet. Full-time and seasonal workers alike partici-
pate in subsistence activities in-season.
The economies in the study area derive almost entirely
from government directly or indirectly. Private sector
activities such as tourism, commercial fishing, gold min-
ing and trapping play a role but are a small proportion
of total economic activity, generally less than one-third.
Direct government employment includes education, law
enforcement, delivery of social services, military installa-
tions, administration of general government business, and
health care delivery.
Retail and transportation services are the next ranking
employment activity. Construction follows and is predom-
inantly government financed. The Department of Hous-
ing and Urban Development constructs and manages hous-
ing for low income Alaska natives. This group comprises
about half of the area population.
Energy needs in regional centers do not differ greatly
from like-size communities elsewhere. Institutional use
such as schools, hospitals, municipal utilities, and com-
mercial buildings is the largest category. Industrial
uses are limited to fish processing and gold mining
(Nome), both concentrated in summer. Residential use
varies with three groups of households; substandard,
-17 -
HUD units, and new private, including apartments. Use
in substandard housing is limited by the absence of ade-
quate wiring and major appliances, because people in
these homes cannot afford them. HUD units are all simi-
lar in size but vary in the appliances installed. The
Housing Authorities are constrained in installation of
appliances by requirements that the recipients be able to
demonstrate ability to pay the operating expenses of the
dwelling. Total utility expenditures per month can easi-
ly exceed $400 (heating, water and sewer, telephone,
and electricity). New private homes and apartments con~
tain appliances commensurate with the salaries their oc~
cupants earn, often over $35,000/year.
3.1.2 Villages
Villages are permanent settlements with a government
body, either tribal or state chartered city. Populations
range from 50 to 350. Populations are 90 percent plus
Alaska native with the majority of the non-natives dir-
ectly associated with the schools. Many of the villages
are traditionally oriented, with life closely tied to the
land and the weather. lnupiat or Athabascan may be
spoken exclusively at community meetings with English
clearly a second language. Subsistence hunting and
fishing is a vital part of village life both culturally and
economically. Retail trade, city and/or tribal adminis-
tration provide the only full-time year-round employ-
ment. Education is the largest wage activity with full-
time work for custodial, kitchen, and maintenance per-
sonnel. Teachers, the highest paid village workers, are
predominantly transient non~natives who do not establish
themselves in the community. It is a conscious policy in
many villages to discourage teachers from assuming
permanent residence. As a result, the high salaries of
~ 18 -
teachers are not reflected in private expansion of the
housing stock. Several service jobs such as maintenance
of the electric plant, operation of the water and sewer
system, postal service, and clearing the runway are
part-time because of the small size of the population
served. Consequently, wages are low, as is depend-
ability.
Seasonal opportunities provide the bulk of cash earnings
in the village economies. They tend to be concentrated
in summer and include commercial fishing, firefighting,
and construction, all of which may require moving to
another village or regional center. Winter brings fur
trapping. Subsistence hunting, fishing, and logging are
the largest real income-producing activities in the area.
More than half of the food and virtually all of the pro-
tein in the village diet comes from hunting and fishing.
Where there is timber present, wood is used for heating
fuel, which saves an average family over $2, 000/year.
Although little cash or wage income is produced in sub-
sistence it plays a vital symbiotic role with seasonal and
part-time wage activites.
Energy needs in villages are tied directly to the facilities
present. A typical village has a high school/elementary
school, some form of water system, a number of HUD
housing units, several house size community buildings
such as clinics and city offices, and whatever housing
stock has not been replaced by HUD.
The school with its lighted gymnasium, large kitchen,
shop facilities, and its automatic heating system is the
largest electric user in a village. The next largest user
is the village water system. In villages such as Ambler,
the piped system may cost as much as $1, 800/month for
electricity to pump effluent to keep it from freezing.
-19 -
Many villages have a washeteria which is a central facil-
ity at which shower, laundry, and drinking water needs
can be filled. These are somewhat cheaper to operate in
terms of energy and in user fees when compared to
piped systems. The next class of user is the residential
user. Homes built by HUD have limited electric appli-
ances and average in the neighborhood of 300 kWh/
month. The largest uses of electricity are for enter-
tainment (television), lighting in winter, and freezing
food in summer. Laundry is a large user both summer
and winter.
Several villages in the study area have summer fish pro-
cessing facilities. These require large amounts of elec-
tricity for making ice and running processing equipment.
Some have cold storage capacity which also is a large
user.
3.2 EXISTING ELECTRICAL GENERATION SYSTEMS
The majority of the communities rely upon diesel powered genera-
tors for their electrical power, most commonly ranging between
50 to 800 kW capacity. These plants are generally owned by
small utility companies or by the Alaska Village Electric Cooper-
ative (AVEC), which serves many small, remote communities. In
a few communities (Candle, Council, Koyukuk), the only sizeable
generator is associated with the school, which may or may not
sell power to the community. In the smallest communities in this
study, such as Candle, the only electrical power available is
produced by individuals using small gasoline electric generators.
In Barrow, Prudhoe Bay, and Dead horse, both diesel and natur-
al gas fired turbines provide electrical power. Nenana was the
only community in this study served by a coal fired plant (lo-
cated in Healy).
-20 -
3.3 EXISTING ELECTRICAL POWER REQUIREMENTS
For villages, the primary electrical energy requirements are for
lighting and appliances. Appliances would include electrical
space heaters, televisions, freezers and battery chargers.
Freezers are a high priority item, since they can replace the in-
convenient traditional methods of meat preservation during the
warm weather months. Since higher temperatures yield propor-
tionally greater runoff, hydroelectric power potential complements
peak electrical use by freezers. As discussed earlier, community
schools are generally the largest single consumers of electricity
in most villages.
Existing electrical power requirements were based on AVEC re-
cords, questionnaire responses from villages, and past studies.
Where published information was lacking, engineering estimates
were based on the number of houses, size of school, and number
and types of stores, shops and centers in the community. Load
factors were used to convert peak demands to annual electrical
consumption. Load factors generally ranged between a high of
0. 4 for stores and shops to a low of 0. 2 for U.S. Public Health
Service facilities. Load factors were varied among communities
to account for different community characteristics.
-21 -
PROJECTED ELECTRICAL POWER REQUIREMENTS
4.0 PROJECTED ELECTRICAL POWER REQUIREMENTS
4.1 LOAD GROWTH PROJECTION METHODS
4.1. 1 Introduction
Load growth in NW Alaskan villages is difficult to predict
because of the great amount of uncertainty surrounding
the effects of government policy and consumer prefer-
ence changes in small populations. Since nearly all eco-
nomic activity is linked to government sources, a small
policy change may produce a relatively large village im-
pact. Similarly, population dynamics have a great impact
on energy demand. For instance, the subtraction of five
families from Ambler could change the residential demand
by 15 percent.
These factors significantly affect load growth in villages;
0 Population
0 Level of income
0 Infrastructure
0 Government policy on energy usage
4. 1. 2 Population
Population growth or decline is influenced by a number
of factors beyond the control of the village. Availability
of housing is a key determinant in the decision of where
a family will live. Privately financed housing construc-
tion is rare in a village because the lack of permanent
jobs precludes the ability to demonstrate payback poten-
tial. Consequently the provision of housing lies with the
government, primarily HUD. The village of Deering ac-
quired six new homes through a BIA program and sub-
sequently enticed five new families to move there from
-22 -
other villages and Anchorage. All the secondary vacan-
cies created by the new housing were filled. In a sur-
vey of households in NANA Region in 1978 1 the question
was asked 1
11 1f you would have to wait five years to re-
ceive a new HUD home in your home village 1 would you
consider moving to another NANA village to get one
sooner?" The response in Kotzebue was 32 percent yes
and in the villages 28 percent yes.
Village demographics are highly skewed toward the
young. Many have median ages of 16 years and young-
er. Where these young people will establish households
as they mature will be largely determined by where hous-
ing is located. Allocations are made by the regional
housing authorities.
The location of population is also strongly influenced by
the availability of subsidized employment. Comprehen-
sive Employment and Training Act funds may employ 75
percent of the work force in a village during the course
of the year. Virtually all municipal labor is provided by
C ETA. Hard cash generated by city sales taxes and
revenue sharing go for non-wage items such as electri-
city and fuel oil. CETA may well be dropped as a fed-
eral program. This could cause a significant population
shift as indicated by the response to this question: 11 lf
no work were available in your village would you take a
job in Kotzebue?" Sixty-eight percent answered yes.
This further volatility in population may be indicated by
the response regarding a question about longevity of
employment. Over 85 percent responded that they had
been in their current positions less than one year.
-23 -
4.1.3 Level of Income
The level of income in a village consists of three compo-
nents: cash earnings 1 transfer payments, and subsis-
tence. Cash earnings as mentioned earlier come from
fishing, firefighting, construction, trapping, retailing,
and government or subsidized employment. Fishing and
trapping are private sector activities. The others are
government induced and susceptible to policy change.
CET A employment is a major job source. Its overall lev-
el is determined by a funding formula allocation process
which stems from the annual congressional appropriation.
Depending on Congress•s mood, the program may be up
or down. Recently the program has decreased about 10%
per year. This will probably continue unless CETA is
totally terminated. Should CET A be reduced further or
eliminated, the number of village residents receiving
transfer payments would increase. This would mean a
decrease in income. At the same time, city services
would increase in cost because labor would have to be
paid for by users. The increase could be sufficient to
lapse utilities into bankruptcy causing closure of city
buildings and water and sewer projects with subsequent
decrease in electric demand.
Transfer payments are a larger income source than
CETA. They are stable and can be considered a base
under which village economic activity will not drop.
They are, however 1 unable to respond quickly to infla-
tion. Temporary or even permanent reductions in real
income can result. The number and type of appliances
installed by HUD in new homes are tied to the level of
income. Households must be able to demonstrate that
they will be able to afford to operate the home.
-24 -
Consequently, HUD will limit the electrical usage in
homes going into a village with no economic base.
Subsistence can be a major factor in real income levels.
The family which successfully harvests its food needs
from locally available fish, game, and berries directly
reduces its need for cash. The net effect is an increase
in disposable income without increased cash income. If,
in addition, the family can secure its heating fuel needs
from surrounding timber, it can further reduce its need
for cash. Those pursuing this style of economic activity
minimize their monthly expenditures, thus making them-
selves better able to purchase large items such as snow-
machines and freezers.
Direct government employment comes in three areas:
program delivery; education and other facilities; and
construction. Program delivery from federal sources
grew rapidly in the 1970's following the Alaska Native
Claims Settlement Act, peaking sometime around 1978,
and have remained constant in dollar value or have in-
creased at a rate slower than the cost of living. New
programs have been picked up, but overall, efforts of
the Federal government to reduce the budget deficit are
felt in NW Alaska.
State of Alaska programs are at present increasing rap-
idly. Regional centers are receiving increased funding
for social service programs, planning, and in some cases
supplemental CETA programs. Villages feel the increases
in new revenue sharing formulas which provide increased
cash that can be used for utilities and other non-labor
costs.
-25 -
4.1. 4 Infrastructure
Nearly all the infrastructure in the villages is provided
by the government grants. It includes schools, water
and sewer systems, housing, community buildings, air-
ports, and streets. Construction of these facilities is a
major wage activity in Northwest Alaska. Once a com-
munity has received its share of the facilities it can look
forward to a reduction in employment activities at the
very time that bills are increasing as the new homes and
community buildings must be operated. In the case of
schools, this is not a problem because the State directly
pays operating expenses.
Every village has a right under Federal law to have an
adequate water and sewer system, and housing for low
income people. Under State law, every village with 8 or
more secondary students has a right to a high school.
The provision of transportation services is the responsi-
bility of both, and improvements in airports including
lights at remote vi II ages can be expected over the next
ten years.
4.1.5 Government Policy on Energy Usage
The State's position on the price of electricity in small
rural communities has long been an issue in the Alaska
Legislature. In 1978 pressure from rural legislators
brought about a bill called 11 lifeline11 which would have
significantly reduced the cost of the first 300 kWh/month
per customer and then penalized further consumption by
sharply increased rates for additional use. The bill was
defeated. In the 1980 session, A.S.83 was amended to
read:
-26 -
11 Power production cost assistance shall be paid to
an eligible electric utility if the actual power pro-
duction costs of the utility exceed its adjusted
power production costs as determined annually by
the Commission. The adjusted power production
costs of an electric utility are:
(1) 15 percent of the portion of the actual
power production costs which does not exceed 40
cents per kWh; plus
(2) the base power production cost escalation.
The base power production cost escalator is 7. 65
cents per kWh adjusted annually by a percentage
equal to the percentage of change in the Anchorage
consumer price index for the year. 11
If fully implemented, this bill would reduce the cost per
kWh approximately 15.25 cents for AVEC customers and
10 cents for regional centers such as Nome. The long
term effect of this should be to increase consumption,
especially as economic substitutions become possible when
other energy sources rise in price more rapidly than
electricity.
The amended law also states that by 1988 all State owned
or operated facilities shall comply with thermal and light-
ing efficiency standards to be adopted by the Depart-
ment of Transportation and Public Facilities. Conversa-
tions with the consultant preparing the standards for
DOT /PF indicate that initial targets of a reduction of 20
percent of electric usage in buildings, such as the
schools recently built in the study area villages, are
likely at a minimum, and that larger cuts are probable
because of the large portion of total energy in schools
that is consumed as electricity. Stricter standards also
are included for homes constructed with financing pro-
vided by any of the State guaranteed or subsidized loan
programs.
-27 -
4.2 PROJECTED DEMANDS FOR EACH COMMUNITY
As discussed previously, load growth in NW Alaska communities
is quite volatile. No accurate predictor exists to project com-
munity population growth and corresponding electrical energy
consumption.
Many communities are in the process of building new community
facilities and houses. These planned construction programs were
included in our load growth estimates. Such programs were
identified in responses to a questionnaire mailed to each village
at the beginning of the study as well as by reviewing recent
pertinent literature. It was assumed these new loads would come
on line and that all communities would be fully electrified by
1990.
A base annual load growth rate of two percent was adopted for
the remainder of the study period. A previous study (Institute
of Social and Economic Research, 1980) has predicted a popula-
tion growth for the Bering-Norton Sea region of about one and
one-half percent annually for the latter part of this century.
Previous engineering studies in NW Alaska have predicted popu-
lation and load growth rates ranging from one to three percent
annually.
Two percent annual load growth was used for all communities
except for the oil production and military installations. The
latter establishments 1 or non conventional communities, are char-
acterized by temporary or transient population. They tend to
grow extremely fast at first, plateau and then disappear quickly
with termination of oil or military activity. The three oil pro-
duction sites in this study, Prudhoe Bay, Deadhorse, and Camp
Lonely 1 were assumed to have reached stable growth levels.
Projection of these levels over the study period appears reason-
-28 -
able based on literature review. The same approach was em-
ployed for the military installation at Cape Lisbourne.
Projected annual demands for 1990, 2000, and 2030 are displayed
in Table 4.3.1.
4.3 PRESENT VALUE OF PROJECTED ENERGY DEMANDS
To determine the present value of projected energy demands, the
present consumer cost of generated electricity for each commun-
ity was divided into two components. The first component is the
portion of the consumer cost which can be attributed to the cost
of fuel and lubricants. The second component of the consumer
cost of energy can be attributed to all other costs associated
with production of the electrical energy. These other costs in-
clude amortized capital investment costs, operation and mainten-
ance costs and depreciation costs. Two present value analyses
were performed for a 50 year economic life at a discount rate of
7-3/8 percent. The first analyses was performed on the fuel
component of the consumer power cost. This component was
escalated at 5 percent per annum in addition to the projected
load growth rate. The second component of the consumer
energy cost attributed to non-fuel cost was escalated at the load
growth rate only and did not include the 5 percent escalation
rate used for the fuel cost portion. Table 4.3.1 summarizes the
present value computations for each of the 50 communities. As
shown in the table, the 1980 cost of generated electricity was
determined by multiplying the 1980 electrical demand by the
present cost per kilowatt-hour.
Listed in the table is the assumed fractional split of the 1980
energy cost between the fuel component and the non-fuel com-
ponent. For example, 28 percent of the 1980 consumer cost of
generated electricity at Ambler was assumed to be attributed to
fuel and lubricant costs.
-29 -
The estimated consumer energy cost at Ambler is 37.2¢ per kilo-
watt-hour, 28 percent of which is assumed to pay for fuel and
lubricants. Thus, the 1980 cost of energy in Ambler was com-
puted to be $27,930 for fuel and lubricants and $71,820 for other
costs associated with the electrical generation.
The 1980 base cost for fuel and lubricants was escalated at 5
percent per annum and at the projected load growth rate. The
present value of the fuel and lubricant cost over a 50 year
economic life (1980 to 2030) was computed by the following
formula:
K = [1 -(1 + a I I + i)n] + i - a
Where: K = the present worth factor for an inflation series
+ a = (1 + fuel cost escalation rate/100) X
(1 + load growth rate/100)
+ i = 1 + (discount rate/100)
n = Period of analysis = 50 years
Discount Rate = 7-3/8 percent
Thus, the present value of the fuel cost portion of the energy
demand between 1980 and 2030 at Ambler was computed to be
$1,639,304.
In a similar manner, the non-fuel component 1980 base price was
escalated at the load-growth rate, with the escalation rate equal
to zero. For Ambler, the present value was computed to be
$1,578,619 for the non-fuel cost component, for a total present
value of fifty years of generation of electricity of $3,217,923.
The final column in the table shows the equivalent average
annual cost over the 50-year period at a 7-3/8 percent discount
rate.
The fraction used to split 1980 energy costs between the fuel
and non-fuel components was determined for each community
-30 -
based on a review of electrical cost data from the Alaska Village
Electric Cooperative (AVEC). Additionally, the fuel portion
fraction was compared to the cost of fuel required to generate
electricity, assuming a diesel generator efficiency of 10 kilowatt
hours produced for each gallon of fuel consumed. Diesel gen-
erators running at peak efficiency consume about one gallon of
diesel fuel for each 14 kilowatt hours produced. However, such
efficiencies require large installations with a variety of diesel
generators to meet fluctuations in demand. Most of the genera-
tor installations in this study consist of two or three units of
approximately the same size. They often run at close to idle
speed, consuming about one gallon of fuel for every six kilowatt
hours generated. Furthermore, maintenance of diesel generators
in villages is typically well below the standards set by the
equipment manufacturers to maintain peak efficiency from the
units.
In general, the fuel and lubricant cost component was usually
assumed to be about 30 percent of the total 1980 consumer cost.
-31 -
TABLE 4.3.1
PROJECTED ELECTRICAL DEMANDS AND PRESENT VALUE
Equivalent
1980 Fraction Present Value ($1,000,000) at Average
Consumer of Cost 5% Fuel Escalation Annual
Electrical Demand 'MWh} Cost Due to Fuel Non-Fuel Cost
Communit:k: 1980 1990 2000 2030 (~!kWh) Fuel Comeonent Comeonent ~ (~1,000)
Alatna 20 137 171 307 0.37 0.30 0.49 0.37 0.86 65
Allakaket 1,121 1,356 1,670 3,015 0.37 0.30 5.43 4.97 10.4 787
Ambler 268 445 560 1,007 0.37 0.28 1.64 1.58 3.22 244
Anaktuvuk Pass 1,000 1,745 2,340 7,030 0.30 0.33 7.51 5.08 12.59 956
w
N Barrow 11,693 18,712 23,390 42,101 0.15 0.65 63.35 13.06 76.41 5,800
Bettles 1,010 1,212 1,515 2,127 0.37 0.31 5.09 4.44 9.53 723
Brevig Mission 400 480 600 1,080 0.35 0.30 1.84 1.68 3.52 267
Buckland 350 988 1,235 2,223 0.65 0.80 7.43 1.29 8.72 662
Candle 7 8.4 10.5 18.9 0.50 0.30 0.05 0.04 0.09 7
Cape lisburne 3,000 1,500 1,500 1,500 0.12 0.90 4.59 0.24 4.83 367
Council 62 74 93 167 0.50 0.30 0.41 0.26 0.67 51
Dead horse 20,000 20,000 20,000 20,000 0.25 0.65 68.67 23.02 91.70 6,960
Deering 175 210 263 472 0.35 0.30 0.80 0.73 1.54 117
Elim 228 769 962 1,731 0.37 0.28 2.67 2.39 5.06 384
Galena 8,332 8,865 9,664 12,859 0.27 0.48 15.08 6.40 21.48 1,631
Golovin 608 730 912 1,641 0.35 0.30 2.79 2.55 5.34 405
Hughes 159 190 239 429 0.50 0.30 1.04 0.95 1.99 151
Huslia 224 464 581 1,045 0.37 0.32 1.92 1.49 3. 41 259
lgnaluk (little 169 203 254 456 0.09 1.00 0.67 0.00 0.67 51
Diomede) (Fuel only)
TABLE 4.3.1
PROJECTED ELECTRiCAL DEMANDS AND PRESENT VALUE
Continued
Equivalent
1980 Fraction Present Value ($1 ,000,000) at Average
Consumer of Cost 5% Fuel Escalation Annual
Electrical Demand (MWh} Cost Due to Fuel Non-Fuel Cost
Community 1980 1990 2000 2030 ~i/kWh} Fuel Comeonent Comeonent Total (i1t000)
Kaltag 399 533 666 1,199 0.37 0.24 1. 71 2.09 3.81 289
Kiana 645 864 1,037 1,296 0.37 0.30 3.07 2.96 6.03 458
Kivalina 368 506 633 1,139 0.37 0.30 2.02 1.82 3.84 292
Kobuk 122 146 183 329 0.50(E) 0.30 0.80 0.73 1.53 116
Kotzebue 5,494 12,636 30,217 54,391 0.25 0.60 106.9 22.2 129.1 9,804
Koyuk 196 235 294 529 0.37 0.30 0.83 0.76 1.59 120
(/.) Koyukuk 750 900 1,125 2,025 0.37(E) 0.30 3.64 3.32 6.96 528 U)
Lonely 164 164 164 164 0.17(E) 0.60 0.47 0.11 0.58 44
Manley Hot Springs 131 157 197 354 0.37(E) 0.30 1.82 0.58 2.40 182
Minto 224 269 336 605 0.37 0.27 0.87 1.06 1. 96 149
Nenana 9,500 19,000 37,000 88,800 0.15 0.65 98.52 16.60 115.12 8,737
Noatak 337 468 585 1,053 0.37 0.30 1.87 1.67 3.54 269
Nome 14,000 31,900 72,900 176,515 0.19 0.66 80.28 37.56 117.84 8,944
Noorvik 732 878 1,098 1,976 0.37 0.30 3.57 3.26 6.83 519
Nuiqsut 526 631 789 1,420 0.33 0.35 2.66 1.93 4.60 349
Nulato 543 698 867 1,571 0.37 0.30 2.81 2.54 5.35 406
Point Hope 1,590 1,907 2,212 4,195 0.25 0.36 5.64 4.25 9.88 750
Point lay 408 490 612 1,102 0.30 0.41 1.90 1.24 3.14 238
Prudhoe Bay 120,000 120,000 120,000 120,000 0.15 0.65 322.0 157.0 489.0 37,000
Rampart 139 167 209 376 0.37 0.30 0.67 0.62 1.29 98
Selawik 647 830 1,038 1,868 0.37 0.30 3.35 3.03 6.38 485
TABLE 4.3.1
PROJECTED ELECTRICAL DEMANDS AND PRESENT VALUE
Continued
Equivalent
1980 Fraction Present Value ($1,000,000) at Average
Consumer of Cost 5% Fuel Escalation Annual
Electrical Demand (MWh) Cost Due to Fuel Non-Fuel Cost
Communitl: 1980 1990 2000 2030 (~/kWh) Fuel Comeonent Comeonent Total (~1,000)
Shaktoolik 200 1,196 1,496 2,692 0.37 0.28 4.00 3.43 7.42 563
Shismaref 539 647 809 1,455 0.37 0.28 2.46 2.47 4.93 374
Shungnak 337 440 551 991 0.37 0.28 1.48 1.68 3.16 240
Solomon 8 10 12 22 0.50(E) 0.30 0.05 0.05 0.10 8
Tanana 1,489 1,787 2,234 8,020 0.17 0.30 3.32 3.03 6.35 482
w Teller 441 529 661 1,190 0.35 0.30 2.01 1.83 3.84 291 ~
Umiat 5 6 7.5 13.5 0.50(E) 0.30 0.03 0.03 0.06 5
Wainwright 1,300 2,782 5,902 14,300 0.25 0.37 14.69 7.62 22.31 1,693
Wales 127 154 191 343 0.37 0.28 0.58 0.58 1.16 88
White Mountain 60 436 545 980 0.37(E) 0.30 1.55 1.18 2.73 208
PRELIMINARY REVIEW OF COMMUNITY
HYDROELECTRIC POTENTIAL
•
5.0 PRELIMINARY REVIEW OF COMMUNITY HYDROELECTRIC POTENTIAL
5.1 REVIEW METHODS
5.1. 1 Selection of Sites
The initial selection of potential hydroelectrical sites in-
volved interpretation and measurements from U.S. Geo-
logical Survey topographic maps. The terrain and
streams within a 20-mile radius were examined. The
watersheds nearest the communities with the greatest
relief and largest flows were selected for initial cost
analysis. With few exceptions, this selection was not
difficult since the relief near most villages was low to
moderate and only one site or watershed was available
for any potential use. After a watershed was located,
the steepest stream gradient along the lower portion of
the basin was selected for the diversion dam and pen-
stock. A maximum of 10,000 feet was allowed for the
penstock length.
5.1. 2 After potential hydroelectrical sites were selected the
generating capacity of the site was estimated. Turbines
and penstocks were sized for a potential energy corre-
sponding to 1.5 times the average annual flow in the
stream. The average annual flow was estimated to be
1-1/3 cubic feet per second per square mile drainage
area. Thus, for a drainage area 10 square miles in size
the turbine and penstock for the preliminary cost esti-
mate was sized for a capacity of 13-1/3 cubic feet per
second. Average annual stream flow in the Northwest
Alaska region varies from about 2. 5 cfs per square mile
in the Nome area to about 0.6 cfs per square mile on the
North Slope.
-35 -
The generator size computed as described above was
then compared to the 2030 electrical demand. Assuming
a plant factor of 0. 3 1 the size of generator needed to
meet the 2030 demand was computed. If this size of
generator was smaller than the computed potential energy
from the stream 1 then the penstock size and turbine and
generator size were reduced to match the 2030 demand.
5.2 DEVELOPMENT COST ESTIMATES
5. 2.1 Geographic Cost Index
Preliminary estimates of hydroelectric project construc-
tion costs were based on November 1980 Fairbanks
prices. Geographic cost indices were developed to ad-
just Fairbanks costs to particular locations in Northwest
Alaska. These indices take into account labor 1 trans-
portation and climatic induced factors that act to in-
crease construction costs of hydroelectric projects be-
yond base prices calculated for Fairbanks 1 Alaska.
Table 5.2.1.1 itemizes the cost indices for each location.
It has been assumed that a total project cost can be
broken down as:
Labor 50 percent
Materials 27 percent
Transportation -13 percent
Utilizing these percentages of total construction cost, the
geographic cost index for a particular location can be
computed: (Labor lndex)(.60) + (Transportation Index)
( .13) + (Materials Index) (.27) = Construction Cost
Index for a specific location.
-36 -
Location
Allakaket
Anaktuvuk Pass
Bettles
Brevig Mission
Buckland
Galena
Golovin
Hughes
lgnaluk
Kobuk
Koyukuk
Manley Hot Springs
Nome
Tanana
White Mountain
1 60% Weighting
2 13% Weighting
a 27% Weighting
TABLE 5.2.1.1
GEOGRAPHIC COST INDEX
FOR VARIOUS COMMUNITIES
Labor1 T ran s~ortation 2
2.24 2.60
2.35 2.60
2.39 2.6
2.37 1.07
2.36 2.6
1.99 2.6
2.43 1.07
2.42 2.6
2.51 2.57
2.45 2.6
2. 41 2.6
1.74 1.08
1. 73 1.07
2.12 2.6
2.43 2.6
FAIRBANKS BASE= 1.0
-37 -
Adjusted
Materials 3 Total
1.0 1.95
1.0 2.02
1.0 2.04
1. 0 1.83
1. 0 2.03
1 .0 1. 81
1. 0 1.87
1. 0 2.06
1.0 2.11
1. 0 2.08
1 .0 2.06
1. 0 1.45
1.0 1. 45
1. 0 1.88
1.0 2.07
5.2.2
For each location, the labor escalation index was calcu-
lated by utilizing current Fairbanks labor rates, plus an
overtime allowance, perdiem rates, rest and recreation
benefits, and current travel costs to the site. The ratio
between the base Fairbanks rate and the site rate was
taken after a local vs. imported work force ratio was
estimated for the project.
The transportation index applies only to materials and
equipment transported from Fairbanks to the project
site. Each site was evaluated in terms of the feasibility
of delivering the materials via existing air, river, all
year road and seasonal raods to obtain the least expen-
sive method of delivery. Materials such as gravel and
earthfill were not included in the index preparation due
to their variability in quantity, quality, availability and
location.
The indices represent estimated costs at each site as of
November 1980.
A more detailed description of the development of geo-
graphic cost indices is included in Appendix A
Unit Cost
Fairbanks, Alaska-based unit costs were determined for
each of the major components of a hydroelectric project.
These unit costs are listed in Table 5.2.2.1. They were
based on information presented in the following reports:
0 CH2M Hill, 1979. Regional Inventory and Reconnais-
sance Study for Small Hydropower Sites in South-
east Alaska
~ 38 ~
1 .
2.
3.
4.
5.
0
0
0
0
U . S • D . 0 . E . , 1979. Small Hydroelectric Inventory
of Villages Served by Alaska Village Cooperative
EBASCO Services, Inc., 1980. Regional Inventory
and Reconnaissance Study for Small Hydropower
Projects Aleutian Islands
General Electric, 1980. Electric Power Generation
Alternative Assessment for Nome 1 Alaska
HMS Inc., 1980. Cost Indices for Northwest Hydro-
power
TABLE 5.2.2.1
FAIRBANKS BASE UNIT COSTS
USED FOR PRELIMINARY COST ESTIMATES
Item Unit Cost per Unit
Diversion Structure L.S. $200,500
Waterways Ft. from Figure 5.2.2.1
Hydroelectric Power kW $800
Station
Transmission Line MI. $48,000
Mobilization and 30% of Above
Demobilization
-39 -
.....
Lt.. ...... .....
400
~ 200
(.)
100
o--------~--------~------~--------~------~---------0 100 150 200
FLOW IN CFS
SOURCE: 1/Llnear Foot from manual on feasibility
of small hydro. Vol. VI-Civil Features
Fig. 3 -I, multiplied by 2.0.
-40 ..
FIGURE 5.2.2-1
WATERWAYS COST
5.3 COMPARISON OF COSTS OF HYDROELECTRIC AND EXISTING
ELECTRICAL GENERATION
Using quantities taken from USGS quadrangles and sizing the
project as described in Section 5.1.2, the construction cost of a
hydroelectric project in each of the communities was estimated.
This cost was compared to the present value of the future
energy produced by the existing method of power generation for
each community, assuming a 5 percent fuel cost escalation. The
comparison is presented in Table 5.3.1 along with the ratio of
the present value of the future energy divided by the prelimin-
ary construction cost estimate.
-41 -
""' N
li-1
Conununiti Name
Alatna
Allakaket
Ambler
Anaktuvuk Pass
Barrow
Bettles
Brevig Mission
Buckland
Candle
Cape Lisburne
Council
lleadhorse
Deering
Elim
Galena
Golovin
llughes
lluslia
TABLE 5.3.1
COMPARISON OF COSTS OF
HYDROELECTRICAL AND EXISTING ELECTRICAL GENERATION
Present Value
of Future Energy Preliminary Estimate
Produced by Existing of Hydroelectric Pro-
Method of Power ject Construction Cost
Generation with 51 ($1,000,000) No Contin-(Present Value)/
Fuel Cost Escalation gencies Engineering, or (Construction Costs)
($1,000,000_) -Administration Included Ratio
0.98 2.50 0.4
10.40 2.74 3.4
3.22 1.93 1.7
12.6 5.82 2.2
76.4 No Site
9.53 2.66 3.4
3.52 5.62 0.6
8. 72 7.19 1.2
0.09 3.37 0.03
4.59 6.18 0.7
0.67 2.82 0.2
91.70 4.91 18.7
1.54 5.26 0.3
5.06 1.69 3.0
21.5 23.59 0.9
5.34 4.26 1.3
1.99 1.96 1.0
3.41 No Site
lgnaluk (Little Diomede) 0.67 1.08 0.6
Communities Previously
Studied For
Hidropower Potential
X
X
X
X
X
.$:>. w
11-2
Community Name
Kaltag
Kiana
Kivalina
Kobuk
Kotzebue
Koyuk
Koyukuk
Lonely
Hanley llot Springs
Minto
Nenana
Noatak
Nome
Noorvik
Nuiqsut
Nulato
Point Hope
Point I.ay
Prudhoe Bay
Rampart
Selawik
Present Value
of l!'uture Energy
Produced by Existing
Method of Power
Generation with 5~
Fuel Cost Escalation
__ {$1,000,000)
3.81
6.03
3.85
1.53
129
1.58
6.96
0.58
2.40
1.96
269
3.55
92.1
6.83
4.60
5.35
9.88
3.14
489
1.29
6.38
TABI.E 5.3.1
Continued
Preliminary Estimate
of Hydroelectric Pro-
ject Construction Cost
($1,000,000) No Contin-
gencies Engineering, or
Administration Included
2.39
3.87
No Site
2.40
No Site
No Site
5.54
No Site
1.18
No Site
5.57
No Site
3.44
No Site
No Site
5.45
7.69
No Site
4.91
2.92
No Site
(Present Value)/
(Construction Costs)
Ratio
1.6
1.6
0.6
1.3
2.0
48.2
26.8
1.0
1.3
99.6
0.4
Communities Previously
Studied For
_!!!Qroeo~__!'~_tent!_ a l
X
X
X
X
X
X
X
X
X
X
II-3
Community Name
Shaktoolik
Shishmaref
Shungnak
Solomon
Tanana
A Teller
A
I Umiat
Wainwright
Wales
White Mountain
* Same site as Golovin
Present Value
of Future Energy
Produced by Existing
Method of Power
Generation with 5%
Fuel Cost Escalation
($1,000,000)
7.42
4.93
3.16
0.10
6.35
3.84
0.06
22.3
1.11
2.73
TABLE 5.3.1
Continued
Preliminary Estimate
of Hydroelectric Pro-
ject Construction Cost
($1,000,000) No Contin-
gencies Engineering, or
Administration Included
No Site
No Site
4.02
2.84
4.67
4.15
1.49
No Site
1.29
4.26*
(Present Value)/
(Construction Costs)
Ratio
0.8
0.04
1.36
0.9
0.04
0.9
0.6
Commupities Previously
Studied For
Hydropower Potential
X
X
X
X
POTENTIAL HYDROELECTRIC SITES
AT SELECTED COMMUNITIES
6.0 POTENTIAL HYDRO SITES AT COMMUNITIES
6.1 COMMUNITY SELECTION CRITERIA
A number of communities were eliminated from further study
after comparing the preliminary estimate of hydroelectric project
construction cost to the present value of future energy produced
by the existing method of power generation with 5 percent fuel
cost escalation. In general, all the communities presented in
Table 5.3.1 with a present value/construction cost ratio less
than 0. 8 as well as communities with no identified hydroelectric
sites were eliminated from further study. In addition, Dead-
horse, Nenana and Prudhoe Bay were eliminated from futher
study because their electrical demands far exceeded any identifi-
able hydroelectric potential. Each of these communities is ade-
quately and efficiently served by electricity generated by fossil
fuel. Although the present value/construction cost ratio was
less than 0.8 for Brevig Mission, Kobuk and White Mountain,
they were included in further studies because of their potential
for interties with communities with a present value/construction
cost ratio equal to 0.8 or greater.
6. 2 Fl ELD RECONNAISSANCE
Many of the communities which passed the initial screening de-
scribed in the previous section have previously been studied for
hydropower potential and have been visited by previous study
participants. Those communities which exhibited a favorable
present value/construction cost ratio and which had not been
previously visited by persons studying the communities for
hydropower potential were selected for field reconnaissance sur-
veys. The purpose of the field reconnaissance was to provide
study participants and individual community leaders with an in-
field overview of sites which illustrated some development poten-
tial and to expose study participants to site conditions and
-45 -
individual community needs. The communities of Allakaket,
Anaktuvuk Pass, Bettles, Brevig Mission, Buckland, Galena,
Golovin, Hughes, lgnalik (Little Diomede), Kobuk, Koyukuk,
Manley Hot Springs, Nome, Tanana, Teller and White Mountain
were chosen for field reconnaissance surveys.
A letter informing the community of the purpose and the date of
the field reconnaissance was mailed in advance to each of the
communities. Each of the communities was visited by a civil
engineer and a mechanical engineer. As a result of the field
reconnaissance it was determined that:
0
0
0
0
Canals and flumes offer a good potential for conveying
water from the diversion dam to the head of the pen-
stock, thus reducing penstock cost. A number of sim-
ilar type canals were witnessed in the Nome and Buck-
land area.
Hydroelectric operation during the ice-free season only
should be considered. It appears that none of the
streams investigated offer significant hydroelectric gen-
eration potential during the winter season. Detailed
hydrologic analysis would be necessary to confirm this
result.
lgnalik (Little Diomede) was eliminated from futher study
because of inadequate streamflow.
All the communities are quite interested in any form of
energy that will replace expensive diesel electric gener-
ation. However, many voice concern over running diesel
electric in conjunction with hydroelectric plants during
the summer season. Complete transition to hydroelectric
generation during the summer months is much preferred
over a combined diesel and hydroelectric generation sys-
tem during the summer.
-46 -
0 Many of the communities would take advantage of hydro-
electric generation during the summer to supply electri-
city to freezers. Use of freezers in the summer is much
preferred over any other alternative for food preserva-
tion.
6.3 HYDROLOGIC ANALYSIS
All USGS records of continuous streamflow in the Yukon Basin,
Northwest, and Arctic Slope regions of Alaska were examined for
their hydropower potential. The records indicate that a wide
range of summer flows, expressed as run-off per square mile,
exist in the region and these differences are not easily cor-
related with hydrologic features derived from topographic maps.
A multiple regression analysis was performed to determine re-
gression equations for 50 percentile monthly flow values, 80
percentile monthly flow values, and minimum low summer flow
values. The independent variables used in the equations are
drainage area, main channel slope, mean basin elevation, area of
forest cover, mean annual precipitation, mean annual snowfall,
and mean minimum January temperature. Flows for winter
months (November through April) showed no significant correla-
tion with hydrologic features other than area. Winter month
flows were estimated from runoff per square mile relationships
developed from the nearest representative gauge record.
From the equations, the 50 and 80 percentile flows for any given
potential hydropower site in Northwest Alaska can be calculated.
However, it is apparent from the records that monthly flows
determined by these regression equations for ungauged hydro-
power sites could be in error as much as 50 percent. Estimated
total runoff for the year is probably within 20 percent of actual.
-47 -
The median annual flow at each hydroelectric site is the mean
value of the twelve SO percentile monthly flows. This flow can
be expected to be exceeded SO percent of the time during a
year. The median annual flow for each hydroelectric site is
displayed in Summary Table 2. The mean value of the twelve 80
percentile monthly flows is equivalent to the 20 percent exceed-
ence flow on an annual flow-duration curve. That is, this flow
can be expected to be exceeded 20 percent of the time during a
year. This flow was used to size hydroelectric turbines, as
described in Section 6.6.2, Design Capacity.
The computed SO and 80 percentile monthly flows are presented
in Section 6. 7 for each community passing the initial screening.
A more detailed description of the hydrologic analyses is in-
cluded in Appendix B.
6.4 ENVIRONMENTAL CONSTRAINTS
None of the hydropower projects presented fall inside the bound-
aries of the present boundaries of national monuments, national
parks, or wilderness areas. Furthermore, none of the diversion
dams cross streams that are wild and scenic rivers.
Streams associated with selected potential hydroelectric sites
were examined in Alaska's Fisheries Atlas to determine probable
fish populations. In a like manner, the selected potential hydro-
electric sites were reviewed to determine conflict with known
peregrine falcon, Falcon peregrinus tundrius and/or Falcon
peregrinus anatum, nesting sites. The locations of known nest-
ing sites are recorded on maps filed in the Endangered Species
Office, U.S. Fish & Wildlife Service. Potential hydropower sites
and transmission line routes were reviewed for conflict with
known archaeological or historic sites. This review was con-
ducted with the assistance of the State Archaeologist and his
staff.
-48 -
6.4.1 Fish
An accurate assessment of the potential impact resulting
from the development of any small hydroelectric project
upon the fish resources of a stream would require a site
specific study. As a preliminary assessment, all streams
involved in the development plans for the 22 selected
communities were reviewed in Alaska's Fisheries Atlas.
This publication provides a good general view of fish
species distribution, but not a complete inventory. Some
small scale utilization of a stream by salmon may not be
covered by the Atlas, as is the case with the Elim pro-
ject. It also indicates populations which may not actu-
ally occur or are insignificant. Fish species shown to
occur in the study area include Arctic grayling, north-
ern pike, burbot, several species of whitefish, Arctic
char, Dolly Varden and several species of salmon. Arc-
tic grayling and the various species of whitefish are
known to be present in nearly all freshwater habitats of
the Northwest region of Alaska. Arctic char and Dolly
Varden enjoy a nearly universal distribution in the re-
gion, being native to all major watersheds and occurring
as anadromous and nonanadromous races. Of the 22
selected community projects, the occurrence of Arctic
char/Dolly Varden (not distinguished separately in the
Atlas) is shown as 11 occasionaJI1 for Allakaket, Bettles,
Galena, Hughes, Kaltag, Koyukuk, Manley Hot Springs,
Nulato and Tanana and 11 present11 for the remaining
areas. Northern pike and burbot are noted along the
major rivers of the region such as the Yukon. But their
occurrence beyond the slack waters of the lowermost sec-
tions of several project streams would be most unlikely.
Salmon are known to be present in the streams involved
with the Elim, Galena, Golovin, and Kaltag projects.
-49 -
6.4.2 Biological Concerns
All selected hydroelectric sites were checked for known
Peregrine Falcon nesting sites at the Endangered Species
Office of the U.S. Fish & Wildlife Service. No known
nesting site was identified within two miles of any pro-
posed hydroelectric site. Good potential exists for nest-
ing sites on bluffs and rocky outcrops in the vicinity of
several proposed hydroelectric sites and are discussed
with the appropriate communities. A biological recon-
naissance during the breeding season is recommended to
clarify each situation. If falcons are nesting within 2
miles of a construction project, certain restrictions would
be in effect from April 15 to August 31.
6.4.3 Archaeology
The potential hydroelectric sites and transmission line
routes for all the communities selected by the preliminary
screening were reviewed for known archeological and/or
historic sites. This work was conducted with the assist-
ance of the State Archaeologist and his staff, in the
Office of History and Archaeology, Alaska, Division of
Parks, Department of Natural Resources, Anchorage. No
previous archaeological survey work has been done in
the area encompassing the proposed hydroelectric sites
or transmission lines outside the boundaries of the com-
munities. This is not unusual, since only about 10% of
the state has been surveyed at a reconnaissance level.
Historic sites have been reported in the vicinity of a few
of the proposed hydroelectric sites. The historic Walla
Walla Roadhouse (1909) is reported to have been in the
vicinity of Walla Walla Creek, which is also proposed as
the site for the hydroelectric power for the community of
Elim.
-50 -
The proposed transmission line route between the Don
River and Brevig Mission may encounter a reported
former Eskimo village on the shore of Brevig Lagoon
approximately 3 to 4 miles west of the present commun-
ity. The proposed transmission line between Galena and
the Kala Creek hydroelectric site crosses the historic
Louden (Abau 1d) site and associated cemetery.
A reconnaissance level archaeologic survey would be re-
quired for all proposed hydroelectric sites and transmis-
sion routes prior to any ground disturbance. The
potential for archaeological and historic sites is rather
high in the vicinity of Anaktuvuk Pass, Manley Hot
Springs and Nome. In or proximal to the present com-
munities of Ambler and Wales are known prehistoric
sites. Most of the other present-day communities are
also historic sites.
6.5 DESIGN CONSIDERATIONS
The conceptual development plans presented in this study were
based on several design assumptio~ One important assumption
was that the hydroelectric plants would be operated as run-of-
the-river installations. Run-of-the-river operations were as-
sumed for two major reasons. One is that dam costs are so high
in Northwest Alaska that they far outweigh the benefits derived
from storage reservoirs. Secondly, adequate foundation for
large dams is difficult to find in this region of Alaska.
Another important assumption was that hydroelectric plants would
be operated during the thaw season only. This season was
assumed to be May through October. This assumption was made
for three major reasons. One is that none of the hydroelectric
sites identified could provide enough firm power to fully displace
all existing electrical generating plants. Thus, hydropower is at
-51 -
best a partial supplier of community electric needs. A second
reason for assuming thaw season operation is that winter flows in
the streams investigated are so low that their hydroelectric gen-
erating potential is very low compared to they typically high
winter electrical demands of the communities. The third and
probably most important reason is that the remote location of the
hydroelectric facilities and harsh winter weather would prevent
vigilant inspection and maintenance of the hydroelectric facilities
during the freeze season. The potential for penstock freezing
or frazil ice blockage would be quite high. Associated costs to
repair facilities damaged by freezing far outweigh the minimal
benefits derived from winter operation.
The scope of this study is necessarily limited to a reconnaissance
level investigation of hydroelectric project feasibility in North·
west Alaska. Therefore, conceptual plans which are presented
are not detailed, and should not be constructed without a great
deal of further design analysis.
The purpose of the following sections is to present some of the
constraints, parameters, and problems that should be considered
before a project is constructed. The section is divided into five
categories of design considerations: 6. 5. 1 Dam and Foundation;
6.5.2 Transmission Line; 6.5.3 Penstock; 6.5.4 Turbine and
Generator, and 6. 5. 5 Fisheries Considerations.
6.5.1 Dam and Foundation
Geotechnical considerations, particularly permafrost, are
perhaps the most important limiting constraint to con-
struction of hydroelectric projects in Northwest Alaska.
The following is a summary of Appendix C, Potential
Geotechnical Engineering Problems Associated with Con-
structing Small Head Hydropower Facilities in Northwest
Alaska.
-52 -
6.5.1.1 Permafrost
0
0
0
Permafrost underlies most of Northwest Alaska.
The fine-grained soils that are commonly found in
Northwest Alaska tend to be ice rich.
Generally, removal or disturbance of vegetation will
cause degradation of the permafrost to begin. Once
thaw occurs, possible local subsidence, flooding,
drainage diversion, and erosion problems may be
encountered.
6.5.1.2 Diversion Structures
0
0
0
0
0
Impounding water behind the diversion structure
may degrade any permafrost under the impound-
ment. Once started, the thermal erosion may con-
tinue forever.
The two most common types of diversion structure
are those constructed of either earth material or
concrete.
An earth fill structure may be designed to function
either in a permanently frozen or unfrozen state.
If the structure is designed to perform in an un-
frozen state, the foundation material should be
thaw-stable (thaw-stable soils are frozen soil or
rock that, on thawing, do not show loss of strength
below normal long-time thawed values or produce
detrimental settlement).
A frozen structure is advantageous since the frozen
core and permafrost form a single mass which is
stable. However, this configuration is thermally
-53 -
0
0
0
0
0
fragile and care must be exercised so that this
frozen mass wi II not thaw.
Several methods of freezing the core of an earth fill
dam are possible: (1) Layer by layer freezing of
the body of the core by material freezing during
the construction process; (2) Freezing of the core
of the structure on completion of its construction
but before completing the shell using artificial cool-
ing; (3) Freezing of the core by natural cooling
using ventilation ducts; and (4) A combination of
the above.
Within the project area the mean annual air temper-
ature is not low enough to maintain frozen cores
within the structures considered. Therefore, either
ventilation ducts or heat tubes would have to be in-
stalled within the structure to maintain the frozen
state.
The construction of concrete dams in Northwest
Alaska presents numerous difficulties due to the ex-
treme cold and remoteness of the sites. Concrete
structures require more stringent foundation re-
quirements than earth fill structures.
One problem associated with a thick concrete struc-
ture in the north is cracking due to tensile
stresses. The downstream face is exposed to large
temperature fluctuations. When a large temperature
difference is present between the two faces of the
dam considerable tensile stresses may be developed.
These stresses can produce horizontal cracks within
the structure.
Concrete is a good conductor of heat. During the
warmer summer months considerable heat will be
-54 -
0
0
conducted into the foundation soils. This may
cause degradation of the permafrost and eventual
differential settlement leading to large stress fields
developing with the structure.
If the permafrost is shallow, preconstruction thaw-
ing of the permafrost may be employed. This
method, while effective, is time-consuming and
costly.
Spillways must be designed to pass infrequent flood
flows. In Northwest Alaska, these flows are typi-
cally associated with spring breakup. The choice
of the spillway design flood requires careful hydro-
logic analysis.
6.5.1.3 Power House
Permafrost will most likely be encountered beneath the
powerhouse. To provide stability to the structure the
thermal regime of the permafrost must be maintained.
Heat that is generated within the structure must be re-
moved before it is conducted into the soil which will in
turn melt the frozen soil. A pile foundation is one mode
that wi II permit the heat to be removed before it enters
the ground. The type and size of the piles will depend
upon site specific conditions. The design of piles in
frozen soils should be accomplished by an experienced
Arctic engineer.
If piles are not employed, the structure will be in direct
contact with the ground surface. To prevent degrada-
tion of the permafrost an active heat extraction system
should be installed. This system may be an insulated
gravel pad with either vents or heat tubes installed in
the gravel pad beneath the insulation. If the structure
-55 -
will ·not be heated during the winter 1 vents or heat
pipes may not be required.
6. 5. 1 . 4 Construction
0
0
0
0
0
The vulnerable place in frozen earth dams is the
contact between the dam and the floodgate or spill-
way. Thermal erosion is very likely to start at
these contact points and progress to the frozen
core.
The local material that is to be used for the struc-
ture may be marginal in quality and high in ice
content. The high ice content may require that the
material be stockpiled for one summer to allow the
ice to melt out.
Compacting of frozen ice rich soils is very difficult
and the degree of compaction generally low. When
thawing occurs 1 settlements in the range of 10 to 20
percent or higher may occur.
The structure should be designed to withstand
large ice and water forces generated during spring
break-up. Spring break-ups in Northwest Alaska
are characterized by high water and large ice flows
which reach large dimensions. The upstream face
should be protected from scour by these flows and
spillway designed so that it won't be ripped apart.
Although most small Alaskan streams freeze to the
bottom during the winter 1 sub-surface flow may still
be present. If the structure is designed to operate
in a frozen configuration 1 this may cut off this flow
during the winter months. In turn 1 this may lead
to the formation of large deposits of aufeis upstream
of the structure.
-56 -
0
0
0
0
0
0
For sites that are located along the coast, the ef-
fects of salinity upon the permafrost should be con-
sidered in the design. These areas have farge
freezing point depressions resulting in unbonded
permafrost (unbonded permafrost is defined as
earth material that is below 32 degrees, but not
bonded by ice due to a freezing point depression).
It is common to find alternating layers of bonded
and unbonded permafrost in . a given soil profile.
Curing of concrete releases heat; this may induce
thawing of permafrost in areas of warm permafrost.
Structures built on frozen bedrock may not be
sound. The bedrock may contain ice lenses be-
tween the strata.
Most diversion structures will probably be located
on alluvium, i.e., sands/gravels. Although gener-
ally thaw stable, once thawed, the amount of seep-
age may not be tolerable.
Soils underlying structures should be non-frost
susceptible to reduce the amount of frost heave.
Frost heave can be detrimental to hydraulic struc-
tures by causing differential movement, cracking,
etc.
A possible approach to the foundation design of the
diversion structure and powerhouse may be to ex-
cavate the overburden material and place the struc-
ture on bedrock. It should be noted that excava-
tion of frozen gravels generally requires blasting
and heavy ripping and thus is very slow and ex-
pensive.
-57 -
0
0
0
0
Diversion of water during construction may be
necessary or possibly only winter construction may
be performed. Winter construction is slow and
quality control becomes very difficult. Numerous
shutdowns may be required due to extremely severe
weather conditions.
Sufficient freeboard will be necessary to prevent
overtopping of the structure during spring break-
up.
Care should be taken where the water flows down
the spillway and into the stream. This increased
flow may cause rapid degradation of the permafrost.
Structural concrete placed in late fall to early
spring has shown lower strength than anticipated or
specified. Temperature of the air adjacent to the
freshly poured concrete should be maintained at ap-
proximately 55 degrees. This will require that
thought be given to the construction of heated
enclosures. Provisions should be included in all
specifications to prevent thermal shock at the time
the enclosure is removed.
6.5.2 Transmission Line
The hydroelectric power plant often must be located
quite a distance from the community it is to serve. A
transmission line will be required to bring the power
from the plant to its point of utilization. The trans-
mission line cost is computed as part of the hydropower
project and the resulting cost of power is compared with
competing schemes.
-58 -
The design and consequent cost of the transmission line
becomes a very large factor in the economic feasibility of
most hydroelectric projects. Planning and design of a
transmission line is a complex problem. It involves si-
multaneous considerations of a multitude of factors.
6. 5.2.1 Right-of-Way and Route Selections
The first step is to select the right-of-way or route the
transmission line is to follow. The following principles
should be used as a guide in this selection process:
0
0
0
All other things being equal select the shortest
route possible.
Parallel highways as much as possible. This makes
the line accessible for both construction and main-
tenance.
Follow section lines and property lines to simplify
acquisition of right-of-way easements. Avoid par-
cels where right-of-ways are difficult or unobtain-
able.
0 Route in the directions of future loads as much as
is practical.
0
0
0
Avoid crossing hills, ridges, swamps and bottom
lands to minimize expense due to damage by light-
ning, storms, floods and other natural hazards.
Locate other utility systems and avoid interference
with them.
Select a route compatible with the environment that
does the least visual damage to the landscape.
-59 -
6.5.2.2 Design
The next step is to design the transmission line itself.
Different types of construction in Alaska include over-
head lines on wooden poles, or steel towers, under-
ground lines, and surface laid utilidors or more exotic
forms such ·as submarine cables or the 11 single-wire
ground return 11 transmission line that is presently being
experimentally demonstrated. Under most conditions and
if the distance is more than a mile the most economical
transmission line will be overhead. Underground lines
should be considered where there is potentially extreme
wind loading conditions or the environmental impact of an
above ground line is unacceptable.
Underground line must be installed in non-frost suscep-
tible soils or buried deep enough to be completely below
the seasonal frost penetration depth to be reliable.
Attention must be paid to the insulation properties of
underground cables at low temperatures. They must be
flexible at low temperatures to prevent cracking damage
to the insulation. Type EP ethylene propylene has been
well accepted as a low temperature insulation in perma-
frost areas. Underground construction is generally not
feasible for higher and longer lines.
The term 11 transmission 11 usually denotes the highest vol-
tage circuits on a given system. Outside of Alaska or in
large power consumption areas this would normally imply
voltages of 69 kV or greater. However, for the system
we are considering in rural areas with relatively small
loads the transmission line voltage selected will be lower
and related to the line length and load to be trans-
mitted. Some typical values are tabulated below.
-60 -
Approximate Length
of Line, miles
1 -3
3 -10
10 -15
15 -25
25 -50
50 -75
6.5.2.3 Frequency and phases
Preferred Voltages,
volts
480 ( 2,400
2,400, 4,160, 7,200
12,400
24,900
34,500
69,000
Almost all lines are constructed standards at three phase
and 60 Hz. Three phase transmission is more efficient
than single phase, two phase or direct current requiring
smaller conductors to transmit an equivalent amount of
load.
6.5.2.4 Conductor Size
The most commonly used conductor for transmission lines
is aluminum conductor, steel reinforced (ACSR). The
reason for its use is its low cost and high strength to
weight ratio as compared to other conductors.
The conductor must be selected to have adequate cur-
rent-carrying capacity and sufficient size and strength
to support itself. and any additional load due to ice,
sleet, and wind.
6.5.2.5 Insulators
After determination of line voltage and conductor size,
the insulator can be selected. There are two types of
insulator in general use, the pin type and the suspen-
sion type. Pin type insulators are generally used at the
-61 -
lower transmission line voltages (under 69 kV) which we
are considering.
6.5.2.6 Spacing and Arrangement of Conductors
The greater the span, the greater the spacing must be
to avoid conductors touching during high winds. For
example the minimum spacing for a 300 foot span may be
four feet whereas a 600 foot span will require six feet
spacing.
There are three conductor arrangements in common use.
These are triangle, vertical and horizontal.
6.5.2.7 Spans
The span is the distance between line supports. The
longer the span the fewer support structures will be re-
quired. However, the longer the span the stronger the
conductor must be to support itself. The increased cost
of the conductor must be balanced against the saving
due to a smaller number of supports to determine the
most economical span. In general spans for pole lines
range from 125 to 350 feet and average about 250 feet.
Spans for tower lines range from 450 to 800 feet and av-
erage about 700 feet.
6.5.2.8 Structures
In addition to the factors mentioned above, the National
Electric Safety Code recommends the minimum height at
which conductors shall be strung above ground. These
clearances are taken into consideration with sag calcula-
tions to determine the required structure heights.
-62 -
6.5.3
Construction of pole lines in permafrost areas requires
special case to prevent later maintenance problems due to
frost jacking. Precautions include wrapping the base of
the pole with plastic.
6.5.2.9 Summary
Selection of a transmission line is a complex problem of
balancing many design factors to arrive at the most eco-
nomical and practical design. This design includes:
0
0
0
voltage selection
span and conductor optimization
structure type selection
It is best accomplished by considering and carefully
weighing a variety of different methods and then narrow-
ing in on the optimum choice.
Penstock
The penstocks envisioned for the hydropower sites in
this analysis range in size from 10 to over 72 inches in
diameter and from 200 to 10,000 feet in length. Durable
plastic pipes may be a desirable choice for penstocks
less than 12 inches in diameter.
Before specifying plastic pipe the following factors must
be taken into account: effects of ultraviolet light, rigid-
ity, coefficient of thermal expansion, its service temper-
ature and surge pressure limits. Characteristics of var-
ious types of plastic pipes are listed in EPA's Cold Cli-
mate Utilities Delivery Design Manual.
Fiberglass reinforced plastic pipe may be desirable for
penstocks up to 36 inches in diameter. For low head
applications, reinforced concrete pipe should be con-
-63 -
sidered. However, in most applications in remote areas
it is probably not economical. For penstocks larger than
12 inches in diameter it may be advisable to use steel
pipe.
For economic considerations, the inside of the penstock
must be as smooth as possible. This will maximize the
head and power generation at the turbine or permit a
smaller diameter pipe to be used. For steel penstocks,
polyurethane vinyl coating on the inside of the penstock
may protect the steel and provide a smoother surface to
reduce head loss. Two coats of polyurethane vinyl may
be suitable corrosion protection on the outside of the
penstock.
Tar, tar enamel, tar epoxy, or asphalt exterior coatings
are not recommended as coatings because they become
brittle and crack at sub-zero temperatures.
Pressure regulators can be used to minimize pressure
surges in the penstock during sudden changes in flow.
This could be a separate by-pass valve linked to the
turbine's flow control valve. When the flow is reduced
suddenly the by-pass valve would open immediately and
then close slowly to keep the pressure rise at a mini-
mum. The pressure regulator valve or turbine valve can
be set to allow for a small flow in the penstock when the
turbine is not running for freeze protection. Pressure
regulating valves should be carefully designed to pre-
vent icing.
It has been assumed that the run-of-the-river hydro-
power operation envisioned by this study will occur only
during the ice-free season. Thermally insulated pipe
(such as Arctic pipe) may therefore not be required.
-64 -
Water should not be allowed in the penstock during the
freezing season. To drain the penstock, valves at the
inlets should be closed. Air inlet valves or pipes must
be provided downstream of the valve. This operation
must proceed slowly to prevent damaging surges and
vacuum pressures. A manually operated gate valve is
recommended at the penstock inlet. Butterfly valves,
although generally less expensive, are not recommended
because of their inherent potential for causing damaging
surges.
Open canals can be used to transport the water to the
penstock inlet. This enables the designer to minimize
the penstock length. This alternative to penstock rout-
ing from diversion to turbine might be feasible for
higher flow rate installations. However, freeze problems
in the canal and its diversion would have to be over-
come.
6. 5. 4 Turbine and Generator
Turbines used for hydroelectric generation can be clas-
sified in two basic categories -impulse turbines, and
reaction turbines. Impulse turbines utilize the power of
a high pressure jet of water striking the blades of a
water wheel. The most common impulse turbine is the
Pelton wheel. Reaction turbines derive their power from
the reaction of the moving mass of water moving through
the turbine as it changes direction within the unit. The
Francis turbine, a very common reaction turbine, is
often compared to an end-suction centrifugal pump run-
ning backwards. Other reaction turbines include the
Kaplan and propeller types.
-65 -
Selection of turbine type is based on the flow of water
and the head available. Impulse turbines are rarely
used if there is less than 50 feet head available. For
large flows and very low head (less than 30 ft.), either
Kaplan or propeller turbines would be used. Neither of
these types would be likely to be used for the sort of
applications considered in this report. For the remain-
ing conditions, Francis turbines are usually selected.
Generators may be either synchronous or induction type.
The speed of an induction generator is controlled by the
network into which it is feeding current; no governor is
required on the driving turbine, and it is very easy to
synchronize with the network. However, the induction
generator cannot operate on its own; it must feed into
an operating network and should be substantially smaller
than the minimum demand on the network it feeds. A
synchronous generator is used whenever the unit pro-
vides a large part of the system•s capacity or where it
must operate along. In order to provide power at the
proper voltage and frequency, the operating speed of a
synchronous generator must be carefully controlled.
A governor is a speed-sensitive device which controls
the speed of a turbine. The governor senses the speed
of the turbine and adjusts the flow of water to it in
order to maintain the proper speed. Without the gover-
nor, fluctuations in the electrical load would cause fluc-
tuations in the generator• s speed, and therefore, its
output.
For most of the sites investigated, the net head varied
between 30 feet and 100 feet and the design flow varied
between 5 cfs and 100 cfs. For these conditions, com-
plete assemblies consisting of a skid mounted Francis
-66 -
Turbine, coupled to a synchronous generator are readily
available. In most cases the proper governor and con-
trol panel can also be included as part of the package.
These units have the advantage of being easily trans-
ported and installed, and are generally more economical
than individual components purchased separately.
6. 5.5 Fisheries Considerations
Probably the most important environmental impact of any
of the hydropower projects presented is disturbance of
fisheries. The purpose of this section is to describe the
procedure the designer should follow to minimize this
impact. The following assumptions are made:
0
0
0
0
0
Some fisheries resource is known to exist in or de-
pend on the stream.
Hydropower plants will be non-consumptive, that is,
water will be returned to the same stream from
which it was taken.
Plants will be operated as run-of-river facilities,
avoiding problems frequently associated with peak-
ing plants.
Fish passage facilities will be provided (Alaska
high-pass ladder, etc.) for systems with anadro-
mous or migrating non-anadromous fish, such as
whitefish, including sheefish, Dolly Varden, Arctic
char, etc.
Alterations in streamflow and water quality will be
essentially limited to that portion of stream between
the diversion structure and pool and the penstock
discharge.
-67 -
6.5.5.1 I nstream flow ( dewatered reach):
0
0
0
0
Enough flow should be provided in the partially de-
watered reach to provide some 11 subsistence 11 habitat
for transient fishes, especially during peak migra-
tion periods. Some habitat for resident or season-
ally rearing fish is also desirable. 11 Creation 11 of
deep pools, etc. may be desirable to make up for
dewatered habitat.
Enough flow should be provided to allow passage,
both upstream and downstream, for adults and ju-
veniles. Requirements may vary seasonally de-
pending on migration timing of species present. A
very general rule of thumb is minimum depths of 4-
to 8-inches and continuous flow for juveniles of
most species (year-round for many species) and
10-inches to 2-feet for adults of most species (sea-
sonal for most species).
Enough flow should be provided to allow passage
over potential migration barriers. Requirements are
very generally 6 to 10 inches maximum jumps for
upstream movement of juveniles of most species.
Jumps passable at typical flows may become impas-
sable at lower flows for both juveniles and adults.
Maximum heights for adults vary greatly among
species. Passability is a function of height, flow,
and the presence of a plunge pool with a standing
wave. Anything over 4 feet is probably too high
for any species, regardless of other factors. Most
species have lower maximum height requirements.
Changing hydraulics in the partially dewatered
reach may result in a change in species preference
and a shift from one species mix to another. This
-68 -
is not necessarily bad and could tend to favor a
11 preferredu species. For example, a partially de-
watered reach may cease to support large popula-
tions of predator fish resulting in a more produc-
tive nursery habitat for a managed species.
6.5.5.2 Fish Screens and Other Intentional Barriers:
0
0
0
Intakes for diversion canals should generally be
screened. In cases where additional rearing habitat
can be provided in the canal, the screen can be
placed at the intake to the penstock. In both cases
a means for downstream movement of fish should be
provided, including an attraction flow (current) to
the downstream migration route near the screen.
Self-cleaning rotating screens placed obliquely to
the flow usually work well at a relatively low cost.
Attempt should be made to design the penstock
outlet so that it will not attract upstream migrants.
Provide a hydraulic barrier (slide) if possible to
avoid injury problems frequently associated with
screens. Upwelling outlets can also be very effec-
tive and result in less sacrifice of head. Locate
the outlet so that the alternate upstream route is
easy to find.
In some cases it may be most desirable to provide
only for downstream migration. Placement of man-
made barriers coupled with an upstream predator/
competitor eradication program can greatly increase
productivity of a target species in some cases,
either as part of an artificial seeding (stocking)
program or with the presence of a self-sustaining
adult population upstream. In these cases, up-
stream migration facilities are undesirable.
-69 -
6.5.5.3 Placement:
0
0
Avoid dewatering or blocking migration to 11 critical 11
habitat or limiting habitat, for example, the only
spawning grounds on the stream or the only good
feeding or nursery area on the stream.
Attempt to place the penstock outlet upstream of a
gravel recruitment source if important spawning
grounds are not far downstream. (Gravel recruit-
ment may be accomplished by flood flows through
the partially dewatered reach.) Steep tributary
streams may provide sufficient recruitment to
spawning grounds if sufficient periodic mainstream
flows exist to carry the gravel downstream. Gravel
catchment structures may be required downstream
to make up for reduced recruitment.
6. 5.5. 4 Mitigation/Enhancement:
0
0
The impoundment pool may work to 11 create 11 wetland
and marsh habitat upstream, especially if run-of-
river operation results in minimal pool fluctuations.
This amounts to a project benefit.
Be aware of mitigation/enhancement opportunities,
for example, laddering falls, thereby opening pre-
vious inaccessible upstream areas to both anadrom-
ous and non-anadromous fishes on the project
stream or a tributary or nearby stream. Be alert
for special cooperative management opportunities
made possible by the project, such as effective
predator/competitor control programs.
-70 -
6.6 COST ESTIMATES
For each of the conceptual hydroelectric development plans pre-
sented in Section 6. 7, a total project cost has been estimated.
These estimates are composed of four parts: (1) Major facility
items including diversions, canal and flume, penstock, turbine
and generator equipment, powerhouse, transmission line and win-
ter haul road; (2) mobilization, demobilization, and contractor's
profit; (3) geographic escalation; and (4) contingencies, plan-
ning and engineering.
Several assumptions form the basis for all the estimates:
0
0
0
The diversion dam will be constructed of concrete. Al-
though earth or rock fill may be less expensive to build
for some communities, this potential cost savings could
not be quantified without an identification of material
borrow areas and estimates of excavation, loading and
transportation costs. Such estimates are beyond the
scope of a reconnaissance study. The cost of importing
cement and reinforcing steel is included in the geogra-
phic escalation. Assuming no special geotechnical prob-
lems exist, concrete dam cost probably represents an
upper limit to the diversion structure cost.
No permanent access roads will be constructed. Costs
for building such roads to minimize environmental impact,
perma frost degradation, and frost heave would be quite
high. It was assumed that heavy equipment and mate-
rials will be transported to the construction site over
winter haul roads. The heavy equipment will be re-
turned over the winter haul road the following winter,
after completion of summer construction.
The winter haul road will parallel the transmission line
route. The transmission line will be constructed in win-
ter.
-71 -
0
0
0
6.6.1
The costs associated with equipment stand-by from one
winter to the next are included in the mobilization and
demobilization costs.
Construction workers and lighter materials and tools will
be transported to and from the construction sites during
the summer season by helicopter. The helicopter costs
are included in the mobilization and demobilization costs.
Interest costs during construction are included in mobil-
ization, demobilization and contractor's profit.
Unit Prices and Cost Basis
Unit prices for the cost estimates were based on the
references presented in Section 5.2. Some of the unit
prices presented in Section 5.2 were modified to take
into account information collected during the field recon-
naissance and developed during the conceptual designs.
The unit prices for each of the major facility items as
well as the basis for computing the other parts of the
total project cost are presented in Table 6.6.1.1.
6.6.1.1 Diversion Structure:
The diversion structure was assumed to be concrete.
Table 6.6.1.2 is a matrix giving estimated construction
costs of various sized concrete dams at Fairbanks,
Alaska base price. The following is a typical computa-
tion used to develop the matrix:
-72 -
Concrete Structure, 20 ft. high structure x 200 ft. long:
Substructure
Excavate 740 CY @ 8.40 $ 6,216
Concrete Foundation 740 CY @ 120.00 88,800
Reinforcement 56 tons @ 1100.00 61,600
Formwork 4000 SF @ 4.50 18,000
Subtotal $174,616
sueerstructure
Concrete Dam Wall 1111 CY @ 130.00 $144,430
Reinforcement 97 tons @ 1150.00 111,550
Formwork 8000 SF @ 6.00 48,000
Subtotal $303,980
TOTAL $478,596
Substructure:
Superstructure:
200 LF $174,616
4000 SF $303,980
= $873/LF
= $ 76/SF
-73 -
TABLE 6.6.1.1
UNIT COSTS AND BASIS FOR CONCEPTUAL PLAN
TOTAL PROJECT COST ESTIMATES
Part Item Description Cost Basis
II .
Ill.
IV.
Major Facility Items:
1 Diversion Structure See Section 6.6.1.1
2 Canal and Flume 50% of Cost in Fig. 5.2.2.1
3 Penstock 100% of Cost in Fig. 5.2.2.1
4 Turbine, Generator, Valves, $900/kW Installed Capacity
Switchgear
5 Powerhouse $120/Sq. Ft.
6 Transmission Line, Overhead $40, 000/Mi.
to 15 kV
7 Winter Haul Road $20,000/Mi.
8
9
10
11
Mobilization, Demobilization,
Contractor1 s Profit
Geographic Escalation
Contingencies
Planning and Engineering
30% of Total of Part I,
Items 1-7
From Table 5.2.1.1
20% of Total Construction
Cost
16% of Total Construction
Cost
NOTE: Items 1 -7 are at Fairbanks, Alaska November, 1980 base price.
-74 -
Dam
Height
( Ft)
so
40
30
20
10
1
0
4671300
3911300
3151300
2391300
1631300
871200
100
TABLE 6.6.1.2
DIVERSION DAM COST MATRIX
9341600 114011900 118691200
7821600 111731900 115651200
6301600 9451900 112691200
4781600 7171900 9571200
3261600 4891900 6531200
1741600 2611900 3491200
200 300 400
-75 -
2 1336 1500 Cost
1 1956 1 500 Cost
1 I 576 1500 Cost
1 1196 1500 Cost
816 1500 Cost
436 1 500 Cost
Dam
500 Length
(Ft.)
6.6.2 Design Capacity
The design capacity of the waterways, turbine and gen·
erator for a specific site was determined in two steps.
In the first step, the· mean value of the eighty percentile
stream flows for each month of the year was computed.
The computed flow represents the twenty percent ex-
ceedance flow, or, that flow which will be exceeded
twenty percent of the time.
Information in the U.S. Army Corps of Engineers 1
Feasibility Studies for Small Scale Hydropower Additions
indicates that turbines are normally designed for a flow
that will be exceeded between 15 percent and 30 percent
of the time, depending on the characteristics of the geo-
graphic region being studied. Several cursory economic
analyses were performed for sites in Northwest Alaska
during this study. It was concluded that the 20 percent
exceedance flow might be the optimum design flow.
However, choice of the 20 percent exceedance value is
an estimate of optimum conditions, and a much more de-
tailed site-specific analysis would be required to estab-
lish the actual optimum design value.
Using the 20 percent exceedance flow and the net head
at the site, the potential energy at the entrance to the
turbine was computed:
-..QI:L PE -11.8
Where: Q
H
PE
=
=
=
20 percent Exceedance Flow, CFS
Net Heat = Available heat -(Energy Losses
through Valves, Intake, Penstock, etc.), FT.
Potential Energy at Entrance to Turbine, kW
-76 -
As a first approximation, the installed capacity of the
installation was set at this computed potential energy
multiplied by an assumed turbine/generation efficiency of
0.85.
In the second step, the community's 1990 projected elec-
trical demand was compared to the design capacity on a
monthly basis. The 1990 peak demand was computed by:
p = 1990 MWh)
(Hrs)(LF
Where: 1990 MWh = Projected 1990 Demand, MWh
Hrs = Number of Hours in a Year = 8766 Hours
LF = Annual Load Factor = 0. 35
P = 1990 Peak Demand, MW
The monthly peak demand was computed using Figure
6.6.2-1. This figure shows the reduced electrical de-
mand in the summer typical of most Alaska communities.
In July, the peak demand is only half of the annual
peak.
The 1990 demand and the energy available from the tur-
bine sized in step one were compared for each of the
assumed 6 months of turbine operation, May through
October. If the installation was sized larger than neces-
sary to meet the 1990 monthly demands, the installed
capacity was reduced to the necessary size.
-77 -
100
80
60
}/.
~ 4110 ~ 0.. Ql
lL
0
"' w
FROM ~f.C:
D + TOGIAK (1978)
+ 0 KIANA (1'l76) • + ~ ELIH (i~78)
D a KALTAG l1976) + • 0
~ X S~Ut-JGI\IA~ (1976) D • • u od FROM NOME: D • NOME (JULY 119-
+ JUNE '50)
+Ax
06x
+
JAN. FE&. MAR. APR. MAY JUN. JUL. AUG. 5EP. OCT ~ DEC.
MONTH
FIGURE 6.G.Z-1
ANNUAL LOAD CURVE.
6.6.3 Quantity Takeoff
Generally, cost item quantities were estimated from avail-
able USGS quadrangle maps, usually at a scale of
1:63,630. The length of diversion dam was estimated
from abutment side slopes measured on the quad map.
Normally, a 10-foot dam height was assumed. In a few
cases, the length of dam necessary to achieve a 10-foot.
height was excessive (over 600 feet). In such cases,
the dam height was reduced to 5 feet.
Canal and flume lengths were measured along the eleva-
tion contour corresponding to the inlet elevation. Pen-
stock lengths were measured along a direct route to the
powerhouse.
The method for estimating the installed capacity of the
turbine-generator equipment has been previously de-
scribed in Section 6.6.2.
Powerhouse sizes were based on Table 6. 6.3. 1.
The length of transmission lines and winter haul roads
were measured from the USGS quad maps. It was as-
sumed winter haul roads would not be required where
winter trails, jeep trails, or developed roadways were
shown on the map as already existing.
-79 -
TABLE 6.6.3.1
POWERHOUSE COSTS
Turbine
Capacity Floor Dimensions
(kW) (Ft. x Ft.) (Ft.2 )
50 20 X 20 = 400
100 24 X 24 = 576
300 30 X 24 = 720
600 40 X 30 = 1,200
1000 45 X 30 = 1,350
-80 -
Allakaket
6. 7 CONCEPTUAL HYDROELECTRIC DEVELOPMENT PLAN OF EACH
COMMUNITY
6.7.1 Allakaket
6. 7. 1 . 1 Location:
Latitude: 66°341 N
Longitude: 152°38'W
6.7.1.2 Community Description:
Allakaket is a subsistence community on the Koyukuk
River downstream from Bettles. Housing built from
locally available timber is adequate. A high school and
PHS washeteria were recently completed there. There is
currently no central electric distribution, although the
school does provide excess power for freezers. The
community has a severe flooding problem which will
probably preclude the construction of a piped water and
sewer system or HUD housing. Subsistence rates vary
highly in priorities. Consequently, community develop-
ment with its attendant introduction o[ monthly bills is
not desirable.
6.7.1.3 Population (Year-round):
1980: 160
2000: 238
2030: 431
6.7.1.4 Economic Base:
Firefighting, fishing, and trapping are the major econo-
mic activities. Transfer payments also play a role.
-81 -
Retail sales are meager with shopping done in Bettles,
especially for fuel which is not sold in the village.
6. 7 .1.5 Existing Electric Power Equipment:
Utility: School and Village Council
Generators:
Capacity:
Diesel
School - 1 00 kW + 60 kW + 2x20 kW
= 200 kW
Peak Demand: 150 kW (est.)
6.7.1.6 Projected Electrical Demands:
1980: 1121 mWh/yr
1990: 1356 mWh/yr
2000: 1670 mWh/yr
2030: 3015 mWh/yr
6.7.1.7 Potential Growth Factors:
Based on the community preference to remain as is,
growth will be slow, if at all. Money was appropriated
in the 1980 Alaska Legistlature to install a lighting and
navigational aid system at the airport.
6.7.1.8 Land Use:
Regional Native Corporation
6.7.1.9 Hydropower Plans (Figure 6.7.1-1):
Two watersheds were identified within 4 miles of
Allakaket. The unnamed stream south of the village
appeared during the field reconnaissance to have better
-82 -
hydropower potential than the unnamed stream to the
northwest.
Plan One: Divert unnamed stream south of Allakaket
into a canal, then drop through penstock to powerhouse
near shore of Koyukuk River.
Plan Two: Divert unnamed stream northwest of village
into a canal, then drop through penstock. Run trans-
mission line through Alatna, and across Koyukuk River.
lntertie with Alatna.
Plan Three: Tap both watersheds, and tie in Alatna and
Allakaket.
-83 -
2.9
• .I : \ ...
·-.
'-!'> .IJ._., . .J • ~ ...
-"".7'-,·---.! .... --.... .r
,Q ' ·-· .... ,-/ • ·~'
F I G U R E 6. 7. I -I
Allakaket Hydro Sites
-84 -
Buildings in Allakaket
Koyokuk River-View Northward Toward Alatna
and Allakaket. Airport at Allakaket in Center
-85 -
Generator Building in Allakaket
Watershed Northeast of Alatna
-86 -
6. 7. 1 . 9. 1 Streamflow Information
Stream: Unnamed Stream South of Allakaket
Location of Dam: Lat. 66°31'N Long. 152°391W
Elevation of Dam Above MS L: 252
Net Head (ft.): 100
Drainage Area (sq. mi.): 9.4
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 0.7 0.9
Feb 0.4 0.6
Mar 0.3 0.5
Apr 0.5 0.9
May 30 40
Jun 25 35
Jul 7 9
Aug 15 20
Sep 10 20
Oct 4 6
Nov 2 2.5
Dec 0.8 1.5
Mean 8.0 11.4
-87 -
Cl)
t:
<(
3l
0
== ::.c
>-i
liJ z
liJ
...J
<(
i= z
~
0 a..
20
0~~~~~-LJ_LJ~~
MAR. I APR. I MAY .IUN. tiUL AUCI. SEP. I OCT. NOV. DEC.
80 TH PERCENTILE
eo TH PERCENTILE
MONTHS
FJGURE 6.7.1-2
CREEK SOUTH OF ALLAKAKET
-88 -
6. 7. 1 . 9. 2 Streamflow Information
Stream: Unnamed Stream Northwest of Allakaket
Location of Dam: Lat. 66°34'N
Elevation of Dam Above MSL: 500
Net Head (ft.): 70
Drainage Area (sq. mi.): 18.9
50 Percentile
Month Flow (CFS)
Jan 1. 0
Feb 0.8
Mar 0.6
Apr 1. 1
May 60
Jun 50
Jul 15
Aug 30
Sep 20
Oct 6
Nov 3
Dec 1. 5
Mean 15.8
-89 -
80 Percentile
Flow (CFS)
1. 2
1.0
0.9
1. 6
65
65
20
35
45
10
4
2.5
20.9
en
t: ~
0 ~ ::.c
> (!) a::
UJ z
UJ
..J
:!
t-z
~
~
200
100
80 TH PERCENTILE
!SO TH PERCENTILE
MONTHS
-90 -
FIGURE 6.7.1-3
UNNAMED CREEK
NORTHWEST §.r:9
Of ALATNA
6.7.1.9.3 Design Information
Description of Plan: Plan One -Creek South of
Allakaket to Allakaket ·
Reference Figures: 6.7.1-1, 6.7.1-2
Diversion Design Flow (CFS): 11.4
Quantity and Type of Turbines: 1-Francis Reaction
Installed Capacity ( kW): 82
Average Annual Hydroelectric Production (mWh): 286
Average Annual Plant Factor:
1990 Annual Demand (mWh):
0.40
1356
Environmental Constraints: Occasionally arctic char
present. Arctic grayling and whitefish present.
Potential for northern pike.
Cost:
Item Unit
1 10'x300' diversion L.S.
2 Canal and Flume ft.
3 Penstock ft.
4 Turbine, Gener-
ator, Valves,
Switchgear kW
5 24'x24' Power-
house sq. ft.
6 Transmission
Line mi.
7 Winter Haul Road mi.
8 Mobilization, Demobilization,
Contractor 1 s Profit @ 30%
Q!y
1
6000
2000
82
576
2.3
0.8
9 Geographic Index Factor, 0.95
Cost/Unit
489,900
29
58
900
120
40,000
20,000
Subtotal
Subtotal
Total Construction Cost
10 Contingencies @ 20%
11 Planning and Engineering @ 16%
TOTAL PROJECT COST
-91 -
Cost
($10002
489.9
174.0
116.0
73.8
69.1
92.0
16.0
1030.8
309.2
1340.0
1273.0
2613.0
522.6
418.1
3554.0
6. 7.1. 9. 4 Design Information
Description of Plan: Plan Two -Creek Northwest of
Allakaket to Alatna· and Allakaket
Reference Figures: 6.7.1-1, 6.7.1-3
Diversion Design Flow (CFS): 20.9
Quantity and Type of Turbines: 1-Francis Reaction
Installed Capacity (kW): 105
Average Annual Hydroelectric Production (mWh): 333
Average Annual Plant Factor: 0.36
1990 Annual Demand (mWh): 1493
Environmental Constraints: Occasionally arctic char
present. Arctic grayling and whitefish present.
Potential for northern pike.
Cost:
Item Unit
1 10'x250' diversion L.S.
2 Canal and Flume ft.
3 Penstock ft.
4 Turbine 1 Gener-
ator, Valves,
Switchgear kW
5 24'x24' Power-
house sq. ft.
6 Transmission
Line mi.
7 Winter Haul Road mi.
8 Mobilization, Demobilization,
Contractor's Profit @ 30%
Q!y
1
7700
1600
105
576
2.5
2.5
9 Geographic Index Factor, 0. 95
Cost/Unit
408,000
35
70
900
120
40,000
20,000
Subtotal
Subtotal
Total Construction Cost
10 Contingencies @ 20%
11 Planning and Engineering @ 16%
TOTAL PROJECT COST
-92 -
Cost
~$1000)
408.0
269.5
112.0
94.5
69.1
100.0
50.0
1103. 1
330.9
1434.0
1362.3
2796.3
559.3
447.4
3803
6. 7.1 . 9. 5 Design Information
Description of Plan: Plan Three -Creek South and
Creek Northwest to Alatna and Allakaket
Reference Figures: 6.7.1-1, 6.7.1-2, 6.7.1-3
Diversion Design Flow (CFS): Creek South-11.4
Creek Northwest-20.9
Quantity and Type of Turbines:
Creek South -1-Francis Reaction
Creek North -1-Francis Reaction
Installed Capacity (kW): Creek South -82
Creek Northwest -105
Average Annual Hydroelectric Production (mWh): 530
Average Annual Plant Factor: 0. 32
1990 Annual Demand (mWh): 1493
Environmental Constraints: Occasionally arctic char
present. Arctic grayling and whitefish present.
Potential for northern pike.
Cost:
Cost
Item Unit Q!y Cost/Unit ($1000)
1 Plan One L.S. 1 3554 3554
2 Plan Two L.S. 1 3803 3803
TOTAL PROJECT COST 7357
-~ -
Ambler
6. 7.2 Ambler
6. 7. 2. 1 Location:
Latitude: 67°05' N
Longitude: 157°521W
6.7.2.2 Community Description:
Ambler is an Eskimo village on the north bank of the
Kobuk River. It was settled in 1958 when residents of
Shungnak moved downstream to take advantage of migrat-
ing caribou. A school and post office were established
in the 1960 1 s. During the 1970 1 s a piped water and
sewer system, federally funded homes and a new high
school with gymnasium were constructed. T.V. and
individual telephones were installed in 1978. Three non-
native families not connected to the AVEC grid produce
their own electricity with a windmill. A community
freezer will be completed by January of 1981, which will
reduce overall electric consumption for food storage.
6.7.2.3 Population (Year-round):
1980: 250
2000: 372
2030: 673
6.7.2.4 Economic Base:
The economic base is subsistence and transfer payments.
A new runway was completed in 1977, making it the
longest year-round maintained facility in the upper
Kobuk Valley. An air taxi business operates from the
village doing a brisk wilderness tourist trade in summer.
-94 -
6.7.2.5 Existing Electric Power Equipment:
Utility:
Generators:
AVEC
Diesel
420 kW
77 kW
Capacity:
Peak Demand:
6.7.2.6 Projected Electrical Demands:
1980: 268 mWh/yr
1990: 445 mWh/yr
2000: 560 mWh/yr
2030: 1007 mWh/yr
6.7.2.7 Potential Growth Factors:
Twenty-five new HUD housing units are scheduled for
construction in 1981. This will expand the housing
stock by 50 percent. An upgrade of the existing water
and sewer system is also funded and expected to take
place in 1981. The airport will receive lights, naviga-
tional aids, a terminal building, and remote weather
reporting equipment.
NANA Regional Corporation has an active jade claim and
mine 10 miles from the village. Boulders are moved
whole to Kotzebue for cutting. Inexpensive electricity
could stimulate preliminary cutting at the village.
A large mineral belt runs through the Brooks Range
near Ambler. Several large mining exploration camps
have been established and should a transportation system
be built, Ambler would experience considerable growth.
-95 -
6.7.2.8 Land Use:
Regional Native Corporation
6.7.2.9 Hydropower Plan (Figure 6.7.2-1):
Diversion of the east fork of Jade Creek.
-96 -
1/2
FIGURE 6.7.2-1
Ambler Hydro Sites
-Q7 -
6 >rmation
Stream: East Fork Jade Creek
Location of Dam: Lat. 67°11'21 11 N Long. 158°06'0011 W
Elevation of Dam Above MSL: 850 ft.
Net Head (ft.): 350 ft.
Drainage Area: 4.3 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 0 .5 0.5
Feb 0.3 0.3
Mar 0.2 0.2
Apr 2.0 2.2
May 30
Jun 20 55
Jul 10 13
Aug 5 9
Sep 7 9
Oct 5 7
Nov 3 3.3
Dec 1 1.1
Mean 6.6 10.9
-98 -
6. 7. 2. 9. 2 Design Information
Description of Plan: East Fork Jade Creek to Ambler
Reference Figure: 6.7.2-1
Diversion Design Flow (CFS): 4.2
Quantity and Type of Turbines: 1-Turgo or Pelton
Impulse
Installed Capacity ( kW): 106
Average Annual Hydroelectric Production (mWh): 252
Average Annual Plant Factor: 0.27
1990 Annual Demand (mWh): 445
Environmental Constraints: Whitefish and arctic
grayling present. Known prehistoric site and
many house pits in vicinity.
Cost:
Item
1 10'x80' diversion
2 Canal and Flume
3 Penstock
4 Turbine, Gener-
ator, Valves,
Unit Q!Y
L.S. 1
ft. 4600
ft. 4700
Switchgear kW 106
5 24 1x44' Power-
house sq. ft. 576
6 Transmission
Line mi. 9
7 Winter Haul Road mi. 9
8 Mobilization, Demobilization,
Contractor's Profit @ 30%
9 Geographic Index Factor, 0.85
Cost/Unit
130,640
28
56
900
120
40,000
20/000
Subtotal
Subtotal
Total Construction Cost
10 Contingencies @ 20%
11 Planning and Engineering @ 16%
TOTAL PROJECT COST
-99 -
Cost
($1000)
130.6
128.8
263.2
95.4
69.1
360
180
1227.1
368.1
1595.2
1356.0
2951.2
590.2
472.2
4013.6
Anaktuvuk Pass
6. 7. 3 Anaktuvuk Pass
6. 7. 3. 1 Location:
Latitude: 68°08 1 N
Longitude: 151 °45'W
6. 7. 3. 2 Cammun ity Descri ptian:
Anaktuvuk Pass was a traditional inland Eskimo village
which was nearly abandoned in the late 19th Century.
People began to return when Noel Wien established ir-
regular air service there in the 1940's. In 1960 a school
was built and in the 1970's the newly-formed North Slape
Borough essentially rebuilt the entire village complete
with high school and 21 new homes. The PHS built a
washeteria but it has been extensively damaged an num-
erous occasions. All utilities are operated by the Bor-
ough. Anaktuvuk Pass is the only village in the study
area nat served by a navigable river.
6. 7.3.3 Papulation (Year-round):
1980: 173
2000: 257
2030: 466
6.7.3.4 Economic Base:
The village economy is Borough employment, subsistence
and transfer payments. Subsistence has been tenuous at
times because of changing caribou migration routes.
-100 -
6. 7 .3.5 Existing Electric Power Equipment:
Utility: North Slope Borough Light and Power
Generators: Diesel
500 kW
288 kW
Capacity:
Peak Demand:
6.7.3.6 Projected Electrical
1980: 1000 mWh/yr
1990: 1745 mWh/yr
2000: 2340 mWh/yr
2030: 7030 mWh/yr
Demands:
6. 7 .3. 7 Potential Growth Factors:
Growth other than normal population growth is unfore-
seen.
6. 7 .3.8 Land Use:
Regional Native Corporation
6.7.3.9 Hydropower Plan (Figure 6.7.3-1):
Diversion of lnukpasugruk Creek and transmission of
power to Anaktuvuk Pass.
-101 -
-102 -
FIGURE 6.7.3-1
Anaktuvuk Pass
Hydro Site
6. 7.3.9.1 Streamflow Information
Stream: lnukpasugruk Creek
Location of Dam: Lat. 68°02'2411 N; Long. 151°45'011 W
Elevation of Dam Above MSL: 2320 ft.
Net Head (ft.): 200 ft.
Drainage Area: 46.5 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 0 0
Feb 0 0
Mar 0 0
Apr 0 0
May 60 100
Jun 100 125
Jut 25 40
Aug 30 40
Sep 25 35
Oct 3 .5
Nov 0 0
Dec 0 0
Mean 20.3 28.8
-103 -
2000
1!500
400
300
200
SO TH PERCENTILE
~0 TH PERCENTILE
MONTHS
FIGURE
I NUKPASUGRUK
-104 -
NEAR
ANAKTUVUK
6.7.3-2
CREEK ~
OTT
PASS
6.7.3.9.1 Design Information
Description of Plan: lnukpasugruk Creek to
Anaktuvuk Pass
Reference Figures: 6.7.3-1, 6.7.3-2
Diversion Design Flow (CFS): 28.8
Quantity and Type of Turbines: 1 -Francis Reaction
Installed Capacity ( kW): 414
Average Annual Hydroelectric Production (mWh): 912
Average Annual Plant Factor: 0.25
1990 Annual Demand (mWh): 1745
Environmental Constraints: Whitefish and arctic
grayling present. High potential for archaeo-
logical and historic sites. The community and
hydro site are in close proximity to Gates of
the Arctic National Monument.
Cost:
Item
1 10'x200' diversion
2 Canal and Flume
3 Penstock
4 Turbine, Gener-
ator 1 Valves 1
Switchgear
5 30'x24' Powerhouse
6 Transmission
Line
7 Winter Haul Road
Unit Q!y
L.S. 1
ft. 4500
ft. 3700
kW 414
sq.ft. 720
mi. 1. 3
mi. 0
8 Mobilization, Demobilization,
Contractor's Profit @ 30%
9 Geographic Index Factor, 1.02
Cost/Unit
3261600
40
80
900
120
401000
20,000
Subtotal
Subtotal
Total Construction Cost
10 Contingencies @ 20%
11 Planning and Engineering @ 16%
TOTAL PROJECT COST
-105 -
Cost
($1000)
326.6
180.0
296.0
372.6
86.4
52.0
0
1313.6
394.1
1707.7
1741.9
3449.6
689.9
551.9
4691.4
Bettles
6.7.4 Bettles
6. 7. 4. 1 Location:
Latitude: 66°54'30 11 N
Longitude: 151 °41'30"W
6. 7.4.2 Community Description:
Bettles is actually two communities, Bettles Field, an
FAA installation, and Evansville, a native community of
65. The infrastructure in Bettles is either FAA or non-
native controlled. At present the village council is
attempting to form an Indian Reorganization Act Council
to gain control of the 1280 acres of land· surrounding the
community. This is being done to discourage indis-
criminate growth of the non-native community. There is
a high school in Bettles, but no water system. Private
wells are used.
6.7.4.3 Population (Year-round):
1980: 105
2000: 125
2030: 226
6.7.4.4 Economic Base:
The economy of Bettles is based on its 5200' runway.
With VOR instrument approach system and full use light-
ing, it is the best facility between Fairbanks and
Kotzebue. The field is strategically located in two ways:
it is close to mining exploration ramps in the Brooks
Ranges and to the newly-created Gates of the Arctic
National Park. Lodge facilities are in place and use is
-106 -
expanding. Retail trade is carried on with surrounding
villages, especially Allakaket, which buys its fuel in
Bettles.
6. 7 .4.5 Existing Electric Power Equipment:
Utility: Bettles Light and Power
Generators: Diesel
900 kW
225 kW
Capacity:
Peak Demand:
6.7.4.6
1980:
1990:
2000:
2030:
6.7.4.7
Projected Electrical Demands:
1010 mWh/yr
1212 mWh/yr
1515 mWh/yr
2727 mWh/yr
Potential Growth Factors:
Bettles with its large airstrip and FAA facility is a likely
staging area for any major development in the western
Brooks Range. In addition, it lies near any alignments
of major transportation development. Tourism in the
Gates of the Arctic is expanding at over 10 percent per
year and the National Park Service plans to establish a
headquarters complex in Bettles. If ownership of land
can be obtained, lodges will be established for both
summer and winter visitation.
The FAA facility staff will be reduced within 10 years,
due to changes in FAA equipment and policy.
-107 -
6.7.4.8 Land Use:
Regional Native Corporation
6.7.4.9 Hydropower Plan (Figure 6. 7. 4-1):
Diversion of Jane Creek and transmission of power to
Bettles
-108 -
30
~
• ~1.
...
--
.,
I
' \ \
\
I f _ _...•
~-
0 4"'".
/' j
' '
-· 31
22
34
i •,
·~ '
\
\ L ~/
4 ../
... ....__ " ' '
-, \"
'-J'\..·'V'\.--
23 \
L-, ''J
\
·-"..) ...,
' \'~--
0 1r
,_) 36
('
I I.
3
(
'·,
"
r (
f
------
19
... --·
I v~ ... -~-·-/ --_ _./ /
" \ ' -'-'
' 15 14 :
l
6
EVAN.SVILL..E
12 7
----
13
33
. ,-l6 8 '~ .. F. ~~+J ,,.-;.
·~·· ~.
;·Bettles
fOWflf 17
BETTLES ~ .i~ .,. (I 0.
D __.
35 ... . • -•'
1l2 I
0
-1 09 -
I
I Mil e
FIGURE
Bettles
a-: ... : .
~·· J .
~ .
6.7.4 -I
-
Hydro Site
20
29
32--
Old Bettles Village
Bettles Generator System
-110 -
Bettles-Mouth of Jane Creek, Koyukuk River in Foreground
Bettles-Jane Creek Watershed
-111 -
Bettles
6.7.4 Bettles
6. 7. 4. 1 Location:
Latitude: 66°54 1 30 11 N
Longitude: 151 °41 130 11 W
6.7.4.2 Community Description:
Bettles is actually two communities, Bettles Field, an
FAA installation, and Evansville, a native community of
65. The infrastructure in Bettles is either FAA or non-
native controlled. At present the village council is
attempting to form an Indian Reorganization Act Council
to gain control of the 1280 acres of land· surrounding the
community. This is being done to discourage indis-
criminate growth of the non-native community. There is
a high school in Bettles, but no water system. Private
wells are used.
6.7.4.3
1980:
2000:
2030:
6.7.4.4
Population (Year-round):
105
125
226
Economic Base:
The economy of Bettles is based on its 5200 1 runway.
With VOR instrument approach system and full use light-
ing, it is the best facility between Fairbanks and
Kotzebue. The field is strategically located in two ways:
it is close to mining exploration ramps in the Brooks
Ranges and to the newly-created Gates of the Arctic
National Park. Lodge facilities are in place and use is
-106 -
expanding. Retail trade is carried on with surrounding
villages, especially Allakaket, which buys its fuel in
Bettles.
6.7.4.5 Existing Electric Power Equipment:
Utility:
Generators:
Capacity:
Peak Demand:
Bettles Light and Power
Diesel
900 kW
225 kW
6.7.4.6 Projected Electrical Demands:
1980: 1010 mWh/yr
1990: 1212 mWh/yr
2000: 1515 mWh/yr
2030: 2727 mWh/yr
6. 7. 4. 7 Potential Growth Factors:
Bettles with its large airstrip and FAA facility is a likely
staging area for any major development in the western
Brooks Range. In addition 1 it lies near any alignments
of major transportation development. Tourism in the
Gates of the Arctic is expanding at over 10 percent per
year and the National Park Service plans to establish a
headquarters complex in Bettles. If ownership of land
can be obtained, lodges will be established for both
summer and winter visitation.
The FAA facility staff will be reduced within 10 years,
due to changes in FAA equipment and policy.
-107 -
6.7.4.8 Land Use:
Regional Native Corporation
6.7.4.9 Hydropower Plan (Figure 6.7.4-1):
Diversion of Jane Creek and transmission of power to
Bettles
-108 -
6.7.4.9.1 Streamflow Information
Stream: Jane Creek
Location of Dam: Lat. 66°55'1211 N; Long. 151°52'1211 W
Elevation of Dam Above MSL: 700 ft.
Net Head (ft.): 100 ft.
Drainage Area: 32.8 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jane 2 2.5
Feb 1.6 2.0
Mar 1 .2 1. 5
Apr 2.2 3.0
May 100 110
Jun 80 115
Jul 30 40
Aug 50 60
Sep 30 80
Oct 15 25
Nov 7 15
Dec 3 5
Mean 26.8 38.3
-112 -
1000
~ 400 c ... z
UJ b 300
a.
200
100
o~~~~~==~~L_~--~~--~~--~~ ~AN. ' FEB. I MAR. ' APil I MAY JUN. ' JUL. AUG. SEP. OCT. NOV. OEC.
MONTHS
80TH PERCENTILE
50 TH PERCENTILE
FIGURE 6.7.4-2
JANE CREEK OTT
NEAR BETTLES
~ 113 -
6.7.4.9.2 Design Information
Description of Plan: Jane Creek to Bettles
Reference Figures: 6.7.4-1, 6.7.4-2
Diversion Design Flow (CFS): 38.3
Quantity and Type of Turbines: 1 -Francis Reaction
Installed Capacity (kW): 276
Average Annual Hydroelectric Production (mWh): 608
Average Annual Plant Factor: 1. 25
1990 Annual Demand (mWh): 1212
Environmental Constraints: Occasionally arctic char
present. Whitefish and arctic grayling present.
Cost:
Item Unit
1 101 x160 1 diversion L.S.
2 Canal and Flume ft.
3 Penstock ft.
4 Turbine, Gener-
ator, Valves,
Switchgear kW
5 30 1x24 1 Power-
house sq. ft.
6 Transmission
Line mi.
7 Winter Haul Road mi.
8 Mobilization, Demobilization,
Contractor1 s Profit @ 30%
~
1
0
7700
276
720
4.3
5.8
9 Geographic Index Factor, 1.04
Cost/Unit
195,960
90
900
120
40,000
20,000
Subtotal
Subtotal
Total Construction Cost
10 Contingencies @ 20%
11 Planning and Engineering @ 16%
TOTAL PROJECT COST
-114 -
Cost
($1000)
196.0
0
693.0
248.4
86.4
172.0
116.0
1511.8
453.5
1965.3
2043.9
4009.2
801.8
641.5
5,452.5
Brevig Mission and Teller
6.7.5 Brevig Mission and Teller
6.7.5.1 Location:
Brevig Mission Teller
Latitude:
Longitude:
6.7.5.2 Community Description:
Brevig Mission was named for Tovig Brevig, a Lapp who
established a reindeer station there in the late 19th cen-
tury. Today the village still supports a reindeer herd.
Infrastructure is lacking with no electric power avail-
able. There is an elementary school and high school.
The watering point burned down and no sanitation facili-
ties exist. Eighteen HUD homes were built in the
1970's, but no more are planned in the near future.
Teller lies at the end of the Nome-Teller road and about
6~ miles southeast of Brevig Mission. Teller has a Post
Office, clinic, stores and a privately-run and well-main-
tained electric utility. Thirty of the homes "in" Teller
are actually 3 miles from the village proper and the air-
port is yet another ~~ miles in another direction. Estab-
lishment of an inexpensive hydroelectric source near
Brevig Mission and Teller could supply the whole area
via interconnection.
-115 -
6.7.5.6 Projected Electrical Demands:
Brevig Mission Teller
1980: 400 mWh/yr 441 mWh/yr
1990: 480 mWh/yr 529 mWh/yr
2000: 600 mWh/yr 661 mWh/yr
2030: 1080 mWh/yr 1190 mWh/yr
6.7.5.7 Potential Growth Factors:
Should a mine be established, the feasibility of which
would be enhanced by a power source, the economy of
Brevig Mission and Teller would increase sharply.
6.7.5.8 Land Use:
Regional Native Corporation
6. 7.5. 9 Hydropower Plan (Figure 6. 7. 5-1):
Plan One -Diversion dam at Don River, transmission
of power to Brevig Mission and Teller
Plan Two -Diversion dam on right fork of Bluestone
River, transmission of power to Brevig
Mission and Teller
Plan Three -Diversion dam on main stem of Bluestone
River, below Nome-Teller Road, and trans-
mission of power to Brevig Mission and
Teller
-117 -
. .
DON RtVER ,. OJ ~ G'~ ' I v
~_j
•570
<... ...-,
( • ·.j
600
M1SSI·ON
! ..
Pt Spencer
r 2 s
j
3 Cape
I
I
~-I
T 4 /
• • • • • • • WATERSHED BN~Y.
""" DAM -
• • • • • •" • • FLUME S CANAL
PENSTOCK
- - - -TRANSMISS ION ItN
POWERHOUSE
===== ACCESS :-AD
Jones Pt
• .,J!!:
s ,.-·
RIGHT FORK
I
0
-118 -
•. . ... AlDER
I
6 Mil es
FIGURE 6.7.5-1
Brevig Mission
Hydro Sites
'
-
•
Don River Near Brevig Mission
Brevig Mission
-119 -
Main Street in· Teller
Teller
-120 -
Upper and Lower Proposed Diversion· Dam Sites
on Bluestone River Near Nome
-121 -
6. 7. 5. 9. 1 Streamflow Information
Stream: Don River
Location of Dam: . Lat. 65°31 1 N; Long. 166°481W
Elevation of Dam Above MSL: 200 ft.
Net Head (ft. ) : 30 ft .
Drainage Area: 49.8 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 0.2 1.5
Feb 0.0 0.5
Mar 0.0 0.3
Apr 0.0 0.6
May 70 120
Jun 200 300
Jul 40 70
Aug 25 45
Sep 30 90
Oct 15 25
Nov 4 8
Dec 1 2
Mean 32.0 55.2
-122 -
~ a:: w z w
1000
200.
100
0
' JAN. FEB. I MAR. ' APR. I MAY l JUN. JUL. AUG. SEP. OCT. I NOV. I DEC.
MONTHS
80 TH PERCENTILE
50 TH PERCENTILE
FIGURE 6.7.5-2
DON RIVER §:E
NEAR BREVIG MISSION
-123 -
6. 7. 5. 9. 2 Streamflow Information
Stream: Right Fork Bluestone River
Location of Dam: Lat. 65°061 N; Long. 166°15 1W
Elevation of Dam Above MSL: 300· ft.
Net Head (ft.): 100 ft.
Drainage Area: 28.9 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 0.5 1.5
Feb 0.2 0.3
Mar 0.0 0.2
Apr 0.0 0.3
May 50 100
Jun 125 160
Jul 30 60
Aug 40 80
Sep 60 120
Oct 20 30
Nov 5 7
Dec 1. 5 2.5
Mean 27.7 46.8
-124 -
1500
en
1-t«
3t g 1000
::.:
>-~
I&J z
l&J
...J
<(
1-z 500 l&J
1-2 409
X>O
200
100
O~J•A•N.~'--FE~B-.~.-M-AR~-A-PR~L_~--L,-J-U~-l-J-U-L.j__AU-8-.L-S-~-.l-0-~-.J:~N~=.~~D~~~.
MONTHS
80 TH. PERCENTILE
50 TH. PERCENTILE
. FIGURE 6.7.5-3
RIGHT FORK BLUESTONE RIVER §T~
NEAR BREVIG MISSION AND TELLER ,,_
-125 -
6. 7. 5. 9. 3 Streamflow Information
Stream: Main Stem Bluestone River
Location of Dam: Lat. 65°06'N; Long. 166°15'W
Elevation of Dam Above MSL: 200 ft.
Net Head (ft.): 100 ft.
Drainage Area: 77.4 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 1.3 4.0
Feb 0.5 1.3
Mar 0.1 0.3
Apr 0.2 0.6
May 130 260
Jun 330 430
Jul 80 160
Aug 110 210
Sep 160 320
Oct 50 80
Nov 15 20
Dec 4 6
Mean 73.4 124.4
-126 -
.·
(I)
1-
~
..J
::.:
b a:
UJ z
UJ
3000
2SOO
2000
1000
500
.JAN. FEB. MAR. APR. MAY .JUN. .JUL. ' AUG. SEP. I OCT. I NOV. DEC.
MONTH~
80 TH. PERCENTILE
50 TH. PERCENTILE FIGURE 6.7.5-4
BLUESTONE RIVER NEAR ~
BREVIG MISSION AND TELLER
-127 ~
6. 7.5.9.4 Design Information
Description of Plan: Plan One -Don River to Brevig
Mission and Teller
Reference Figures: 6.7.5-1, 6.7.5-2
Diversion Design Flow (CFS): 55.2
Quantity and Type of Turbines: 1 -Francis Reaction
Installed Capacity (kW): 119
Average Annual Hydroelectric Production (mWh): 287
Average Annual Plant Factor: 0.28
1990 Annual Demand (mWh): 1009
Environmental Constraints: Whitefish and arctic
grayling present. Historic Eskimo villlage at
Brevig Lagoon.
Cost:
Cost
Item Unit ~ Cost/Unit ($1000)
1 10'x200' diversion L.S.
2 Canal and Flume ft.
3 Penstock ft.
. 4 Turbine, Gener-
ator, Valves,
Switchgear kW
5 24'x24' Powerhouse sq. ft.
6 Transmission
Line mi.
7 Winter Haul Road mi.
8 Mobilization, Demobilization,
Contractor's Profit @ 30%
1
0
10400
119
576
24
14
9 Geographic Index Factor, 0.83
326,600
112
900
120
40,000
20,000
Subtotal
Subtotal
Total Construction Cost
10 Contingencies @ 20%
11 Planning and Engineering @ 16%
TOTAL PROJECT COST
-128 -
326.6
0
1164.8
107.1
69.1
960
280
2907.6
872.3
3779.9
3137.3
6917.2
1383.4
1106.8
9407.4
6.7.5.9.5 Design Information
Description of Plan: Plan Two -Right Fork Blue-
stone River to Brevig Mission and Teller
Reference Figures: 6.7.5-1 1 6.7.5-3
Diversion Design Flow ( CFS): 33.3
Quantity and Type of Turbines: 1 -Francis Reaction
Installed Capacity (kW): 240
Average Annual Hydroelectric Production (mWh): 565
Average Annual Plant Factor:
1990 Annual Demand (mWh):
0.27
1009
Environmental Constraints: Whitefish and arctic
grayling present. Salmon occasionally present.
Cost:
Item Unit
1 10'x100' diversion L.S.
2 Canal and Flume ft.
3 Penstock ft.
4 Turbine, Gener-
ator 1 Valves.,
Switchgear kW
5 30'x24' Power-
house sq. ft.
6 Transmission
Line mi.
7 Winter Haul Road mi.
8 Mobilization 1 Demobilization 1
Contractor's Profit @ 30%
Q.ti.
1
12500
200
240
720
11
0
9 Geographic Index Factor, 0.83
Cost/Unit
163,300
43
86
900
120
40,000
201000
Subtotal
Subtotal
Total Construction Cost
10 Contingencies @ 20%
11 Planning and Engineering @ 16%
TOTAL PROJECT COST
-129 -
Cost
($1000)
163.3
537.5
17.2
216.0
86.4
440
0
1460.4
438.1
1898.5
1575.8
3474.3
694.9
555.9
4725.1
6. 7. 5. 9. 6 Design Information
Description of Plan: Plan Three -Main Stem Blue-
Stone River to Brevig Mission and Teller
Reference Figures: 6. 7 .5-1, 6. 7.5-4
Diversion Design Flow (CFS): 38.3
Quantity and Type of Turbines: 1 -Francis Reaction
Installed Capacity ( kW): 276
Average Annual Hydroelectric Production (mWh): 581
Average Annual Plant Factor: 0. 24
1990 Annual Demand (mWh): 1009
Environmental Constraints: Whitefish and arctic
grayling present. Salmon occasionally present.
Cost:
Item
1 10 1x80 1 diversion
2 Canal and Flume
3 Penstock
4 Turbine, Gener-
ator, Valves,
Switchgear
5 30 1x24' Power-
house
6 Transmission
Line
7 Winter Haul Road
Unit
L.S.
ft.
ft.
kW
sq. ft.
mi.
mi.
8 Mobilization, Demobilization,
Contractor•s Profit @ 30%
.Q!i
1
0
9300
276
720
11
3
9 Geographic Index Factor, 0.83
Cost/Unit
130,640
88
900
120
40,000
20,000
Subtotal
Subtotal
Total Construction Cost
10 Contingencies @ 20%
11 Planning and Engineering @ 16%
TOTAL PROJECT COST
-130 -
Cost
($1000)
130.6
0
818.4
248.4
86.4
440
60
1783.8
535.1
2318.9
1924.7
4243.6
848.7
678.9
5771.2
Buckland
6. 7.6 Buckland
6. 7. 6. 1 Location :
Latitude: 65°59'N
Longitude: 161 °08'W
6. 7 .6.2 Community Description:
Buckland grew up as a reindeer herding town. Several
herds, including the Gray's and the Hadley's, survived
the fall of the 30's up until recently when NANA Region-
al Corporation consolidated the ranges and herds.
Buckland today has a high school and several community
buildings. Housing is poor compared to other villages in
the area. Expansion of the community is constrained by
poorly-drained land and the close proximity of its short
runway. The Buckland River experiences an ice jam
downstream from the village nearly every spring, caus-
ing extensive flooding and evacuation of the village. No
sanitation facilities have been built in Buckland and are
not likely to be built until the village is moved or break-
up flooding can be eliminated.
The electric utility is operated by the City and has an
extremely poor reliability record.
author counted 12 dysfunctional
behind the village utility building.
At one time this
generators stacked
Conditions have im-
proved with the donation by the State of two new diesel
units in the spring of 1980. It remains to be seen
whether they will be maintained or if enough fuel storage
is present to keep them running. In the past a flat
charge was levied per household. The ensuing competi-
tion to see who could use the most was instrumental in
-131 -
the failures of the previous generators. Meters have
now been installed, but the sophistication to manage a
rate system is probably not present.
6.7.6.3 Population (Year-round):
1980: 174
2000: 259
2030: 468
6.7.6.4 Economic Base:
Buckland's economy is reindeer and subsistence. Four
full-time year-round jobs with NANA's herd make Buck-
land better off economically than most NANA villages.
6. 7 .6.5 Existing Electric Power Equipment:
Utility: Indian Reorganization Act Council
(IRA), School
Generators:
Capacity:
Diesel
IRA -1x75 kW + 1x125 kW = 200 kW
School -1x60 kW + 1x100 kW = 160 kW
Peak Demand: IRA -100 kW
6.7.6.6
1980:
1990:
2000:
2030:
6.7.6.7
Projected Electrical Demands:
350 mWh/yr
988 mWh/yr
1235 mWh/yr
2223 mWh/yr
Potential Growth Factors:
NANA has plans to expand the present herd from 8,000
head to 30,000. This will create many new jobs, but not
necessa ri I y new homes.
-132 -
Money was appropriated in 1980 to build a 3,000-foot
runway at Buckland. If it is located away from the
village, hew housing could be built on the old runway.
At present there are plans for 10 new HUD units in
1982.
6.7.6.8 Land Use:
Regional Native Corporation
6.7.6.9 Hydropower Plan (Figure 6.7.6-1):
Diversion dam on Hunter Creek, transmission of power to
Buckland
-133 -
·-
'·
,,
-.....
;-/---.
. /
~, I
/
~~/
->'d . .,. \
%.
/
I HUNTER CREEK
1-...-...
8
-134 -
..
} \ u .
I
SMiles
FIGURE 6.7.6-1
I
I • I
r
Buckland Hydro Site
Village of Buckland
Hunter Creek at Buckland
-135 -
Diesel Generator Plant at Buckland
New High School . at Buckland
-136 -
6. 7. 6. 9. 1 Streamflow Information
Stream: Hunter Creek
Location of Dam: Lat. 65°45 1 N; Long. 161°31 1W
Elevation of Dam Above MSL: 400 ft.
Net Head (ft.): 200 ft.
Drainage Area: 70.1 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 1. 0 3.0
Feb 0.4 0.7
Mar 0.0 0.4
Apr 0.0 0.8
May 80 180
Jun 150 250
Jut 25 40
Aug 20 40
Sep 15 45
Oct 15 20
Nov 7 12
Dec 3 5
Mean 26.4 49.3
-137 -
(/)
1-
~
0
...J
3!500
3000
2500
::c:
-2000
~ ex:
UJ z
UJ
<i 1500
1-z
UJ
1-
0 a.
1000
500
400
300
200L~...li---LL~~ 100
0
JAN. l FEB. ' MAR. ' APR. MAY l JUN. I JUL. I AUG. SEP. ' OCT. ' NOV. DEC.
80 TH. PERCENTILE
50TH. PERCENTILE
MONTHS
• 138 •
HUNTER CREEK
NEAR BUCKLAND
6.7.6.9.2 Design Information
Description of Plan: Hunter Creek to Buckland
Reference Figures: 6.7.6-1 1 6.7.6-2
Diversion Design Flow (CFS): 16.5
Quantity and Type of Turbines: 1 -Francis Reaction
Installed Capacity (kW): 238
Average Annual Hydroelectric Production (mWh): 556
Average Annual Plant Factor: 0.27
1990 Annual Demand (mWh): 998
Environmental Constraints: Whitefish and arctic
grayling present.
Cost:
Item Unit Q!Y
L.S. 1 1 101 x601 diversion
2 Canal and Flume
3 Penstock
ft. 43000
ft. 4000
4 Turbine, Gener-
ator 1 Valves,
Switchgear kW 238
5 301x241 Power-
house sq. ft. 720
6 Transmission
Line mi. 23.5
7 Winter Haul Road mi. 25
8 Mobilization, Demobilization,
Contractor•s Profit @ 30%
9 Geog rap hie Index Factor 1 1 . 03
Cost/Unit
971960
32
65
900
120
40,000
201000
Subtotal
Subtotal
Total Construction Cost
10 Contingencies @ 20%
Cost
($1000)
98.0
1376
260
214.2
86.4
940
500
3474.6
1042.4
4517.0
4652.5
9169.5
1833.9
11 Planning and Engineering @ 16% 1467.1
TOTAL PROJECT COST 12,470.5
-139 -
Elim
6.7.7 Elim
6. 7. 7. 1 Location:
Latitude: 64°38'N
Longitude: 162°151W
6.7.7.2 Community Description:
Elim lies east of Golovin on Norton Bay. With the com-
pletion of construction in progress in 1980, the village
will nearly double its building stock of 47 units with 35
additional HUD homes. At the same time, a new high
school and water and sewer system are being built. The
village has phones, AVEC power and is served by the
North Star Ill .
6.7.7.3 Population (Year-round):
1980: 196
2000: 291
2030: 528
6.7.7.4 Economic Base:
Elim's economy is commercial fishing and subsistence.
The fishery has an annual average value of $300,000
with gill and gut operations, providing employment for
40 workers in summer. No cold storage facility is now
in place, but could become feasible with successful
herring development.
-140 -
6. 7. 7. 5 Existing Electric Power Equipment:
Utility: AVEC
Generators: Diesel
285 kW
60 kW
Capacity:
Peak Demand:
6.7.7.6 Projected Electrical Demands:
1980: 228 mWh/yr
1990: 769 mWh/yr
2000: 962 mWh/yr
2030: 1731 mWh/yr
6.7.7.7 Potential Growth Factors:
The expansion of housing 1 the existence of good utili-
ties 1 and summer fishing jobs may draw new residents to
Elim. The village has considerable timber resources and
a small sawmill which could facilitate further housing ex-
pansion.
6.7.7.8 land Use:
Reservation
6. 7. 7. 9 Hydropower Plan (Figure 6. 7. 7-1):
Plan One -Diversion dam on the creek at Elim and
Plan Two
connection to Elim power distribution sys-
tem
-Diversion dam on Quiktalik Creek and
transmission of power to Elim
Plan Three -Diversion dams on the creek at Elim and
Quiktalik Creek, and intertie both trans-
mission lines to supply power to Elim
-141 -
Plan Four -Tap Quiktalik Creek, the creek at Elim,
and Peterson Creek, and transmit power
to Elim
-142 -
,f I
{ I
I
J
(11
l
I
'/: f!i! , I (Ia, ... :j'l . • ~~
~
\ . ~__... -----
..-;:::.
~
\\ ~ I,
~ ''{ . / .
•
•
• QUIKTALIIK • .........
..
• •·
•
•
...
+
I •
~ •. • . •
...--
.. )I
..
•
I l ~____....,__ :;--· ........ _ ..... . .,
• • • (I ~.
• l
•?/ ,/
3)1
+
... .... ' . /::::'\ .
I
l
.• ...... _ .........
.. • • • J . . · .• '\ ..-' ;~)'
/
-~I
. ./
I /
/
INORTH
I
0
-143 -
. I'
t'/
I
I Mile
FIGURE 6.7.7-1
E lim Hydro Sites
•
..
• ..... .
\~~ \~~--
\ . .
6. 7. 7. 9. 1 Streamflow Information
Stream: Creek at Elim
Location of Dam: Lat. 64°38'N; Long. 162°16'W
Elevation of Dam Above MSL: 70 ft.
Net Head (ft.): 40 ft.
Drainage Area: 2.54 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 1 . 1 1. 3
Feb 0.9 1 . 1
Mar 0.9 1 . 1
Apr 1 . 1 1.3
May 13 20
Jun 22 29
Jul 11 14
Aug 7 8
Sep 11 20
Oct 10 16
Nov 2 2.5
Dec 1. 6 1. 8
Mean 6.8 9.7
-144 -
6. 7. 7. 9. 2 Streamflow Information
Stream: Quiktalik Creek
Location of Dam: Lat. 64°36'N; Long. 162°21'W
Elevation of Dam Above MSL: 100 ft.
Net Head (ft.): 80 ft.
Drainage Area: 6.0 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 2.6 3.2
Feb 2.1 2.6
Mar 2.1 2.6
Apr 2.6 3.2
May 32 47
Jun 53 68
Jul 26 34
Aug 16 18
Sep 26 47
Oct 24 37
Nov 5 5.8
Dec 3.7 4.2
Mean 16.3 22.7
-145 -
6. 7. 7. 9. 3 Streamflow Information
Stream: Peterson Creek
Location of Dam: Lat. 64°35'N; Long. 162°24'W
Elevation of Dam Above MSL: 250 ft.
Net Head (ft.): 200 ft.
Drainage Area: 1.14 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 0.5 0.6
Feb 0.4 0.5
Mar 0.4 0.5
Apr 0.5 0.6
May 6.0 9.0
Jun 10.0 13.0
Jul 5.0 6.5
Aug 3.0 3.5
Sep 5.0 9.0
Oct 4.5 7.0
Nov 1.0 1.1
Dec 0.7 0.8
Mean 3.1 4.1
-146 -
(I)
t:
~
0 ...J
~
>-(!) a:
UJ z
14.1
...J 200
<(
.... z
14.1 ....
0
Q.
100
MONTHS
80 TH PERCENTILE
50 TH PERCENTILE
-147 -
FIGURE 6.7.7-2
PETERSON CREEK OTT
NEAR ELIM
•'
6. 7. 7. 9. 4 Design Information
Description of Plan: Plan One -Creek at Elim
Reference Figures: 6.7.7-1
Diversion Design Flow (CFS): 9. 7
Quantity and Type of Turbines: 1 -Francis Reaction
Installed Capacity ( kW): 28
Average Annual Hydroelectric Production (mWh): 118
Average Annual Plant Factor: 0.48
1990 Annual Demand (mWh): 769
Environmental Constraints: Salmon, whitefish, and
arctic grayling present.
Cost:
Item Unit
1 10 1 x380 1 diversion L.S.
2 Canal and Flume ft.
3 Penstock ft.
4 Turbine, Gener-
ator, Valves,
Switchgear kW
5 20 1 x20 1 Power-
house sq. ft.
6 Transmission
Line mi.
7 Winter Haul Road mi.
8 Mobilization, Demobilization,
Contractor•s Profit @ 30%
Q!Y.
1
0
2800
28
400
0
0
9 Geographic Index Factor, 0.83
Cost/Unit
620,540
56
900
120
40,000
20,000
Subtotal
Subtotal
Total Construction Cost
10 Contingencies @ 20%
11 Planning and Engineering @ 16%
TOTAL PROJECT COST
-148 -
Cost
($1000)
620.5
0
156.8
25.2
0
0
0
850.5
255.2
1105.7
917.7
2023.4
404.7
323.7
2751.8
6. 7. 7. 9.5 Design Information
Description of Plan: Plan Two -Quiktalik Creek to
Elim
Reference Figures: 6.7.7-1
Diversion Design Flow ( C FS): 22.7
Quantity and Type of Turbines: 1 -Francis Reaction
Installed Capacity ( kW): 131
Average Annual Hydroelectric Production (mWh): 374
Average Annual Plant Factor:
1990 Annual Demand (mWh):
0.33
769
Environmental Constraints: Salmon, whitefish and
arctic grayling present.
Cost:
Cost
Item Unit Q!y Cost/Unit ($1000)
1 101x200 1 diversion L.S.
2 Canal and Flume ft.
3 Penstock ft.
4 Turbine, Gener-
ator, Valves,
Switchgear kW
5 24 1x24 1 Power-
house sq. ft.
6 Transmission
Line mi.
7 Winter Haul Road mi.
8 Mobilization, Demobilization,
Contractor's Profit @ 30%
1
0
6000
131
576
1. 5
1. 1
9 Geographic Index Factor, 0.83
326,600
72
900
120
40,000
20,000
Subtotal
Subtotal
Total Construction Cost
10 Contingencies @ 20%
11 Planning and Engineering @ 16%
TOTAL PROJECT COST
-149 -
326.6
0
432
117.9
69.1
60
22
1027.6
308.3
1335.9
1108.8
2444.7
488.9
391.2
3324.8
6.7.7.9.6 Design Information
Description of Plan: Plan Three -Quiktalik Creek
and Creek at Elim to Elim
Reference Figures: 6.7.1-1
Diversion Design Flow ( CFS): Quiktalik Creek -22.7
Creek at Elim -9. 7
Quantity and Type of Turbines:
Quiktalik Creek -1-Francis Reaction
Creek at Elim -1-Francis Reaction
Installed Capacity (kW): Quiktalik Creek -131
Creek at Elim -28; Total -159
Average Annual Hydroelectric Production (mWh): 411
Average Annual Plant Factor: 0.30
1990 Annual Demand (mWh): 769
Environmental Constraints: Salmon, whitefish and
arctic grayling are present.
Cost:
Cost
Item Unit ~ Cost/Unit ($1000)
1 Plan One
2 Plan Two
-150 -
L.S.
L.S.
1
1
TOTAL PROJECT COST
2751.8
2796.4
5548.2
6.7.7.9.7 Design Information
Description of Plan: Plan Four -Quiktalik Creek,
Creek at Elim, and Peterson Creek to Elim
Reference Figures: 6.7.7-1, 6.7.7-2
Diversion Design Flow (CFS): Quiktalik Creek -21.6;
Creek at Elim -9.2; Peterson Creek -3.9
Quantity and Type of Turbines:
Quiktalik Creek -1-Francis Reaction
Creek at Elim -1-Francis Reaction
Peterson Creek -1-Turgo Impulse
Installed Capacity (kW): Quiktalik Creek -125;
Creek at Elim -26; Peterson Creek -60;
Total -211
Average Annual Hydroelectric Production (mWh): 444
Average Annual Plant Factor:
1990 Annual Demand (mWh):
0.25
769
Environmental Constraints: Salmon, whitefish and
arctic grayling are present. Walla Walla Road-
house historic site in vicinity.
Cost:
Cost
Item Unit Q!y Cost/Unit ($1000)
1 10'x200' diversion L.S. 1 326,600 326.6
10'x380' diversion L.S. 1 620,540 620.5
10 1 x100' diversion L.S. 1 163,300 163.3
2 Canal and Flume ft. 0 0
3 Penstock ft. 6000 72 432.0
Penstock ft. 2800 56 156.8
Penstock ft. 3700 56 207.2
4 Turbine, Gener-
ator, Valves,
Switchgear kW 125 900 112.5
5 24'x24' Power-
house sq. ft. 576 120 69.1
20'x20' Power-
house sq. ft. 400 120 48.0
20'x20' Power-
house sq. ft. 400 120 48.0
-151 -
6 Transmission
Line mi. 1.5 40,000 60.0
Transmission
Line mi. 3.4 40,000 136.0
7 Winter Haul Road mi. 1 . 1 20,000 22.0
Winter Haul Road mi. 0.7 20,000 14.0
Subtotal 2493.4
8 Mobilization, Demobilization,
Contractor•s Profit @ 30% 748.0
Subtotal 3241.4
9 Geographic Index Factor, 0.83 2690.4
Total Construction Cost 5931.8
10 Contingencies @ 20% 1186.4
11 Planning and Engineering @ 16% 949.1
TOTAL PROJECT COST 8067.3
-152 -
Galena
6.7.8 Galena
6. 7. 8.1 Location:
Latitude: 64°441 N
Longitude: 156°561W
6.7.8.2 Community Description:
Galena lies on the Yukon River upstream from the con-
fluence with the Koyukuk River. It is subregional cen-
ter by virtue of its paved 6,000-foot runway. An Air
Force base and FAA station dominate the village. Galena
has a high school, clinic with physician, and a commun-
ity washeteria.
6.7.8.3
1980:
2000:
2030:
6.7.8.4
Population (Year-round):
750 (Galena) + 300 (Military Base)
1114 + 300
2020 + 300
Economic Base:
Economic activity in Galena is centered around the mili-
tary installation. In summer there is a salmon roe strip-
ping operation and barge service to surrounding vil-
lages. An air taxi is based there, and miners use
Galena as a supply point.
-153 -
6.7.8.5 Existing Electric Power Eouipment:
Utility:
Generators:
M and D Enterprise, U.S. Air Force
Diesel
Capacity:
Peak Demand:
M and D -650 kW, USAF -2100 kW
M and D -325 kW, USAF -1000 kW
6.7.8.6 Projected Electrical Demands:
Galena USAF
1980: 2663 mWh/yr 5669 mWh/yr
1990: 3196 mWh/yr 5669 mWh/yr
2000: 3995 mWh/yr 5669 mWh/yr
2030: 7190 mWh/yr 5669 mWh/yr
6.7.8.7 Potential Growth Factors:
Should the market develop for fresh salmon, the fishery
could expand. The regional native nonprofit corporation
has plans to locate additional health care facilities in
Galena. There are no new HUD units planned. The
future growth of Galena hinges on the military base.
There are no plans to close it or expand it at present.
6.7.8.8 Land Use:
Regional Native Corporation
6.7.8.9 Hydropower Plan (Figure 6.7.8-1):
Diversion dam on Kala Creek, and transmission of power
to Galena.
-154 -
-155 -
a
~ • • (}?s
• ..
I
SMiles
Fl GU RE 6.7.8-1
Galena Hydro Site
Galena-New Town Site
Galena-Kala Creek About Four Miles Below
Proposed Dam Site
-156 -
Galena-Generator Building at U.S.
Air Force Base
Galena-M ~nd D Electric Generator Building
-157 -
6. 7. 8. 9.1 Streamflow Information
Stream: Kala Creek
Location of Dam: Lat. 64°33'N; Long. 156°451W
Elevation of Dam Above MSL: 190 ft.
Net Head (ft.): 60 ft.
Drainage Area: 218 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 5 7
Feb 5 7
Mar 5 7
Apr 5 7
May 500 700
Jun 400 500
Jul 220 270
Aug 200 240
Sep 210 260
Oct 110 140
Nov 40 70
Dec 10 20
Mean 143 186
-158 -
(I)
1-
i
0
...J
~
3000
2000
1000
500
400
300
200
100
0
.JAN. FEB. MAR. APR. ' MAY JUN. JUL. AUB. SEP. OCT. NOV. DEC •
MONTHS
80TH PERCENTILE
50 TH PERCENTILE
-159 -
FIGURE 6.7. 8-2
KALA CREEK a
TRIBUTARIES ~
NEAR GALENA
6. 7. 8. 9. 2 Design Information
Description of Plan: Kala Creek to Galena
Reference Figures: 6.7.8-1 1 6.7.8-2
Diversion Design Flow (CFS): 176
Quantity and Type of Turbines: 1-Francis Reaction
Installed Capacity (kW): 761
Average Annual Hydroelectric Production (mWh): 1729
Average Annual Plant Factor: 0.26
1990 Annual Demand (mWh): 3196
Environmental Constraints: Salmon, whitefish 1 arctic
grayling are present. Occasionally arctic char
are present. Historic site and cemetery at
Louden. High potential for peregrin falcon
nesting.
Cost:
Cost
Item Unit ~ Cost/Unit ($1000)
1 10'x100' diversion L.S. 1 163,300 163.3
2 Canal and Flume ft. 20300 130 2639
3 Penstock ft. 2500 260 650
4 Turbine, Gener-
ator, Valves,
Switchgear kW 761 900 684.9
5 40'x30' Powerhouse sq. ft. 1200 120 144.0
6 Transmission
Line mi. 9.8 40,000 392.0
7 Winter Haul Road mi. 14.0 201000 282.0
Subtotal 4955.2
8 Mobilization, Demobilization 1
Contractor's Profit@ 30% 1486.6
Subtotal 6441 . 8
9 Geographic Index Factor 1 0.81 5217.9
Total Construction Cost 11659.7
10 Contingencies @ 20% 2331.9
11 Planning and Engineering @ 16% 1865.6
TOTAL PROJECT COST 15,857.2
-160 -
6.7.9 Golovin
6. 7. 9.1 Location:
Latitude: 64°33'N
Longitude: 163°021W
6. 7. 9. 2 Community Description:
Golovin is a fishing village located on Golovin Bay on the
North Shore of Norton Sound about 70 miles east of
Nome. The village was founded at the turn of the cen-
tury as a Swedish Covenant Mission. Today there are
33 homes, 9 of which were constructed by the Alaska
State Housing Authority. Water and sanitation needs are
served by a PHS washeteria. At this time a new high
school is under construction and should be completed by
1981.
6.7.9.3 Population (Year-round):
1980: 118
2000: 175
2030: 318
6.7.9.4 Economic Base:
Golovin has an active salmon fishery in summer which
draws 200 seasonal residents from the surrounding vil-
lages, including Elim and White Mountain. The Golovin
fisherman's cooperative operates a processing/freezing
facility which employs 40 workers. Fishing and proces-
sing together bring an average of over $300,000 per
year to Golovin.
-161 -
6. 7. 9. 5 Existing Electric Power Equipment:
Utility: Olson & Sons (private), BIA, Fish Proces-
sor, School
Generators: Diesel
.Capacity: Olson - 1 x 7. 5 kW
BIA - 2 x 25 kW = 50 kW
School - 2 x 90 kW, 1 x 30 kW = 210 kW
Fish Processor - 2 x 125 kW, 1 x 250 kW =
500 kW
Peak Demand: 177 (total)
6.7.9.6 Projected Electrical Demands:
1980: 608 mWh/yr
1990: 730 mWh/yr
2000: 912 mWh/yr
2030: 1641 mWh/yr
6. 7. 9. 7 Potential Growth Factors:
In addition to salmon, Golovin has a substantial herring
fishery. Efforts will be made in 1981 to freeze the her-
ring. This will increase electric demand significantly.
6.7.9.8 Land Use:
Regional Native Corporation
6.7.9.9 Hydropower Plan (Figure 6.7.9-1):
Plan One -Diversion dam on East tributary to Cheenik
Creek. Transmission of power to Golovin.
-162 -
Plan Two -Diversion dams on east tributary of
Cheeni k Creek and Upper Cheenik Creek.
Transmission of Power to Golovin.
Plan Three -Same as Plan Two, except use same power-
house and penstock for both drainage
basins.
Plan Four -Diversion dam at Eagle Creek, transmis-
sion of power to Golovin
Plan Five
Plan Six
-Same as Plan Four, except intertie with
White Mountain. Therefore, transmission
of power to both Golovin and White Moun-
tain.
-Diversion dam on west tributary of
Kwiniuk River and transmission of power
to Golovin.
-163 -
. . . .
r"\
j o../'"J
/ _:~~ >";
\ \
:·~-~ I
. ·:·.1'
J
..;-.,.-_,
"'boa .
"'?(.: . ...J
-\. (
G .<. "( ._, I'
;, . J'\
· ~oo __ ·-~ f ,r"" . .._... \
·: .· ·-;
'
/
.,......, -'· c:. \'
4 / ~: \ ....... ...:.. -' ' ,/\"'o~ ·"'I :::. :54,'~/ . 8~" . ~DO ..
·-··---• • 0 -~ ._. --f.. --;· . • -... I
0
. '~ : .
j ! •
)
'-.
,, '. '3' ·-'I
• '·, 'I
/ ... ,~-. -. ~r _,. --~--..c ·~, ' .... ,. ·. ~~-~ \ ' d -··.--..._
~-'· (_-_> I '
·:~~~ .. /( \ \ 'J :;; .
\. : • -....... j
" ) ---.. ·. ~.,. -\'
WH ITE M.OUN TA I.N \· c I .. ._. (\ I ; .
I (I < ..
,.-· I
I ('(,..-' \ . \ ,~ -~' .,.,., . -J % ._ •. ~·~-----.. -·-, v '-..~ -\.. .. I -~-. , • ... ,
.. :-~I
. /)'
r ,.._ ,.
\
/
•
. : .
CREEK
"' ..
•
•
--.~ ~I ( . I ,.: .
\ '21 •
GOLOV I N-...... J --\' / .-I ·j5J /;~ ••
' ....... , · .. '\~}I. -'\/I!
\ ./
'-r -....;,/
.. ) )
..
<!,I (ri l ! .. <f', ' ; ' ~~ :_: .,_
I' i
1 I ~ ... _ . ..., --,--· ---/
I I -'I j.
,/,{
~-f : (
\ \'
I \
1/2 0 &Miles
FIGURE 6 .7.9-1
White Mountain 8
Golovin Hydro Sites
-164 -
New High School in Golovin
Looking Northwest at Proposed Diversion Dam
Site on Eagle Creek, North of Golovin
-165 -
Golovin-Note New High School and Tank Farm
-166 -
6. 7. 9. 9. 1., Streamflow Information
Stream: East Tributary of Cheenik Creek
Location of Dam: Lat. 64°361 N; Long. 162°581W
Elevation of Dam Above MSL: 120 ft.
Net Head (ft.): 60 ft.
Drainage Area: 8.9 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 1. 3 1. 8
Feb 0.8 1. 3
Mar 0.5 1.0
Apr 0.5 1 .0
May 33 50
Jun 38 90
Jul 23 30
Aug 18 23
Sep 28 38
Oct 18 25
Nov 8 10
Dec 2.5 3
Mean 14.3 22.8
-167 -
Cl)
t:
~
0
..J
:.:: 30
>-(!)
0:
1.&.1 z
1.&.1
..J 200
<(
1-z
~
0 a..
100
0
I .JAN. I FEB. MAR I APR. i MAY .JUN. .IUL AUG. SEP. ' OCT. NOV. DEC.
MONTHS
80 TH PERCENTILE
50 TH PERCENTILE
FIGURE 6.7.9-2
EAST TRIBUTARY OF CHEENIK CREEK §~
NEAR GOLOVIN AND WHITE MOUNTAIN
-168 -
6. 7. 9. 9. 2 Streamflow Information
Stream: Upper Cheenik Creek
Location of Dam: Lat. 64°37 1 N; Long. 162°581W
Elevation of Dam Above MSL: 180 ft.
Net Head (ft. ) : 1 00 ft.
Drainage Area: 3.5 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 0.5 0.7
Feb 0.3 0.5
Mar 0.2 0.4
Apr 0.2 0.4
May 13 20
Jun 15 35
Jul 9.0 12
Aug 7.0 9.0
Sep 11 15
Oct 7.0 10
Nov 3.0 4
Dec 1. 0 1.2
Mean 5.6 9.0
-169 -
(/)
l:
<I(
~
0
...J
~ 30
~
lU z
lU
...J 200
<I(
1-z
~ 0
Q.
100
80 TH PERCENTILE
50TH PERCENTILE
MONTHS
FIGURE 6.7. 9-3
UPPER CHEENIK CREEK NEAR §~
GOLOVIN AND WHITE MOUNTAIN
-170 -
6. 7. 9. 9. 3 Streamflow Information
Stream: Eagle Creek
Location of Dam: Lat. 64°43 1 N; Long. 162°541W
Elevation of Dam Above MSL: 280 ft.
Net Head (ft.): 90 ft.
Drainage Area: 30.3 sq. mi.
Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Mean
50 Percentile
Flow (CFS)
-171 -
6
4
2
2
160
180
110
85
135
.85
35
10
67.8
80 Percentile
Flow (CFS)
8
6
5
5
240
420
145
110
180
120
50
15
108.7
(I) .... ....
~
0
..J
~
~ a:
lU z
lU
~00
3000
2!500
2000
~ 1500 .... z
LIJ ....
0 a.
1000
500
400
300
200
10~~~~==~==59~==~---4----~--~--~--_j~--4----C~~
JAN. FEB. ' MAR. APR. MAY JUN. JUL. AUG. SEP. OCT. ' NOV. DEC.
80 TH. PERCENTILE
50TH. PERCENTILE
MONTHS
. FIGURE 6.7. 9-4
EAGLE CREEK NEAR §~
GOLOVIN AND WHITE MOUNTAIN
-172 -
6. 7. 9. 9. 4 Streamflow Information
Stream: West Tributary of Kwiniuk River
Location of Dam: Lat. 64°36'N; Long. 162°40'W
Elevation of Dam Above MSL: 390 ft.
Net Head (ft.): 50 ft.
Drainage Area: 16.9 sq. mi.
Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Mean
50 Percentile
Flow (CFS)
-173 -
3
1. 9
1.3
1.3
80
95
55
45
70
45
20
6
35.3
80 Percentile
Flow (CFS)
4
3
2
2
125
220
75
55
95
65
25
8
56.6
1000
...1 400
"' 1-z
I.&J b 300
ll.
200
100
0~~~~==~~--~--~~--~--~~--~~ .JAN. I FEB. MAR. ' APR MAY I .JUN. I .JUL. ' AUG. I SEP. OCT. NOV. I DEC.
MONTHS
80TH PERCENTILE
50TH PERCENTILE
FIGURE 6.7. 9-5
WI::SI IRIBUIARY QF KWINIUK RIVER §I~
NEAR GOLOVIN AND WHITE MOUNTAIN
-174 -
6.7.9.9.5 Design Information
Description of Plan: Plan One -East Tributary
Cheenik Creek to Golovin
Reference Figures: 6.7.9-1, 6.7.9-2
Diversion Design Flow (CFS): 22.8
Quantity and Type of Turbines: 1 -Francis Reaction
Installed Capacity (kW): 99
Average Annual Hydroelectric Production (mWh): 328
Average Annual Plant Factor: 0.38
1990 Annual Demand (mWh): 730
Environmental Constraints: Salmon, whitefish and
arctic grayling are present.
Cost:
Cost
Item Unit Q!Y Cost/Unit ($1000)
1 10'x250' diversion L.S.
2 Canal and Flume ft.
3 Penstock ft.
4 Turbine, Gener-
a tor, Valves,
Switchgear kW
5 24'x24' Power-
house sq. ft.
6 Transmission
Line mi.
7 Winter Haul Road mi.
8 Mobilization, Demobilization,
Contractor's Profit @ 30%
1
6800
3000
99
576
4.7
3.0
9 Geographic Index Factor, 0.87
408,250
36
72
900
120
40,000
20,000
Subtotal
Subtotal
Total Construction Cost
10 Contingencies @ 20%
11 Planning and Engineering @ 16%
TOTAL PROJECT COST
-175 -
408.3
216.0
216.0
89.1
69.1
188.0
60.0
1275.3
382.6
1657.9
1442.4
3100.3
620.1
496.0
4216.4
6.7.9.9.6 Design Information
Description of Plan: Plan Two-East Tributary
Cheenik Creek and Upper Cheenik Creek to
Golovin
Reference Figures: 6.7.9-1, 6.7.9-2, 6.7.9-3
Diversion Design Flow (CFS): East Tributary -
22.8; Upper Cheenik Creek -9.0
Quantity and Type of Turbines: 1-Francis Reaction
each creek
Installed Capacity (kW): East Tributary -99;
Upper Cheenik -65; Total -164
Average Annual Hydroelectric Production (mWh): 392
Average Annual Plant Factor: 0.27
1990 Annual Demand (mWh): 720
Environmental Constraints: Salmon, whitefish and
arctic grayling are present.
Cost:
Cost
Item Unit Q!y Cost/Unit ($1000)
1 10'x250' diversion L.S. 1 408,300 408.3
2 Canal and Flume ft. 4500 28 126.0
3 Penstock ft. 3700 56 207.2
4 Turbine, Gener-
ator, Valves,
Switchgear kW 65 900 58.5
5 2'0x20' Power-
house sq. ft. 400 120 48.0
6 Transmission
Line mi. 2.4 40,000 96.0
7 Winter Haul Road mi. 2.0 20,000 40.0
Subtotal 984
8 Mobilization, Demobilization,
Contractor• s Profit @ 30% 295.2
Subtotal 1279.2
-176 -
9 Geographic Index Factor, 0. 87
Total Construction Cost
10 Contingencies @ 20%
11 Planning and Engineering @ 16%
Subtotal
12 Plan One
TOTAL PROJECT COST
-177 -
1112.9
2392.1
478.4
382.7
3253.2
4216.4
7469.6
6.7.9.9.7 Design Information
Description of Plan: Plan Three -Same as Plan Two,
Except Use Same Powerhouse and Penstock
Reference Figures: Same as Plan Two
Diversion Design Flow ( CFS): East Tributary
Cheenik Creek -22.8; Upper Cheenik Creek -
9.0
Quantity and Type of Turbines: 1-Francis Reaction
Installed Capacity (kW): East Tributary -99;
Upper Cheenik -65; Total -164
Average Annual Hydroelectric Production (mWh): 392
Average Annual Plant Factor: 0.27
1990 Annual Demand (mWh): 730
Environmental Constraints: Salmon, whitefish and
arctic grayling are present.
Cost:
Cost
Item Unit Q!y Cost/Unit ($1000)
L.S. 2 1 1 O'x250' diversion
2 Canal and Flume
Canal and Flume
3 Penstock
ft. 18000
4 Turbine, Gener-
ator, Valves,
Switchgear
5 24' x24' Power-
house
6 Transmission
Line
7 Winter Haul Road
ft.
ft.
kW
sq. ft.
mi.
mi.
8 Mobilization, Demobilization,
Contractor's Profit @ 30%
-178 -
4500
3700
164
576
5.8
5.0
408,250
36
28
84
900
120
40,000
20,000
Subtotal
Subtotal
816.6
648.0
126.0
310.8
147.6
69.1
232
100
2450.0
735.0
3185.1
9 Geographic Index Factor, 0.87 2771.1
Total Construction Cost 5956.2
10 Contingencies @ 20% 1191.2
11 Planning and Engineering @ 16% 953.0
TOTAL PROJECT COST 8100.4
-179 -
6. 7. 9. 9. 8 Design Information
Description of Plan: Plan Four -Eagle Creek to
Golovin
Reference Figures: 6.7.9-1, 6.7.9-4
Diversion Design Flow (CFS): 30.8
Quantity and Type of Turbines: 1 -Francis Reaction
Installed Capacity ( kW): 200
Average Annual Hydroelectric Production (mWh): 427
Average Annual Plant Factor:
1990 Annual Demand (mWh):
0.24
730
Environmental Constraints: Salmon, whitefish and
arctic grayling are present.
Cost:
Cost
Item Unit Q!y Cost/Unit ($1000)
1 101x170' diversion L.S.
2 Canal and Flume ft.
3 Penstock ft.
4 Turbine, Gener-
ator, Valves,
Switchgear kW
5 24'x241 Power-
house sq. ft.
6 Transmission
Line mi.
7 Winter Haul Road mi.
8 Mobilization, Demobilization,
Contractor's Profit @ 30%
1
9200
1300
200
576
12
7
9 Geographic Index Factor, 0.87
277,600
42
84
900
120
40,000
20,000
Subtotal
Subtotal
Total Construction Cost
10 Contingencies @ 20%
11 Planning and Engineering @ 16%
TOTAL PROJECT COST
-180 -
277.6
386.4
109.2
180.0
69.1
480
140
1642.3
492.7
2135.0
1857.4
3992.4
798.5
638.8
5429.7
6. 7. 9. 9. 9 Design Information
Description of Plan: Plan Five -Eagle Creek to
Golovin and White Mountain
Reference Figures: 6.7.9-1, 6.7.9-4
Diversion Design Flow (CFS): 49.2
Quantity and Type of Turbines: 1 -Francis Reaction
Installed Capacity ( kW): 319
Average Annual Hydroelectric Production (mWh): 670
Average Annual Plant Factor: 0.24
1990 Annual Demand (mWh): 1166
Environmental Constraints: Salmon, whitefish and
arctic grayling are present.
Cost:
Cost
Item Unit Q!y Cost/Unit ($1000)
1 10'x170' diversion L.S.
2 Canal and Flume ft.
3 Penstock ft.
4 Turbine, Gener-
ator, Valves,
Switchgear kW
5 30'x24' Power-
house sq. ft.
6 Transmission
Line mi.
7 Winter Haul Road mi.
8 Mobilization, Demobilization,
Contractor1 s Profit @ 30%
1
9200
1300
319
720
29
7
9 Geographic Index Factor, 0.87
277,600
53
106
900
120
40,000
20,000
Subtotal
Subtotal
Total Construction Cost
10 Contingencies @ 20%
11 Planning and Engineering @ 16%
TOTAL PROJECT COST
-181 -
277.6
487.6
137.8
287.1
86.4
1160
140
2576.5
773.0
3349.5
2914.0
6263.5
1252.7
1002.2
8518.4
6.7.9.9.10 Design Information
Description of Plan: Plan Six -West Tributary
Kwiniuk River to Golovin
Reference Figures: 6.7.9-1, 6.7.9-5
Diversion Design Flow (CFS): 56.6
Quantity and Type of Turbines: 1 -Francis Reaction
Installed Capacity (kW): 204
Average Annual Hydroelectric Production (mWh): 578
Average Annual Plant Factor: 0.32
1990 Annual Demand (mWh): 730
Environmental Constraints: Salmon, whitefish and
arctic grayling are present.
Cost:
Cost
Item Unit Q!1: Cost/Unit ($1000)
1 10 1 x250 1 diversion L.S.
2 Canal and Flume ft.
3 Penstock ft.
4 Turbine, Gener-
ator, Valves,
Switchgear kW
5 24 1x24 1 Power-
house sq. ft.
6 Transmission
Line mi.
7 Winter Haul Road mi.
8 Mobilization, Demobilization,
Contractor•s Profit @ 30%
1
5000
400
204
576
16.4
0
9 Geographic Index Factor, 0.87
408,250
57
114
900
120
40,000
20,000
Subtotal
Subtotal
Total Construction Cost
10 Contingencies @ 20%
11 Planning and Engineering @ 16%
TOTAL PROJECT COST
-182 -
408.3
285.0
45.6
183.6
69.1
656.0
0
1647.6
494.3
2141.9
1863.4
4005.3
801.1
640.0
5447.3
Hughes
6.7.10 Hughes
6. 7. 1 0. 1 Location :
Latitude: 66°03 1 N
Longitude: 154°151W
6. 7 .10. 2 Community Description:
Hughes started as a mining supply center on the Koyu-
kuk River. Today there are 16 homes all connected to a
piped water and sewer system. There is a high school
with gym. Until recently the school generated its own
power, and the water and sewer its own with a 9 kW
generator. But the IRA council secured a HUD Block
Grant to build an electric distribution system and the
State is granting funds for a large generator. Waste
heat recovery equipment on the generator will save
10,000 gallons of heating fuel in the sewer system and
the school, essentially paying the operating costs for
residents. All freezers in Hughes are in a central build-
ing and the residents would prefer an alternate source
of electricity, such as a windmill, to power them, re-
lieving the need to run the diesel generator in summer.
6.7.10.3 Population (Year-round):
1980: 95
~000: 141
2030: 256
6. 7. 10. 4 Economic Base:
Hughes economy is summer firefighting, construction and
trapping. Transfer payments and subsistence provide
-183 -
the bulk of the community•s needs. Hughes has a small
sawmill for producing housing materials.
6. 7 .10.5 Existing Electric Power Equipment:
Utility: Village Council and School
Generators:
Capacity:
Peak Demand:
Diesel
Village Council -generator presently
under repair
School -25 kW
63 kW after electrification
6. 7 .10.6 Projected Electrical Demands:
1980: 159 mWh/yr
1990: 190 mWh/yr
2000: 239 mWh/yr
2030: 429 mWh/yr
6.7.10.7 Potential Growth Factors:
Nothing major is planned. Conservation attitude may
reduce needs.
6.7.10.8 Land Use:
Regional Native Corporation
6.7.10.9 Hydropower Plan (Figure 6.7.10-1):
Plan One -Diversion dams in two creeks west of Hughes.
Join penstocks to feed single powerhouse. Trans-
mission of power to Hughes.
Plan Two -Diversion dam in creek northwest of Hughes.
Transmission of power to Hughes.
-184 -
•
• I
•
•
• ,-.
·~
.. ? • • • ,. j ~. •
0
-185 -
I
\
\
()
\
\
I Mile
\
\
\
\
\
\
\
\
\
\
\
\
\
I \ \
\
NORTH
FIGURE 6.7.10-1
Hughes Hydro Sites
3
Hughes
Two Creeks West of Hughes, Looking So.uth
-186 -
Two Creeks West of Hughes, Looking Toward Hughes
Creek Northwest of Hughes
-187 -
6. 7. 10. 9. 1 Streamflow Information
Stream: Two creeks west of Hughes
Location of Dam: Lat. 66°04'N; Long. 154°19 1W
Elevation of Dam Above MSL: 400 ft.
Net Head (ft.): 80 ft.
Drainage Area: 5.4 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 1. 0 1. 5
Feb 0.7 1.3
Mar 0.5 1. 0
Apr 1. 5 2.0
May 11 16
Jun 16 21
Jul 6 8
Aug 5 16
Sep 11 15
Oct 3 4
Nov 2 3
Dec 1.5 2
Mean 4.9 7.6
-188 -
UJ
t: ;
0 ....
~ 30
>-~
I.&J z
Ll.l
.... 20
:!
1-z
~
0
~
80 TH PERCENTILE
50TH PERCENTILE
MONTHS
-18 -
FIGURE 6.7.10-
TWO CREEKS WEST OTT
OF HUGHES
6. 7. 10.9. 2 Streamflow Information
Stream: Creek northwest of Hughes
Location of Dam: Lat. 66°061 N; Long. 154°19'W
Elevation of Dam Above MSL: 400 ft.
Net Head (ft.): 100 ft.
Drainage Area: 5.1 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 1. 0 1.5
Feb 1. 7 1.3
Mar 0.5 1. 0
Apr 1.5 2.0
May 10 15
Jun 15 20
Jul 6 8
Aug 5 15
Sep 10 14
Oct 3 4
Nov 2 3
Dec 1.5 2
Mean 4.7 7.2
-190 -
(I)
I=
<Cl
31:
0
...J
~
>-(!) a:
l.tJ z
l.tJ
...J 20
:!
1-z
~
0 a..
100
MONTHS
80 TH PERCENTILE
50TH PERCENTILE
CREEK
OF HUGHES
-191 -
6.7.10.9.3 Design Information
Description of Plan: Plan One -Two creeks west
of Hughes to Hughes
Reference Figures: 6.7.10-1, 6.7.10-2
Diversion Design Flow ( C FS): 7. 6
Quantity and Type of Turbines: 1 -Francis Reaction
Installed Capacity (kW): 45
Average Annual Hydroelectric Production (mWh): 85
Average Annual Plant Factor: 0.22
1990 Annual Demand (mWh): 190
Environmental Constraints: Occasionally arctic char
are present. Whitefish and arctic grayling are
present.
Cost:
Cost
Item Unit Q.!y Cost/Unit ($1000)
1 10'x100' diversion L.S. 2 163,300 326.6
2 Canal and Flume ft. 0 0
3 Penstock ft. 8200 56 459.2
4 Turbine, Gener-
ator, Valves,
Switchgear kW 45 900 40.5
5 20'x20' Powerhouse sq. ft. 400 120 48.0
6 Transmission
Line mi. 0.5 40,000 20.0
7 Winter Haul Road mi. 2.0 20,000 40.0
Subtotal 934.3
8 Mobilization, Demobilization,
Contractor's Profit @ 30% 280.3
Subtotal 1214.6
9 Geographic Index Factor, 1.06 1287.5
Total Construction Cost 2502.1
10 Contingencies @ 20% 500.4
11 Planning and Engineering @ 16% 400.3
TOTAL PROJECT COST 3402.8
-192 -
6.7.10.9.4 Design Information
Description of Plan: Plan Two -Creek northwest
of Hughes to Hughes
Reference Figures: 6.7.10-1, 6.7.10-3
Diversion Design Flow (CFS): 6.2
Quantity and Type of Turbines: 1 -Francis Reaction
Installed Capacity ( kW): 45
Average Annual Hydroelectric Production (mWh): 100
Average Annual Plant Factor: 0.25
1990 Annual Demand (mWh): 190
Environmental Constraints: Occasionally arctic char
are present. Whitefish and arctic grayling are
present.
Cost:
Item Unit
1 10'x240' diversion L.S.
2 Canal and Flume ft.
3 Penstock ft.
4 Turbine, Gener-
a tor, Valves,
Switchgear kW
5 20'x20' Powerhouse sq. ft.
6 Transmission
Line mi.
7 Winter Haul Road mi.
8 Mobilization, Demobilization,
Contractor's Profit @ 30%
Q!y
1
3500
400
45
400
5.5
6.0
9 Geographic Index Factor, 1.06
Cost/Unit
391,920
28
56
900
120
40,000
20,000
Subtotal
Subtotal
Total Construction Cost
10 Contingencies @ 20%
11 Planning and Engineering @ 16%
TOTAL PROJECT COST
-193 -
Cost
($1000)
391.9
98.0
22.4
40.5
48.0
220.0
120.0
940.8
282.2
1223.0
1296.4
2519.4
503.9
403.1
3426.4
Kaltag
6. 7.11 Kaltag
6. 7.11. 1 Location:
Latitude: 64 °201 N
Longitude: 158°43'W
6. 7.11.2 Community Description:
Kaltag is the fishing center for Nulato and Koyukuk.
Thirty-nine homes are connected to a piped water and
sewer system and 17 new HUD homes are planned for
construction in 1981 or 1982. There is a high school
with gym.
6.7.11.3 Population (Year-round):
1980: 240
2000: 357
2030: 646
6.7.11.4 Economic Base:
Kaltag is the location of the Middle Yukon fishery. Roe
stripping is now performed with forwarding of some iced
fish taking place. Trapping is important in winter.
6. 7 .11.5 Existing Electric Power Equipment:
Utility: AVEC
Generators:
Capacity:
Peak Demand:
Diesel
455 kW
92 kW
-194 -
6.7.11.6 Projected Electrical Demands:
1980: 399 mWh/yr
1990: 533 mWh/yr
2000: 666 mWh/yr
2030: 1199 mWh/yr
6.7.11.7 Potential Growth Factors:
Should a market develop for the salmon 1 there will be an
expansion of the current facility with a blast freezer pos-
sibly added.
6 . 7. 11 . 8 Land Use:
Regional Native Corporation
6.7.11.9 Hydropower Plan (Figure 6.7.11-1):
Plan One -Diversion dam on south tributary of Kaltag
River. Transmission of power to Kaltag.
Plan Two -Diversion dam on north tributary to Kaltag
River. Transmission of power to Kaltag.
Plan Three -Combine Plans One and Two. Dams on both
tributaries 1 and transmission of power to Kaltag.
-195 -
..
'f//
I U< ' ,',J
. I • -.
r-'
------
' ' ; ~; -H'·· j ~: ~I . 'i ( ' . .
\' --._.. ---·'--j' ............. '•
. --:.. -/ -----· .,.... --
; .
. '
• . .
:/! .• \......-• '• --· (, ·.;. .
--' .
,--I .
~ \. ._) ,r \ / -~ ' -~~ I
I
• .) 1' '\. ~-:. -~-// . ' • I
•• I i ':2-l ~ . / \'\----~/, ),
28
---1
•// i
.(
·)
KALTAG ·RIVER
'
X ' fj'
---
I 1
I \..j.
. . ~ . :
I -\
.;:-/
35
11
I
1/2
•
24
_ _;
--,!
12
'· -..,
.. .-:
-196 -
I .
0
---
I ..
\) 5 ___ :;
. I
It
------
~--.
/
19
' I
-.,. I
1 i -·· .. \ .
5 4
0 \.,
~ .-.
NOitTH -..
'11~170 ...... ..., ' 0 ' '--··..'7 ,,
11
\
,J 0 I'
I
I Milt
F I G U R E 6. 7.11-1
Kaltag Hydro Site
6. 7. 11 . 9. 1 Streamflow Information
Stream: South Tributary of Kaltag River
Location of Dam: Lat. 64°18 1 N; Long. 158°531W
Elevation of Dam Above MSL: 400 ft.
Net Head (ft.): 100 ft.
Drainage Area: 16.4 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 0.4 0.8
Feb 0.3 0.5
Mar 0.3 0.4
Apr 0.3 0.5
May 30 50
Jun 25 40
Jul 15 30
Aug 13 32
Sep 15 22
Oct 6 3
Dec 0.6 1.3
Mean 9.0 15.9
-197 -
..J
~ ..... z
~
0
Q.
o~~~-LJ_~~E5~
.IAN. I FEB. I MAR. I APR. I MAY I .JUN. .IUL. AUG. SEP. OCT. NOV.
80 TH PERCENTILE
50TH PERCENTILE
MONTHS
FIGURE 6.7.11-2
-198 -
SOUTH TRIBUTARY
KALTAG RIVER
NEAR KALTAG
TOQ
t:::J
6. 7. 11 . 9. 2 Streamflow Information
Stream: North Tributary to Kaltag River
Location of Dam: Lat. 64°21'N; Long. 158°42'W
Elevation of Dam Above MSL: 280 ft.
Net Head (ft.): 150 ft.
Drainage Area: 25. 8 sq. mi.
Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Mean
50 Percentile
Flow (CFS)
-199 -
0.6
0.5
0.4
0.5
50
40
25
20
25
10
3
1
14.7
80 Percentile
Flow (CFS)
1.2
0.8
0.7
0.8
80
60
45
50
35
15
5
2
24.6
(J)
1-
i g
~ -
>-(!)
0::
l&J z
l&J
..J c
1-z
l&J
t-
0
ll.
1000
50
400
300
200
100
0
I .JAN. ' FEB. I MAR. APR. ' MAY I JUN. JUL. AUG. SEP. OCT. NOV. I DEC.
80 TH PERCENTILE
50 TH PERCENTILE
MONTHS
FIGURE 6.7.11-3
NORTH TRIBUTARY TO
-200 -
KALTAG -R.VER
NEAR KALTAG
6.7.11.9.3 Design Information
Description of Plan: Plan One -South Tributary
of Kaltag River to Kaltag
Reference Figures: 6.7.11-1, 6.7.11-2
Diversion Design Flow (CFS): 15.9
Quantity and Type of Turbines: 1 -Francis Reaction
Installed Capacity (kW): 115
Average Annual Hydroelectric Production (mWh): 262
Average Annual Plant Factor: 0.26
1990 Annual Demand (mWh): 553
Environmental Constraints: Salmon, whitefish, and
arctic grayling present. Occasionally arctic
char are present.
Cost:
Cost
Item Unit Q!y Cost/Unit ($1 0002
1 10'x280' diversion L.S. 1 457,200 457.2
2 Canal and Flume ft. 0 0
3 Penstock ft. 6000 65 290.0
4 Turbine, Gener-
a tor, Valves,
Switchgear kW 115 900 103.5
5 24'x24' Power-
house sq. ft. 576 120 69.1
6 Transmission
Line mi. 4.2 40,000 168
7 Winter Haul Road mi. 6.4 20,000 128
Subtotal 1315.8
8 Mobilization, Demobilization,
Contractor1 s Profit @ 30% 394.7
Subtotal 1710.5
9 Geographic Index Factor, 1.06 1813.2
Total Construction Cost 3523.7
10 Contingencies @ 20% 704.7
11 Planning and Engineering @ 16% 563.8
TOTAL PROJECT COST 4792.2
-201 -
6. 7.11. 9. 4 Design Information
Description of Plan: Plan Two -North Tributary of
Kaltag River to Kaltag
Reference Figures: 6.7.11-1 1 6.7.11-3
Diversion Design Flow (CFS): 11.8
Quantity and Type of Turbines: 1 -Francis Reaction
Installed Capacity (kW): 127
Average Annual Hydroelectric Production (mWh): 300
Average Annual Plant Factor: 0.27
1990 Annual Demand (mWh): 533
Environmental Constraints: Salmon 1 whitefish 1 and
arctic grayling are present. Occasionally 1
arctic char are present. Known peregrin falcon
nesting habitat in vicinity.
Cost:
Item Unit
1 5 1x400 1 diversion L.S.
2 Canal and Flume ft.
3 Penstock ft.
4 Turbine, Gener-
ator 1 Valves,
Switchgear kW
5 241 x24 1 Power-
house sq. ft.
6 Transmission
Line mi.
7 Winter Haul Road mi.
8 Mobilization 1 Demobilization 1
Contractor's Profit @ 30%
9£!
1
10300
3600
127
576
1. 9
2.6
9 Geographic Index Factor 1 1 . 06
Cost/Unit
5011200
29
58
900
120
401000
201000
Subtotal
Subtotal
Total Construction Cost
10 Contingencies @ 20%
11 Planning and Engineering @ 16%
TOTAL PROJECT COST
-202 -
Cost
C$10ooL
501.2
298.7
208.8
114.3
69.1
76
52
1320.1
396.0
1716.1
1819. 1
3535.2
706.4
565.6
4807.2
6.7.11.9.5 Design Information
Description of Plan: Both North and South Tribu-
taries to Kaltag·
Reference Figures: 6.7.11-1, 6.7.11-2, 6.7.11-3
Diversion Design Flow (CFS): North Tributary -9.5;
South Tributary -6.0
Quantity and Type of Turbines: 1 -Francis Reaction
each creek
Installed Capacity (kW): North Tributary -103;
South Tributary -43; Total -146
Average Annual Hydroelectric Production (mWh): 311
Average Annual Plant Factor: 0.24
1990 Annual Demand (mWh): 533
Environmental Constraints: Salmon, whitefish, arctic
grayling are present. Occasionally arctic char
are present. Known peregrin falcon nesting
habitat in vicinity.
Cost:
Cost
Item Unit Q!Y Cost/Unit ($1000)
1 10 1 x280' diversion L.S. 1 501,200 501.2
2 Canal and Flume ft. 10300 28 0
3 Penstock ft. 6000 56 336
Penstock ft. 3600 56
4 Turbine, Gener-
ator, Valves,
Switchgear kW 43 900 201.6
Turbine, Gener-
ator, Valves,
Switchgear kW 103 900 92.7
5 20'x20 1 Power-
house sq. ft. 400 120 48.0
24'x24' Power-
house sq. ft. 576 120 69.1
6 Transmission
Line mi. 4.2 40,000 168.0
Transmission
Line mi. 1. 9 40,000 76.0
-203 -
7 Winter Haul Road mi. 6.4 20,000 128.0
Winter Haul Road mi. 2.6 20,000 52.0
Subtotal 2129.8
8 Mobilization, Demobilization,
Contractor 1 s Profit @ 30% 638.9
Subtotal 2768.7
9 Geographic Index Factor, 1.06 2934.9
Total Construction Cost 4703.6
10 Contingencies @ 20% 1140.7
11 Planning and Engineering @ 16% 912.6
TOTAL PROJECT COST 7756.9
-204 -
/
Kiana
6.7.12 Kiana
6. 7. 12.1 Location:
Latitude: 66°58 1 N
Longitude: 160°26'W
6. 7. 11 . 2 Community Description:
Kiana was founded by gold miners who came to the Klery
Creek area in the early 1900's. Mining there lasted into
the 19401 s when costs became prohibitive. The village is
an Eskimo community today, but has evolved from its
mining roots as a much more western community than its
neighbors. Two non-natives have well-established stores
there and do a thriving business even with surrounding
villages. The BIA maintained a K-12 school system in
Kiana until the State took it over in the early 1970•s.
There is a high school with vocational training center
and a 4-room elementary school. The village has a piped
water and sewer system which is at its limit. The run-
way is 4,000-feet with lights and was resurfaced in 1980.
Teacher housing is available and of high quality.
6. 7.12.3 Population (Year-round):
1980: 314
2000: 467
2030: 845
6.7.12.4 Economic Base:
The economy of Kiana is markedly different from its
neighbors. Work patterns and skills are much higher
quality and are reflected in the comparatively large num-
-205 -
ber of residents working on the North Slope and other
parts of Alaska, then returning to the village to live.
Many have built spacious modern homes with many con-
veniences. Subsistence is important in Kiana, too. An
air taxi operates from there, as well as two wilderness
guide businesses.
6. 7 .12.5 Existing Electric Power Equipment:
Utility: AVEC
Generators: Diesel
650 kW
144 kW
Capacity:
Peak Demand:
6.7.12.6 Projected Electrical
1980: 645 mWh/yr
1990: 864 mWh/yr
2000: 1037 mWh/yr
2030: 1296 mWh/yr
Demands:
6.7.12.7 Potential Growth Factors:
Given the preference of residents to work outside the
village and return, Kiana will probably grow more
quickly than surrounding villages. The city council is
able to plan and anticipate needs, as evidenced in its
requests to expand its sewer system. Buildable land is
abundant in the village, as is gravel for streets. A
small portable sawmill will be introduced in 1981, which
should increase self-housing activity, as will the 10 new
HUD housing units being planned for 1981-82.
Electric usage should expand in Kiana faster than any
other NANA region village.
-206 -
6.7.12.8 Land Use:
NANA Regional Native Corporation
6.7.12.9 Hydropower Plan (Figure 6.7.12-1):
Divert Canyon Creek to turbine.
power to Kiana.
-207 -
Transmission of
I
I
)
(<
33
\
,....->
'-
~
\.,.;J's ' ~'
' ::<-
~-'
I
CANYON
I
15 l
I
I
f ,
\ \
10•
\
\
I
\ %
r --\
\ \. r
/
1 \
'
? "IZO ( r' \ ..,
I
I
I
I
, ~ I --., l -
I
, __ ) / 16
I
I
) I
lUANA .~--I . . I -,
"1
I
I
I
'I
I
I
j
\
0
-~~
'I. ---:;;J
\
\,
f'l<>
.... -
-:..·-
.:::./
-
(
(
\.
\.
\
,.-
)
..-'\_ >(
(
I "\.
' ....... ~./, \
\.. -
_.,.. r ~ _r /
---~ I -/ I I, \ '\ " '+ -'
./ ' •.6; -\.
' \
\.""\ ' l-~
" \
~, , .. _..,,
:1 .. %"':
,/) f}
I
(
'-...._ "\. .... -"'
.J
_£/
~ NORTti
I
I Mile
FIGURE 6.7.12-1
Kiana Hydro Site
--208 -
. I
I
I
6. 7.12. 9.1 Streamflow Information
Stream: Canyon Creek
Location of Dam: Lat. 67°05' N; Long. 160°08'W
Elevation of Dam Above MSL: 400 ft.
Net Head (ft.): 150 ft.
Drainage Area: 9.5 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 1.2 1.4
Feb 1 . 1 1. 3
Mar 1.0 1 .2
Apr 1.5 2.0
May 35 50
Jun 50 70
Jul 20 25
Aug 20 30
Sep 15 25
Oct 6.0 10
Nov 3.0 5.0
Dec 1.4 1.6
Mean 12.9 18.5
-209 -
>-(!)
1000
ffi 50
2
Ll.l
..J 400
Cl
1-
2
~ 300
0
ll.
200
100
0
I .JAN. FEB. I MAR. I APR. I MAY I .JUN. JU.L. ' AUG. SEP. OCT. NOV. I DEC.
MONTHS
80 TH PERCENTILE
50 TH PERCENTILE
-210 -
FIGURE 6.7.12-2
CANYON CREEK
NEAR KIANA
6. 7. 12. 9. 2 Design Information
Description of Plan: Canyon Creek to Kiana
Reference Figures: 6.7.12-1, 6.7.12-2
Diversion Design Flow (CFS): 18.5
Quantity and Type of Turbines: 1 -Francis Reaction
Installed Capacity (kW): 205
Average Annual Hydroelectric Production (mWh): 387
Average Annual Plant Factor: 0.22
1990 Annual Demand (mWh): 864
En vi ron mental Constraints:
grayling are present.
nesting habitat.
Whitefish and arctic
Potential peregrin falcon
Cost:
Item Unit
1 10'x50' Diversion L.S.
2 Canal and Flume ft.
3 Penstock ft.
4 Turbine, Gener-
ator, Valves,
Switchgear kW
5 241x24' Powerhouse sq. ft.
6 Transmission Line mi.
7 Winter Haul Road mi.
8 Mobilization 1 Demobilization,
Contractor•s Profit @ 30%
~
1
0
6300
205
576
8.4
9.6
9 Geographic Index Factor, 1.08
Cost/Unit
81,650
66
900
120
40,000
20,000
Subtotal
Subtotal
Total Construction Cost
10 Contingencies @ 20%
11 Planning and Engineering @ 16%
TOTAl PROJECT COST
-211 -
Cost
($1000)
81.7
0
415.8
184.5
69.1
336.0
192.0
1279.1
383.7
1662.8
1795.9
3458.7
691.7
553.4
4703.8
Kobuk
6. 7.13 Kobuk
6. 7 .13.1 Location:
Latitude: 66°55 1 N
Longitude: 156°521W
6.7.13.2 Community Description:
The village of Kobuk is the oldest of the three upper
Kobuk River villages. Population shifts in recent years
have created doubt as to the continued viability of the
village. In 1979 the city council lapsed into nonexis-
tence, but was re-established.
Kobuk lacks several of the necessities of a viable NANA
village. Wien Air Alaska only flies two scheduled stops
per week. The store is poorly stocked. Although a line
has been run between Shungnak and Kobuk, there is no
electricity yet. No bulk storage tanks or fuel sales are
present. The airport is only 1,500-feet and belongs to
Wien instead of the State. The village floods regularly.
6.7.13.3 Population (Year-round):
1980: 49
2000: 73
2030: 132
6.7.13.4 Economic Base:
Ten new HUD homes are scheduled for construction in
1981. This should draw new families to Kobuk. Money
was appropriated to contruct a 3, 000-foot runway with
lights and shelter. Because of the ownership problem,
it is not clear what will be done.
-212 -
Subsistence is the mainstay of the village, although much
of the population is over 60 years of age.
6. 7 .13. 5 Existing Electric Power Equipment:
Utility: School
Generators:
Capacity:
Peak Demand:
Diesel
100 kW
25 kW
6. 7. 13.6 P rejected Electrical Demands:
1980: 122 mWh/yr
1990: 146 mWh/yr
2000: 183 mWh/yr
2030: 329 mWh/yr
6.7.13.7 Potential Growth Factors:
The construction of 10 new housing units and the intro-
duction of a small portable sawmill will make housing in
Kobuk an attraction. As mentioned in the section on
Shungnak, the Dahl Creek Airport is nearby and may
foster further growth.
6.7.13.8 Land Use:
NANA Native Corporation
6.7.13.9 Hydropower Plan (Figure 6.7.13-1):
An electrical intertie between Kobuk and Shungnak is
presently being constructed. Therefore, the hydropower
plan developed for Kobuk consists of a diversion dam on
Dahl Creek, and transmission of power to Kobuk, thus
servicing both Kobuk and Shungnak.
-213 -
-214 -
Fl GURE 6.7.13-1
Shungnak a Kobuk
Hydro Sites
Dahl Creek in Kobuk
ViUage of Kobuk, Looking Westward
-215 -
Dahl Creek, North of Kobuk
-216 -
Dahl Creek, North of Kobuk.
Dahl Creek Landing Strip
in Center
6. 7. 13. 9. 1 Streamflow Information
Stream: Dahl Creek
Location of Dam: Lat. 66°57 1 N; Long. 156°50'W
Elevation of Dam Above MSL: 500 ft.
Net Head (ft.): 200 ft.
Drainage Area: 9.6 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 1. 2 1.4
Feb 1 . 1 1. 3
Mar 1. 0 1. 2
Apr 1. 5 2.0
May 40 60
Jun 25 35
Jul 15 25
Aug 20 25
Sep 15 25
Oct 8 15
Nov 4 6
Dec 1.4 1. 6
Mean 11.1 16.5
-217 -
1000
-Cl)
1-
1-~
~
9
:::.:::
>-(.!)
a:: 50 l.tJ z
l.tJ
..J 400 c
1-z
l.tJ 300 1-
0
11.
200
100
o~~~==~~_j __ l_j_-l--L-j_~~
..IAN. . FEB. • MAR. APR. I MAY ..IUN. ..IUL. AUG. I SEP. I OCT. I NOV. I DEC.
MONTHS
80TH PERCENTILE
50TH PERCENTILE
FIGURE 6.7.13-2 ~~~ =~ §2~
-218 ..
6.7.13.9.2 Design Information
Description of Plan: Dahl Creek to Kobuk. Kobuk
is presently intertieing with Shungnak.
Reference Figures: 6.7.13-1, 6.7.13-2
Diversion Design Flow ( CFS): 9. 7
Quantity and Type of Turbines: 1 -Turgo Impulse
Installed Capacity ( kW): 140
Average Annual Hydroelectric Production (mWh): 328
Average Annual Plant Factor: 0.28
1990 Annual Demand (mWh): Kobuk-146;
Shungnak -440i Total -586
Environmental Constraints: Whitefish and arctic
grayling are present. Potential peregrin falcon
nesting habitat in vicinity.
Cost:
Item
1 10'x701 Diversion
2 Canal and Flume
3 Penstock
4 Turbine, Gener-
ator, Valves,
Switchgear
5 24'x24' Powerhouse
6 Transmission
Line
7 Winter Haul Road
Unit
L.S.
ft.
ft.
kW
sq. ft.
mi.
mi.
8 Mobilization, Demobilization,
Contractor's Profit @ 30%
Q!i
1
0
6300
140
576
3.5
0
9 Geographic Index Factor, 1.08
Cost/Unit
114,310
56
900
120
40,000
Subtotal
Subtotal
Total Construction Cost
10 Contingencies @ 20%
11 Planning and Engineering @ 16%
TOTAL PROJECT COST
-219 -
Cost
($1000)
114.3
0
352.8
126.0
69.1
140.0
0
802.2
240.7
1042.9
1126.3
2169.2
433.8
347.1
2950.1
Koyukuk
6. 7.14 Koyukuk
6.7.14.1 Location:
Latitude: 64°53 1 N
Longitude: 157°421W
6. 7 .14.2 Community Description:
Koyukuk is a fishing viiJage. A high school with full-
size gym was recently completed. Water needs are taken
care of by a PHS washeteria. Housing is in high de-
mand in Koyukuk.
6.7.14.3 Population (Year-round):
1980: 124
2000: 184
2030: 334
6.7.14.4 Economic Base:
Summer commercial fishing for salmon is the major econo-
mic activity. Trapping is a mainstay in fall/winter.
The demand for housing will probably bring a HUD pro-
ject.
6. 7. 14.5 Existing Electric Power Equipment:
Utility: Koyukuk Yukon School District
Generators:
Capacity:
Peak Demand:
Diesel
1-30 kW, 1-75 kW, 1-100 kW = 205 kW
80 kW
-220 -
6.7.14.6 Projected Electrical Demands:
1980: 750 mWh/yr
1990: 900 mWh/yr
2000: 1125 mWh/yr
2030: 2025 mWh/yr
6.7.14.7 Potential Growth Factors:
At present the salmon are stripped of their eggs and the
. carcasses discarded for lack of a market. Negotiations
are currently taking place to establish a market utilizing
empty backhaul international cargo flights which refuel
in Fairbanks. Should negotiations be successful, the vil-
lage has plans to obtain an icing and cool storage facility
for forwarding fresh iced salmon. This facility would be
a major electricity user.
Several small gold claims are worked in the surrounding
area. It does not appear likely that these will stimulate
growth in the village.
6.7.14.8 Land Use:
Regional Native Corporation
6.7.14.9 Hydropower Plan (Figure 6.7.14-1):
Diversion dam on east tributary to Nulato River, trans-
mission of power to Koyukuk.
-221 -
..,
. •
')
·~KOYUK~
----\ -
/ ·-
-/·,--..:;..,.-:>
- -( <:;·./ /":::.
---/ ?
---? ~N
:... ~--
"'R;~ ., ~ ...
~ .
I
112 6
-222 -
-
t ....
-
"'
~~ I ....
~" ..
• •• &
..,...
..
~
FIGURE 6.7.14-1
...
Koyukuk a Nulato
Hydro Sites
~·
Koyukuk-Looking Northwest
Koyukuk-Proposed Diversion Dam Site on
East Tributary to Nulato River
-223 -
Koyukuk-Buildings in Village
Koyukuk-Generator Building at School
-224 .
6. 7.14. 9. 1 Streamflow Information
Stream: East Tributary to Nulato River
Location of Dam: Lat. 64°52' N; Long. 158°1 O'W
Elevation of Dam Above MSL: 480 ft.
Net Head (ft.): 70 ft.
Drainage Area: 23.3 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 0.5 1. 0
Feb 0.5 1.0
Mar 0.5 1.0
Apr 2.0 3.0
May 95 140
Jun 50 75
Jul 30 35
Aug 30 35
Sep 40 45
Oct 20 25
Nov 10 12
Dec. 0.5 1
Mean 23.3 31.2
-225 -
1500
en
1-
!:i
3:: g 1000
~
>-(,!) a:
IU z
LU
...J
c:t
1-z 500 LU
1-
0 400 a.
300
200
100
0
JAN. FEB. I MAR. APR. I
80 TH PERCENTILE
50 TH PERCENTILE
MAY JUN. JUL. AUG. SEP. I OCT. I NOV. DEC.
MONTHS
FIGURE 6.7.14-2
EAST TRIBUTARY
TO NULATO RIVER
NEAR NULATO
-226 -
6.7.14.9.2 Design Information
Description of Plan; East Tributary of Nulato River
to Koyukuk
Reference Figures: 6.7.14-1, 6.7.14-2
Diversion Design Flow (CFS); 31.2
Quantity and Type of Turbines: 1-Francis Reaction
Installed Capacity (kW): 157
Average Annual Hydroelectric Production (mWh): 440
Average Annual Plant Factor:
1990 Annual Demand (mWh):
0.32
900
Environmental Constraints: Occasionally, arctic char
are present. Whitefish and arctic grayling are
present.
Cost:
Item Unit
1 10'x500' Diversion L.S.
2 Canal and Flume ft.
3 Penstock ft.
4 Turbine, Gener-
ator, Valves,
Switchgear kW
5 24'x24' Powerhouse sq. ft.
6 Transmission
Line mi.
7 Winter Haul Road mi.
8 Mobilization, Demobilization,
Contractor's Profit @ 30%
~
1
11600
400
157
576
14.4
10.3
9 Geographic Index Factor, 1.06
Cost/Unit
626,500
42
84
900
120
40,000
20,000
Subtotal
Subtotal
Total Construction Cost
10 Contingencies @ 20%
11 Planning and Engineering @ 16%
TOTAL PROJECT COST
-227 -
Cost
($1000)
626.5
487.2
33.6
141.3
69.1
576.0
206.0
2139.7
641.9
2781.6
2948.5
5730.1
1146.0
916.8
7792.9
Manley Hot Springs
6. 7.15 Manley Hot Springs
6.7.15.1 Location:
Latitude: 65°00 1 N
Longitude: 150°38'W
6.7.15.2 Community Description:
Manley Hot Springs is a resort village at the end of the
Elliot Highway, 130 miles from Fairbanks. The village
has a lodge, bar and store which see a large influx of
tourists and gold miners in summer. There is a growing
number of retirees establishing summer homes and many
miners are constructing residences closer to their claims.
6. 7 .15. 3 Population (Year-round):
1980: 74
2000: 110
2030: 199
6.7.15.4 Economic Base:
The economy of the village is tourism and mining. Both
are growing rapidly.
6. 7. 15.5 Existing Electric Power Equipment:
Utility: Manley Hot Springs Enterprises
Generators:
Capacity:
Peak Demand:
Diesel
110 kW
37.5 kW
-228 -
6.7.15.6 Projected Electrical Demands:
1980: 131 mWh/yr
1990: 157 mWh/yr
2000: 197 mWh/yr
2030: 354 mWh/yr
6.7.15.7 Potential Growth Factors:
The tourism facilities are regarded as excellent and will
probably continue to gorw.
6. 7. 15. 8 Land Use:
Unknown.
6.7.15.9 Hydropower Plan (Figure 6.7.15-1):
Diverson dam on McCloud Ranch Creek. Transmission of
power to Manley Hot springs.
-229 -
-230 -
I Mile
FIGURE 6.7.15-1
Manley Hot Springs
Hydro Site
Manley Hot Springs
Generator Building at Manley Hot Springs
-231 -
McCloud Ranch Creek, West ·of Manley Hot Springs
-232 -
McCloud . Ranch Creek,
West of Manley Hot Springs
6. 7. 15. 9. 1 Streamflow Information
Stream: McCloud Ranch Creek
Location of Dam: Lat. 65°00 1 N; Long. 150°45 1 W
Elevation of Dam Above MSL: 600 ft.
Net Head (ft.): 300 ft.
Drainage Area: 2.3 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 0.1 0.2
Feb 0.0 0.1
Mar 0.0 0.1
Apr 0.3 0.4
May 6.0 9.0
Jun 5.0 8.0
Jul 2.0 2.5
Aug 3.5 5.0
Sep 1.5 2.0
Oct 1.0 1. 3
Nov 0.4 0.5
Dec 0.3 0.3
Mean 1. 7 2.5
-233 -
>-~
liJ z
liJ
o~~dJ_j_J__CJ~"""""" JAN. I FEB. I MAR. APR. MAY I JUN. .IUL. AUG. I SEP. ' OCT. NOV. I DEC.
LEGEND:
80 TH PERCENTILE
50TH PERCENTILE
MONTHS
FIGURE 6.7.15-2
Me CLOUD RANCH CREEK §.I~
NEAR MANLEY HOT SPRINGS
-234 -
6. 7.15. 9. 2 Design Information
Description of Plan: McCloud Ranch Creek to Manley
Hot Springs
Reference Figures: 6.7.15-1, 6.7.15-2
Diversion Design Flow ( C FS): 1. 7
Quantity and Type of Turbines: 1 -Pelton Impulse
Installed Capacity ( kW): 37
Average Annual Hydroelectric Production (mWh): 84
Average Annual Plant Factor: 0.26
1990 Annual Demand (mWh): 157
Environmental Constraints: High
aeological and historic sites.
arctic grayling are present.
arctic char are present.
potential for arch-
Whitefish and
Occasionally,
Cost:
Cost
Item Unit Q!y Cost/Unit ($1000)
1 10'x50' diversion L.S.
2 Canal and Flume ft.
3 Penstock ft.
4 Turbine, Gener-
ator, Valves,
Switchgear kW
5 20'x20' Powerhouse sq. ft.
6 Transmission Line mi.
7 Winter Haul Road mi.
8 Mobilization, Demobilization,
Contractor's Profit @ 30%
1
0
3700
37
400
2.2
2.9
9 Geographic Index Factor, 0.45
81,650
56
900
120
40,000
20,000
Subtotal
Subtotal
Total Construction Cost
10 Contingencies @ 20%
11 Planning and Engineering @ 16%
TOTAL PROJECT COST
-235 -
81.7
0
207.2
33.3
48.0
88.0
58.0
516.2
154.9
671.1
302.0
973.1
194.6
155.7
1323.4
Nome
6. 7.16 Nome
6. 7. 16. 1 Location :
Latitude: 64°30'N
Longitude: 165°251W
6.7.16.2 Community Description:
Nome is the regional center for the Bering Straits area.
It was founded in 1898 when gold was discovered in
Anvil Creek. Shortly after, its population reached
40,000, making it one of America•s most famous boom
towns. Today its population has returned to 3,000.
The population is about 1/3 non-native, 2/3 Eskimo,
although Nome is clearly run by the non-natives.
Nome contains extensive infrastructure too numerous to
list, including hospital, paved airport with hangars and
two 6,000-foot runways, barge docks, paved streets with
access to over 300 miles of interconnected roads, high
school, elementary school, and community college, radio
stations, many retail and services businesses, a hotel
and many restaurants and bars.
6.7.16.3 Population (Year-round):
1980: 2585
2000: 3842
2030: 6959
6. 7 .16.4 Economic Base:
Nome's economy is diverse, although heavily dependent
on government employment. The Federal Government, in
-236 -
addition to the hospital, employs workers in administra-
tive positions in the BIA, BLM, and a large FAA instal-
lation. The State of Alaska also has extensive staff, in-
cluding DOT /PF, Fish and Game, the court system, and
regional social service delivery. The private sector in-
cludes several air taxi operators, headquarters for sche-
duled air service to surrounding villages, and connec-
tions to Anchorage. The Alaska Gold Company operates
several large dredges in the summer, tallying 130,000
ounces production in 1979. The dredges have their own
diesel electric generators and are estimated to use over
500,000 gallons of fuel per 180-day season. This repre-
sents 1/3 the annual fuel consumption for electric gener-
ation in Nome and the majority of summer electric usage.
A small salmon and crab fishery is located in Nome, but
no processing is done. Reindeer are slaughtered in a
facility 5 miles out of town.
6.7.16.5 Existing Electric Power Equipment:
Utility: Nome Joint Utilities (City of Nome),
Alaska Gold Company
Generators:
Capacity:
Peak Demand:
Diesel
City of Nome -6850 kW
Alaska Gold Company 4800 kW
3100 kW (excluding Alaska Gold Co.)
6. 7. 16.6 Projected Electrical Demands:
1980: 14,000 mWh/yr
1990: 31,900 mWh/yr
2000: 72,900 mWh/yr
2030: 176,515 mWh/yr
-237 -
6.7.16.7 Potential Growth Factors:
Norton Sound is scheduled for the sale of Offshore Oil
Lease Tracts in 1982. Nome is the likely service base
for the exploration phase and should large quantities of
oil and gas be found, major development would take
place in Nome. The City of Nome will, actively seek and
support such development.
The government sector is growing quickly and should
continue as State oil revenues increase. High gold
prices have sharply increased mining activity both in
Nome and the surrounding Seward Peninsula and are
likely to continue.
The final potential is that a hard rock mineral operation
will be started somewhere on the Seward Peninsula or
that the transportation system for one elsewhere would
terminate near Nome.
Recent enactment of state guaranteed mortgage programs
will create private housing boom as highly paid resident
government workers seek tax and family shelters.
6. 7. 16. 8 Land Use:
Mining
6.7.16.9 Hydropower Plans (Figure 6.7.16-1):
Plan One -Diversion dam on Penny River. Transmission
of power to Nome.
Plan Two -Diversion Dam on Osborn Creek. Transmis-
sion of power to Nome.
-238 -
Plan Three -Diversion dams on Buster Creek and Os-
born Creek. lntertie transmission lines and transmit
power to Nome.
Plan Four -Diversion
Creek, Basin Creek,
dams on Osborn Creek, Buster
Alfield Creek and David Creek.
Transmission of all generated power to Nome.
-239 -
-.,
. .
' ;·.
4 r
+
'
/l
' .. ~;
,~35 J' ;::.
I I
p
PENNY RWER
·-
\ 1\ t /
)\. ,. ,,
l
... ) (\l
Ot I ~~,6~~ ~~ l ,. -·
..I .. .1 :;_!.;_
• • • • • • WATERSHED BNDRY.
r" DAM
FLUME a CANAL
PENSTOCK
- - - -TRANSMISSION LINE
• POWERHOUSE
= ==== ACCESS ROAD
t ·
NOME~
1/2 0
-240 -
• •
:, ". • •
6 Miles
CRE EK
•
) .le .-~--
•
."-'-)( : ----, 'r ~~ ' I [
,_
..... ' ...
L---.-n.s,BORN
, .• CREEK .
~ ·. \' ~1,0/ll . '
... t ..
Fl GU R E 6.7.16-1
Nome Hydro Sites
Watershed Upstream of Osborn Creek Dam Site, East
of Nome
Penny River Near Nome
-241 -
Proposed Dam Site on Osborn Creek, East of Nome
Standing in Middle of Typical Diversion Canal,
Near Nome River .
-242 -
. Culvert Crossing-Basin Creek, North of Nome
Culvert Crossing-David Creek, North of Nome
-243 -
6.7.16.9.1 Streamflow Information
Stream: Penny River
Location of Dam: Lat. 64°36 1 N; Long. 165°34'W
Elevation of Dam Above MSL: 160 ft.
Net Head: 50 ft.
Drainage Area: 16.01 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 4 4.5
Feb 3.5 4.0
Mar 3 3.5
Apr 2.5 4.0
May 70 150
Jun 110 160
Jul 50 60
Aug 50 75
Sep 100 200
Oct 30 45
Nov 15 17
Dec 5 6
Mean 36.9 60.8
-244 -
-
>-(.!)
1000
ffi 50 z
LIJ
....J 400 ct
t-z
LIJ
b 300
0..
200
100
O ' JAN. . FEB. . MAR. APR. . MAY ' JUN. ' JUL.
MONTHS
80TH PERCENTILE
50 TH PERCENTILE
-245 -
AUG. SEP. OCT. I NOV:
FIGURE 6.7.1
PENNY RIVER
NEAR NOME
DEC.
6. 7. 16.9. 2 Streamflow Information
Stream: Osborn Creek
Location of Dam: Lat. 64 °36 1 N; Long. 165 °061W
Elevation of Dam Above MSL: 180 ft.
Net Head: 100 ft.
Drainage Area: 21.1 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 4.4 5
Feb 4.0 4.4
Mar 3.3 3.8
Apr 2.7 4.4
May 80 165
Jun 120 175
Jut 55 65
Aug 55 80
Sep 110 220
Oct 35 50
Nov 16 20
Dec 5.5 6
Mean 40.9 66.6
-246 -
(/)
1-
1-
~
9
~ -
>-(!) a::
L&J z
L&J
...1
<X
1-z
L&J
b
CL.
2000
1500
1000
500
400
300
200
100
O ' JAN. FEB, MAR. APR. MAY JUN. JUL. 1 AUG. SEP. OCT. 1 NOV. 1 DEC.
80TH PERCENTILE .
50 TH PERCENTILE
MONTHS
-247 -
FIGURE 6.7.16-3
OSBORN CREEK OTT
NEAR NOME
6. 7. 16. 9.3 Streamflow Information
Stream: Buster and Lillian Creeks
Location of Dam: Lat. 64°36 1 N; Long. 165°061W
Elevation of Dam Above MSL: 100 ft.
Net Head: 50 ft.
Drainage Area: 4.9 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 1.0 1 . 1
Feb 0.9 1.0
Mar 0.8 0.9
Apr 0.6 1. 0
May 18 40
Jun 28 40
Jul 13 15
Aug 13 19
Sep 25 50
Oct 8 11
Nov 4 4
Dec 1. 3 1. 5
Mean 9.5 15.4
-248 -
>-<.!)
1000
ffi 50 z
LIJ
_J 400 ~
1-z
LIJ b 300
0..
200
100
0
I JAN. FEB. I MAR. APR. MAY I JUN. JUL. AUG. SEP. I OCT. I NOV. DEC.
MONTHS
80TH PERCENTILE
50 TH PERCENTILE
-249 -
FIGURE 6.7.16-4
BUSTER a LILLIAN §
CREEKS NEAR NOME
6.7.16.9.4 Streamflow Information
Stream: Basin Creek
Location of Dam: Lat. 64°39'N; Long. 165°15'W
Elevation of Dam Above MSL: 200 ft.
Net Head: 60 ft.
Drainage Area: 3.1 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 1. 0 1.1
Feb 0.8 0.9
Mar 0.6 0.6
Apr 0.5 0.5
May 13 30
Jun 20 30
Jut 10 12
Aug 10 14
Sep 20 40
Oct 6 9
Nov 3 3.5
Dec 1.0 1 . 1
Mean 7.2 11.9
-250 -
.-
(/)
I=
~ ~
0
....J
~
>-(!) a: w z w
....J
~
1-z w
1-
0 a.
200
100
o~~~~~J_~~
MAR. I APR. ' MAY ; JUN. .IUL AUG. SEP. ' OCT. I NOV. I DEC. JAN.
MONTHS
80 TH PERCENTILE
50 TH PERCENTILE
-251 -
FIGURE 6.7.16-5
BASIN CREEK
NEAR NOME
OTT
6. 7.16. 9. 5 Streamflow Information
Stream: Alfield Creek
Location of Dam: Lat. 64°491 N; Long. 165°09'W
Elevation of Dam Above MSL: 550 ft.
Net Head: 50 ft.
Drainage Area: 4 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 1 . 1 1. 2
Feb 0.9 1.1
Mar 0.8 0.9
Apr 0.7 1 . 1
May 19 40
Jun 30 45
Jul 13 16
Aug 13 20
Sep 27 55
Oct 8 12
Nov 4 4.5
Dec 1. 3 1 .6
Mean 9.9 16.5
-252 -
(J)
t:
<(
3:
0
..J
~ 30
,_
<.!) a:
""' z
""'
..J 200
<(
..... z
""' .....
0 a.
100
0
' .JAN. I FEB. MAR. I APR. I MAY i JUN. .IUL AUG. ' SEP. I OCT. ' NOV.
LEGEND:
80 TH PERCENTILE
50TH PERCENTILE
MONTHS
-253 -
FIGURE 6.7.16-
ALFIELD CREEK OTT
NEAR NOME
Golovin
6. 7. 16.9. 6 Streamflow Information
Stream: David Creek
Location of Dam: Lat. 64°49 1 N; Long. 165°091W
Elevation of Dam Above MSL: 950 ft.
Net Head: 130 ft.
Drainage Area: 2.1 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 0.6 0.6
Feb 0.5 0.6
Mar 0.4 0.5
Apr 0.3 0.6
May 10 21
Jun 15 22
Jul 7 8
Aug 7 10
Sep 14 28
Oct 4 6
Nov 2 2
Dec 0.7 0.8
Mean 5.1 8.3
-254 -
rn
1-
1-<t
3:
0
..J
::.c:: 30
>-(!) a:
LLJ z
LLJ
..J 200 <t
1-z
LLJ
1-
0 a.
100
SO TH PERCENTILE
50 TH PERCENTILE
MONTHS
FIGURE 6.7.16-7
DAVID CREEK NEAR NOME
-255 -
6.7.16.9.7 Design Information
Description of Plan: Plan One-Pef}ny River to Nome
Reference Figures: 6.7.16-1, 6.7.16-2
Diversion Design Flow (CFS): 60.8
Quantity and Type of Turbines: 1-Francis Reaction
Installed Capacity (kW): 219
Average Annual Hydroelectric Production (mWh): 827
Average Annual Plant Factor: 0.43
1990 Annual Demand (mWh): 31,900
Environmental Constraints: Salmon, whitefish, and
arctic grayling are present. High potential for
archeological and historic sites.
Cost:
Item Unit
1 10'x300' diversion L.S.
2 Canal and Flume ft.
3 Penstock ft.
4 Turbine, Gener-
ator, Valves,
Switchgear kW
5 24'x24' Powerhouse sq. ft.
6 Transmission Line mi.
7 Winter Haul Road mi.
8 Mobilization, Demobilization,
Contractor's Profit @ 30%
Q!y
1
11100
600
219
576
6.8
0
9 Geographic Index Factor, 0.35
Cost/Unit
489,900
61
122
900
120
40,000
20,000
Subtotal
Subtotal
Total Construction Cost
10 Contingencies ~ 20%
11 Planning and Engineering @ 16%
TOTAL PROJECT COST
-256 -
Cost
($1000)
489.9
677.1
73.2
197.1
69.1
272
1778.4
533.5
2311.9
809.2
3121.1
624.2
499.4
4244.7
6.7.16.9.8 Design Information
Description of Plan: Plan Two-Osborn Creek to Nome
Reference Figures: 6. 7.16-1, 6. 7.16-3
Diversion Design Flow ( C FS): 66. 6
Quantity and Type of Turbines: 1 -Francis Reaction
Installed Capacity ( kW): 479
Average Annual Hydroelectric Production (mWh): 1, 824
Average Annual Plant Factor:
1990 Annual Demand (mWh):
0.43
31,900
Environmental Constraints: Salmon, whitefish and
arctic grayling are present. High potential for
archaeological and historic sites.
Cost:
Item Unit
1 1 0'x1 50' diversion L.S.
2 Canal and Flume ft.
3 Penstock ft.
4 Turbine, Gener-
ator, Valves,
Switchgear kW
5 40'x30' Powerhouse sq. ft.
6 Transmission
Line mi.
7 Winter Haul Road mi.
8 Mobilization, Demobilization,
Contractor's Profit @ 30%
Slli
1
14300
1300
479
1200
8.1
2.5
9 Geographic Index Factor, 0.35
Cost/Unit
244,950
64
128
900
120
40,000
20,000
Subtotal
Subtotal
Total Construction Cost
10 Contingencies @ 20%
11 Planning and Engineering @ 16%
TOTAL PROJECT COST
-257 -
Cost
($1000)
245.0
915.2
166.4
431.1
144.0
324.0
50.0
2275.7
682.7
2958.4
1035.4
3993.8
798.8
639.0
5431.6
6.7.16.9.9 Design Information
Description of Plan: Plan Three-Osborn Creek and
Buster Creek to Nome
Reference Figures: 6.7.16-1, 6.7.16-3, 6.7.16-4
Diversion Design Flow (CFS): Osborn Creek -66.6
Buster Creek -15.4
Quantity and Type of Turbines: 1-Francis Reaction.
each creek
Installed Capacity ( kW): Osborn Creek -479
Buster Creek -55, Total -534
Average Annual Hydroelectric Production (mWh): 2035
Average Annual Plant Factor: 0.44
1990 Annual Demand (mWh): 31,900
Environmental Constraints: Salmon, whitefish and
arctic grayling present. High potential for
archaeological and historic sites.
Cost:
Cost
Item Unit Q!i. Cost/Unit ($1000)
1 10'x220' diversion
2 Canal and Flume
3 Penstock
4 Turbine, Gener-
ator, Valves,
Switchgear
5 20 1x201 Powerhouse
6 Transmission Line
7 Winter Haul Road
L.S.
ft.
ft.
kW
sq. ft.
mi.
mi.
8 Mobilization, Demobilization,
Contractor's Profit @ 30%
1
3200
2700
55
400
3.6
0
9 Geographic Index Factor, 0.35
359,260
32
64
900
120
40,000
20,000
Subtotal
Subtotal
Total Construction Cost
10 Contingencies @ 20%
11 Planning and Engineering @ 16%
Total Buster Creek Project Cost
12 Osborn Creek Project
TOTAL PROJECT COST
-258 -
359.3
102.4
172.8
49.5
48.0
144.0
0
876.0
262.8
1138.8
398.6
1537.4
307.5
246.0
2090.9
5431.6
7522.5
6.7.16.9.4 Design Information
Description of Plan: Plan Four-Penny River 1 Osborn 1
Buster 1 Basin 1 Alfield, and
David Creeks to Nome
Reference Figures: 6.7.16-1 1 6.7.16-2, 6.7.16-3,
6.7.16-4, 6.7.16-51 6.7.16-6, 6.7.16-7
Diversion Design Flow ( C FS): Osborn Creek -66.6
Buster Creek-15.4
Basin Creek -11.9
Alfield Creek -16.5
David Creek 8.3
Quantity and Type of Turbines: 1-Francis Reaction
each creek
Installed Capacity ( kW): Osborn Creek -479
Buster Creek -55
Basin Creek 51
Alfield Creek -60
David Creek 79
TOTAL -724
Average Annual Hydroelectric Production (mWh): 2750
Average Annual Plant Factor: 0.43
1990 Annual Demand (mWh): 31 1900
Environmental Constraints: Salmon 1 whitefish and
arctic grayling are present. High potential
for archaeological and historic sites.
Cost:
Cost
Item Unit QSy Cost/Unit ($1000)
1 10'x70' diversion L.S. 3 114,310 342.9
2 Canal and Flume ft. 0 0
3 Penstock ft. 2100 58 121.8
" ft. 2100 65 136.5
II ft. 5300 56 296.8
4 Turbine, Generator 1 kW 51 900 45.9
Valves, Switchgear kW 60 900 54.0
kW 79 900 71.1
5 20'x20' Powerhouse sq. ft. 3x400 120 144.0
6 Transmission Line mi. 20 40,000 800.0
7 Winter Haul Road mi. 3 20,000 60.0
Subtotal 2073.0
-259 -
8 Mobilization, Demobilization,
Contractor 1 s Profit @ 30%
9 Geographic Index Factor, 0.35
Subtotal
Total Construction Cost
10 Contingencies @ 20%
11 Planning and Engineering @ 16%
Total Cost for Basin, Alfield, & David Creek
12 Buster Creek Project
13 Osborn Creek Project
-260 -
TOTAL PROJECT COST
621.9
2694.9
943.2
3638.1
727.6
582.1
4947.8
2090.9
5431.6
12470.3
Nulato
6. 7.17 Nulato
6. 7. 17. 1 Location :
Latitude: 64°43'N
Longitude: 158°06'W
6. 7.17 .2 Community Description:
Nulato is a rapidly growing community. Fifteen BIA
homes were built in 1979 and 30 new HUD homes are
under construction at a new village expansion site out of
the flood plain. The high school will be completed in
1981. Water is supplied by a PHS washeteria.
6.7.17.3 Population (Year-round):
1980: 365
2000: 542
2030: 983
6.7.17.4 Economic Base:
Nulato is the most job/cash-oriented community in the
Galena Subregion. Villagers have placed the provision
of jobs above subsistence in their priority list. Summer
provides commercial fishing and winter provides trapping.
Salmon are taken by boat to Kaltag for processing and
no plans are foreseen for processing in the village.
-261 -
6. 7.17. 5 Existing Electric Power Equipment:
Utility: AVEC
Generators:
Capacity:
Peak Demand:
Diesel
550 kW
167 kW
6.7.17.6 Projected Electrical Demands:
1980: 543. 4 mWh/yr
1990: 698 mWh/yr
2000: 867 mWh/yr
2030: 1571 mWh/yr
6.7.17.7 Potential Growth Factors:
Nulato is actively seeking to establish a fur tannery.
Studies of its feasibility are being conducted now and if
proven economical, investment by Doyon and State
Development agencies is likely. The facility would be a
major employer for the village and surrounding area, as
well as a large electric consumer.
The village is also investigating the possibility of mining
coal for heating, electric generation and distribution to
nearby villages.
6. 7.17 .8 Land Use:
Regional Native Corporation
6.7.17.9 Hydropower Plan (Figure 6.7.14-1):
Plan One -Diversion dam on west unnamed tributary to
Nulato River. Transmission of power to Nulato.
-262 -
Plan Two -Diversion dams on east and west tributaries
to Nulato River. Transmission of power to both Nulato
and Koyukuk.
-263 -
6. 7. 17.9. 1 Streamflow Information
Stream: West Unnamed Tributary to Nulato River
Location of Dam: Lat. 64°52'N; Long. 158°19'W
Elevation of Dam Above MSL: 400 ft.
Net Head: 100 ft.
Drainage Area: 25.3 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 0.5 1.0
Feb 0.5 1.0
Mar 0.5 1.0
Apr 2.0 3.0
May 100 150
Jun 55 80
Jul 30 40
Aug 30 35
Sep 40 45
Oct 20 25
Nov 10 12
Dec 0.5 1.0
Mean 24.1 32.8
-264 -
-(I) .... ;
ISOO
g 1000
::.c::
>-(!)
0::
I.IJ z
I.IJ
200
100
0 JAN. • FEB. I MAR.
80 TH PERCENTILE
50TH PERCENTILE
APR. JUN. JUL. AUG. SEP. OCT. ' NOV. ' DEC.
MONTHS
-265 -
FIGURE 6.7.17-1
WEST TRIBUTARY
TO NULATO RIVER
NEAR NULATO
6.7.17.9.2 Design Information
Description of Plan: Plan One-West Tributary to Nulato
Reference Figures: 6.7.14-1 1 6.7.17-1
Diversion Design Flow (CFS): 23.0
Quantity and Type of Turbines: 1-Francis Reaction
Installed Capacity ( kW): 166
Average Annual Hydroelectric Production (mWh): 390
Average Annual Plant Factor:
1990 Annual Demand (mWh):
0.27
698
Environmental Constraints: Occasionally 1 arctic char
are present. Whitefish and arctic grayling are
present.
Cost:
Cost
Item Unit Q!Y Cost/Unit ($1000)
1 101x2401 diversion L.S. 1 391,900 391.9
2 Canal and Flume ft. 9000 37 333.0
3 Penstock ft. 1800 74 133.2
4 Turbine 1 Gener-
ator 1 Valves,
Switchgear kW 166 900 149.4
5 24 1x241 Power-
house sq. ft. 576 120 69.1
6 Transmission
Line mi. 11.5 401000 460.0
7 Winter Haul Road mi. 13.5 201000 270.0
Subtotal 1806.6
8 Mobilization 1 Demobilization,
Contractor• s Profit @ 30% 542.0
Subtotal 2348.6
9 Geographic Index Factor 1 1. 06 2489.5
Total Construction Cost 4838.1
10 Contingencies @ 20% 967.6
11 Planning and Engineering @ 16% 774.1
TOTAL PROJECT COST 6579.8
-266 -
6.7.17.9.3 Design Information
Description of Plan: Plan Two -Both East and
West Triburaties to Nulato and Koyukuk
Reference Figures: 6.7.14-1, 6.7.14-2, 6.7.17-1
Diversion Design Flow ( C FS): East Tributary -30.1
West Tributary -31.8
Quantity and Type of Turbines: 1-Francis Reaction
each creek
Installed Capacity (kW): East Tributary -152
West Tributary -229
Total 381
Average Annual Hydroelectric Production (mWh): 871
Average Annual Plant Factor: 0.26
1990 Annual Demand (mWh): 1598
Environmental Constraints:
grayling are present.
char are present.
Whitefish and arctic
Occasionally, arctic
Cost:
Item Unit ~ Cost/Unit
1 5'x5001 diversion L.S. 1 626,500
10'x2401 diversion L.S. 1 391,900
2 Canal and Flume ft. 11600 41
II II II ft. 9000 42
3 Penstock ft. 400 82
II ft. 1800 84
4 Turbine, Generator, kW 152 900
Valves, Switchgear kW 229 900
5 24'x24' Powerhouse sq. ft. 2x 576 120
6 Transmission mi. 14.4 40,000
Line mi. 11.5 40,000
7 Winter Haul Road mi. 10.3 20,000
II II II mi. 13.5 20,000
II II II mi. 3.2 20,000
Subtotal
8 Mobilization, Demobilization,
Contractor•s Profit @ 30%
Subtotal
9 Geographic Index Factor, 1.06
Total Construction Cost
10 Contingencies @ 20%
11 Planning and Engineering @ 16%
TOTAL PROJECT COST
-267 -
Cost
($1000)
626.5
391.9
475.6
378.0
32.8
151.2
136.8
206.1
138.2
576.0
460.0
206.0
270.0
64.0
4113.1
1233.9
5347.0
5667.9
11014.9
2203.0
1762.4
14,980.3
Point Hope
6.7.18 Point Hope
6.7.18.1 Location:
Latitude: 68°21 1 N
Longitude: 166°471W
6.7.18.2 Community Description:
Point Hope is one of the oldest continuously-inhabited
places in North America. Located on a gravel spit in
the Chuckchi Sea, it is ideally suited for hunting marine
mammals, including bowhead whales. Point Hope is part
of the North Slope Borough, and thus enjoys a higher
level of government employment and infrastructure than
other villages in the study area. Nearly all the 70
homes in the village are new. The high school was com-
pleted in 1979 and there are adequate teachers• quarters
and a warehouse. Water needs are met with a washe-
teria. All utilities and community services are financed
by the Borough.
6.7.18.3 Population (Year-round):
1980: 507
2000: 753
2030: 1365
6. 7.18.4 Economic Base:
The economy of Point Hope is subsistence, transfer pay-
ments, and Borough employment. Trapping plays a
minor winter role.
-268 -
6. 7 .18.5 Existing Electric Power Equipment:
Utility: North Slope Borough Power and Light
Generators:
Capacity:
Peak Demand:
Diesel
510 kW
300 kW
6.7.18.6 Projected Electrical Demands:
1980: 1590 mWh/yr
1990: 1907 mWh/yr
2000: 2212 mWh/yr
2030: 4195 mWh/yr
6.7.18.7 Potential Growth Factors:
No major developments are likely near Point Hope. Off-
shore oil may be present, but ice conditions are extreme-
ly hazardous. Significant coal seams are nearby, but
not likely developable. Revenues to run the Borough
stem directly from taxes on Prudhoe Bay property.
These will be sustained through the end of the century,
but further onshore finds will be needed to extend the
tax base.
6. 7.18.8 Land Use:
Regional Native Corporation
6.7.18.9 Hydropower Plan (Figure 6.7.18-1):
Diversion dam on Akalolik Creek. Transmission of power
to Point Hope.
-269 -
NORTH
POINT HOPE
... , --
-~-.. --...... .-· -; ....
<-t .. -:~ --,
I
0
-270 -
..... l-
-1'"'
\
~'.~-.
·-·· ~ (_
I
I
~
6 Miles
..
•
•
•
•
•
•
• ..
• • •
+
FIGURE 6.!18-1
• • •
Point Hope Hydro Site
'-;>'
6.7.18.9.1 Streamflow Information
Stream: Akalolik Creek
Location of Dam: Lat. 68°29 1 N; Long. 166°10 1W
Elevation of Dam Above MSL: 200 ft.
Net Head: 63 ft.
Drainage Area: 50.9 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 0 0
Feb 0 0
Mar 0 0
Apr 0 0
May 50 160
Jun 220 420
Jul 160 230
Aug 110 150
Sep 110 300
Oct 25 35
Nov 1 2
Dec 0 0
Mean 56.3 108.1
-271 -
en ....
!i
3:
0
...J
3500
3000
2500
::.:::
-2000
>-(!) cr::
LLJ :z
LLJ
<i 1500
.... :z
LLJ ....
0 a..
1000
500
400
300
200
100
o+---~------~---+---4--~~--~--~--~~~--~~~ JAN. 1 FEB •. MAR. ' APR. ' MAY JUN. JUL. ' AUG. SEP. ' OCT. ' NOV. ' DEC.
MONTHS
80 TH. PERCENTILE
50 TH. PERCENTILE
-272 -
FIG RE 6.7.18-
AKALOLIK CREEK OTT
NEAR POINT HOPE
6.7.18.9.2 Design Information
Description of Plan: Akaloli k Creek to Point Hope
Reference Figures: 6. 7.18-1, 6. 7.18-2
Diversion Design Flow (CFS): 100
Quantity and Type of Turbines: 1-Francis Reaction
Installed Capacity ( kW): 454
Average Annual Hydroelectric Production (mWh): 1006
Average Annual Plant Factor: 0.25
1990 Annual Demand (mWh): 1907
Environmental Constraints: Whitefish and arctic
grayling are present.
Cost:
Item Unit Q!y Cost/Unit
1 10'x360' diversion L.S. 1 587,880
2 Canal and Flume ft. 8500 82
3 Penstock ft. 1300 165
4 Turbine, Gener-
ator, Valves,
Switchgear kW 454 900
5 30'x24' Power-
house sq. ft. 720 120
6 Transmission
Line mi. 18.7 40,000
7 Winter Haul Road mi. 20.6 20,000
Subtotal
8 Mobilization, Demobilization,
Cost
($1000)
587.9
697.0
214.5
408.6
86.4
748.0
412.0
3154.4
Contractor's Profit @ 30% 946. 3
Subtotal 4100.7
9 Geographic Index Factor, 0.95 4182.7
Total Construction Cost 8283.5
10 Contingencies @ 20% 1656.7
11 Planning and Engineering @ 16% 1325.4
TOTAL PROJECT COST 11265.6
-273 -
Shungnak
6.7.19 Shungnak
6. 7. 19. 1 Location:
Latitude: 66°52 1 N
Longitude: 157°09'W
6.7.19.2 Community Description:
Shungnak is located on the north bank of the Kobuk
River on a channel which is rapidly closing due to sedi-
mentation. It was founded in 1908 when people migrated
from Kobuk. During the 1940's a weather station was
there.
6.7.19.3 Population (Year-round):
1980: 226
2000: 336
2030: 608
6.7.19.4 Economic Base:
During the 1970's several public buildings, including a
snowmachine repair shop, clinic, public safety buildings
and teen center were built. The high school was fin-
ished in 1977, 18 HUD homes in 1978 and the PHS water
and sewer in 1979. AVEC began generating electricity
shortly after television and telephone were established.
Eighteen new housing units are now being planned.
During 1980 an electric line was run to Kobuk. If suc-
cessful, it will add 12 residential customers to the sys-
tem.
-274 -
The village runway will be expanded in 1981-83 1 at
which time an airport warmup shelter and lights will be
installed.
The village economy is subsistence and government.
6. 7 .19.5 Existing Electric Power Equipment:
utility: A vee
Generators:
Capacity:
Peak Demand:
Diesel
705 kW
96 kW
6.7.19.6 Projected Electrical Demands:
1980: 336.9 mWh/yr
1990: 440 mWh/yr
2000: 551 mWh/yr
2030: 991 mWh/yr
6.7.19.7 Potential Growth Factors:
The channel at Shungnak is not navigable every year by
barge. Since all fuel is delivered this way, severe prob-
lems can develop.
Should a transportation system be developed 1 significant
employment growth would result.
Bornite mine is 20 miles from Shungnak. Owned by
Kennecott Copper subsidiary 1 Bear Creek Mining I it is a
fully-developed copper mine that was closed in the early
1970's because of shaft flooding and lack of a transpor-
tation system.
-275 -
The intertie with Kobuk could be expanded to include
Dahl Creek Airport. Dahl Creek is the only 5,000-foot
runway in the upper Kobuk Valley. It receives large
quantities of equipment and supplies to serve the mining
camps in the surrounding area. During summer the B LM
establishes a firefighting base camp there, which in-
cludes two barracks buildings. Plans are now set for
the establishment of bulk fuel sales at the airport, which
should increase small craft traffic. Dahl Creek is con-
nected to Kobuk and Bornite via 35 miles of gravel road
and would probably be a staging area for any future
major development.
6.7.19.8 Land Use:
Regional Native Corporation
6.7.19.9 Hydropower Plan (Figure 6.7.13-1):
Diversion dam on Cosmos Creek. Transmission of power
to Kubuk and Shungnak.
-276 -
Shungnak
-277 -
6. 7 .19.9.1 Streamflow Information
Stream: Cosmos Creek
Location of Dam: Lat. 67°00' N; Long. 157°09'W
Elevation of Dam Above MSL: 600 ft.
Net Head (ft.): 200 ft.
Drainage Area: 11.7 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 1. 3 1. 5
Feb 1.2 1. 3
Mar 1.0 1. 2
Apr 2.0 3.0
May 50 80
Jun 30 40
Jul 20 35
Aug 25 35
Sep 20 30
Oct 10 18
Nov 5 7
Dec 1. 5 1.8
Mean 13.9 21 .2
-278 -
en .... ....
~
3: g
~
>-(!) a::
lLI z
lLI
~
~ .... z w ....
0
d.
1500
1000
500
400
~0
MONTHS
80 TH. PERCENTILE
50 TH. PERCENTILE
-279 -
FIGURE 6.7.19-1
COSMOS CREEK §2~
NEAR SHUNGNAK
6.7.19.9.2 Design Information
Description of Plan: Cosmos Creek to Shungnak and
Kobuk
Reference Figures: 6.7.13-1, 6.7.19-1
Diversion Design Flow (CFS): 10
Quantity and Type of Turbines: 1-Turgo Impulse
Installed Capacity (kW): 144
Average Annual Hydroelectric Production (mWh): 331
Average Annual Plant Factor: 0.26
1990 Annual Demand (mWh): 586
Environmental Constraints: Whitefish and arctic
grayling are present.
Cost:
Item
1 1 0 1x501 diversion
2 Canal and Flume
3 Penstock
4 Turbine, Gener-
ator, Valves,
Switchgear
5 24'x241 Power-
house
6 Transmission
Line
7 Winter Haul Road
Unit
L.S.
ft.
ft.
kW
sq. ft.
mi.
mi.
8 Mobilization, Demobilization,
Contractor's Profit @ 30%
Q!i
1
0
6800
144
576
6.8
8.1
9 Geographic Index Factor, 1. 08
Cost/Unit
81,650
56
900
120
40,000
20,000
Subtotal
Subtotal
Total Construction Cost
10 Contingencies @ 20%
11 Planning and Engineering @ 16%
TOTAL PROJECT COST
-280 -
Cost
($1000)
81.7
0
380.8
129.6
69.1
272.0
162.0
1095.2
328.6
1423.8
1537.7
2961.5
592.3
473.8
4027.6
Tanana
6.7.20 Tanana
6.7.20.1 Location:
Latitude: 65°10 1 N
Longitude: 152°041W
6. 7. 20.2 Community Description:
Tanana can be considered a subregional center. The
village contains an FAA facility, U.S. Air Force site,
PHS hospital, two large stores, a wholesale/cooperative
grocery distribution business, motel and cafe. There is
a community washeteria, and most homes have wells and
septic systems. The village has a high school and HUD
is constructing 25 new homes in 1980.
6. 7.20.3 Population (Year-round):
1980: 499
2000: 742
2030: 1,343
6.7.20.4 Economic Base:
The economy of Tanana is mixed. There is significant
government employment at FAA, PHS and U.S. Air Force
site. Summer sees fish processing. The facility has
lost money recently but will continue to operate. If the
market for fresh fish develops, the power requirements
for icing and cooling will increase significantly. Winter
provides trapping income and, as in other villages, sub-
sistence hunting and wood fuel gathering are important
activities.
-281 -
6.7.20.5 Existing Electric Power Equipment:
Utility: Tanana Power Company
Generators: Diesel
1000 kW
425 kW
Capacity:
Peak Demand:
6.7.20.6
1980:
1990:
2000:
2030:
6.7.20.7
Projected Electrical Demands:
1489 mWh/yr
1787 mWh/yr
2234 mWh/yr
8020 mWh/yr
Potential Growth Factors:
Tanana has an aggressive city council and manager.
The last legislature funded $3,000,000 in capital improve-
ments, including a food processing storage facility, an
ice rink, multi-purpose community building, float plane
dock, etc. These will all increase demand.
The PHS hospital will discontinue inpatient care in 1981.
The facility will be converted to an ambulatory senior
citizens home and a headquarters for decentralization of
many health services now in Fairbanks. Staff will in-
crease and will be permanent Tanana residents instead of
transients. With growth in employment of local resi-
dents, a private housing market will develop.
6.7.20.8 Land Use:
Regional Native Corporation
-282 -
6. 7. 20.9 Hydropower Plan (Figure 6. 7. 20-1):
Plan One -Diversion dam on Bear Creek. Transmission
of power to Tan ana.
Plan Two -Diversion dam on Jackson Creek. Trans-
mission of power to Tanana.
Plan Three -Diversion dams on Bear Creek and Jackson
Creek. Transmission of power to Tanana.
-283 -
..,
<J;)
~
' ~
)' $...,
.I)
.... .
!"
I
J
t1
(/=>
(; , ......
...,
00
"" .....
I
/.
,...,.
~
0'
.•
,~
tl t
rl a
"· . .... •
~
..,
\
J
a-.
J I !
.,.i
\)
(}
<?
<>
(
.,~.r
' t
! , , {
a
~
,.
"'
\0
0
~ ,f..,'
\
Tf,
. ' \ "' \ \'Jt _, ,\...;
·~
'-; --:: . . .
BEAR CREEK ~~
-----
\_
r '-
~~ ~~'
f
\
----{ ' ~ . /
~\I . .-:::....r
•,
"'• .; \. . '
\
,, \.., \
...............
.
)!. ~ Y! .-_~ .
•
~-
JACKSON CREEK "' ---.. \-. . . . . \ . . . •
I 1/2 0 I Mil e
-284 -
FIGURE 6.7.20-1
Tanana Hydro Sites
«f c:
«f c:
«f .... ....
0 .... «f CIJ c: «f «f w c: -«f ~ I.() .... co
Q) N
Q)
""' 0
c:
0
CIJ
~
0
«f -,
as c: as c: as
~
-.....
0
~ ...
~
0 z
<.0 co
N
~
CD
CD
~
0
~ as
CD m
6. 7. 20.9. 1 Streamflow Information
Stream: Bear Creek
Location of Dam: Lat. 65°16 1 N; Long. 152°001W
Elevation of Dam Above MSL: 475 ft.
Net Head: 75 ft.
Drainage Area: 35.5 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 1.5 2.0
Feb 0.8 1. 0
Mar 0.7 1.0
Apr 1.0 1 . 1
May 70 110
Jun 45 100
Jul 30 50
Aug 35 75
Sep 30 38
Oct 16 20
Nov 8 10
Dec 3 4
Mean 20.1 34.3
-287 -
>-(!)
1000
ffi 50 z
ILl
....J 400 <(
1-z
ILl 5 300
a.
200
100
O~,=J~A~N=.~F:E:B=.~,:M:A:R=.~.=A:P:Rd'L_M-AY_j'L_J-UN-.+--JU-L-.+-A-U-G-.l,-S-E-P-.~,-O-C-~~,-N-0-~JC:D:EC=.~,
MONTHS
80 TH PERCENTILE
50 TH PERCENTILE
FIGURE 6.7.20-
BEAR CREEK OTT
NEAR TANANA
-288 -
6. 7. 20.9. 2 Streamflow Information
Stream: Jackson Creek
Location of Dam: Lat. 65°16 1 N; Long. 151 °48'W
Elevation of Dam Above MSL: 325ft.
Net Head: 75 ft.
Drainage Area: 34.2 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 1.5 2.0
Feb 0.8 1.0
Mar 0.7 1.0
Apr 1.0 1. 1
May 65 100
Jun 42 90
Jul 28 45
Aug 33 70
Sep 28 35
Oct 15 19
Nov 8 10
Dec 3 4
Mean 18.8 31.5
-289 -
>-(!)
1000
ffi so z
LIJ
...J 400 ~
1-z
~ 300
0
0..
200
100
O ' JAN. ' FEB. ' MAR. ' APR. ' MAY ' JUN. JUL. AUG. SEP. ' OCT. ' NOV.
80 TH PERCENTILE
50 TH PERCENTILE
MONTHS
-290 -
FIGURE 6.7.20-3
JACKSON CREEK ~
NEAR TANANA
6.7.20.9.3 Design Information
Description of Plan: Plan One-Bear Creek to Tanana
Reference Figures: 6.7.20-1, 6.7.20-2
Diversion Design Flow (CFS): 34.3
Quantity and Type of Turbines: 1-Francis Reaction
Installed Capacity (kW): 185
Average Annual Hydroelectric Production (mWh): 624
Average Annual Plant Factor: 0.39
1990 Annual Demand (mWh): 1787
Environmental Constraints: Occasionally, arctic
char are present. Whitefish and arctic gray-
ling are present.
Cost:
Cost
Item Unit Q!i: Cost/Unit ($1000)
1 10'x360' diversion L.S.
2 Canal and Flume ft.
3 Penstock ft.
4 Turbine, Gener-
ator, Valves,
Switchgear kW
5 24'x24' Power-
house sq. ft.
6 Transmission
Line mi.
7 Winter Haul Road mi.
8 Mobilization, Demobilization,
Contractor's Profit @ 30%
1
11000
600
185
576
3.4
2.0
9 Geographic Index Factor, 0.88
587,880
44
88
900
120
40,000
20,000
Subtotal
Subtotal
Total Construction Cost
10 Contingencies @ 20%
11 Planning and Engineering @ 16%
TOTAL PROJECT COST
-291 -
587.9
484.0
52.8
166.5
69.1
136.0
40.0
1536.3
460.9
1997.2
1757.5
3754.7
750.9
600.8
5106.4
6.7.20.9.4 Design Information
Description of Plan: Plan Two-Jackson Creek to Tanana
Reference Figures: 6.7.20-1, 6.7.20-3
Diversion Design Flow (CFS): 31.5
Quantity and Type of Turbines: 1-Francis Reaction
Installed Capacity (kW): 174
Average Annual Hydroelectric Production (mWh): 594
Average Annual Plant Factor: 0. 39
1990 Annual Demand (mWh): 1787
Environmental Constraints: Occasionally, arctic char
are present. Whitefish and arctic grayling are
present.
Cost:
Item Unit
1 10 1 x160 1 diversion L.S.
2 Canal and Flume ft.
3 Penstock ft.
4 Turbine, Gener-
ator, Valves,
Switchgear kW
5 24 1 x24 1 Power-
house sq. ft.
6 Transmission
Line mi.
7 Winter Haul Road mi.
8 Mobilization, Demobilization,
Contractor•s Profit @ 30%
Q!y
1
7100
800
174
576
8.4
1.7
9 Geographic Index Factor, 0.88
Cost/Unit
261,280
42
84
900
120
40,000
20,000
Subtotal
Subtotal
Total Construction Cost
10 Contingencies @ 20%
11 Planning and Engineering @ 16%
TOTAL PROJECT COST
-292 -
Cost
($1000)
261.3
298.2
67.2
156.6
69.1
336.0
34.0
1222.4
366.7
1589.1
1398.4
2987.5
597.5
478.0
4063.0
6.7.20.9.5 Design Information
Description of Plan: Bear Creek and Jackson Creek
to Tanana
Reference Figures: 6.7.20-1, 6.7.20-2, 6.7.20-3
Diversion Design Flow (CFS): Bear Creek -34.3
Jackson Creek-31.5
Quantity and Type of Turbines: 1-Francis Reaction
each creek
Installed Capacity ( kW): Bear Creek
Jackson Creek
Total
Average Annual Hydroelectric Production
Average Annual Plant Factor: 0. 29
1990 Annual Demand (mWh): 1787
-185
-174
359
(mWh): 889
Environmental Constraints: Occasionally, arctic
char are present. Whitefish and arctic gray-
ling are present.
Cost:
Cost
Item Unit .Q.!x Cost/Unit ($1 000)
1 Bear Creek Project
2 Jackson Creek Project
5106.4
4063.0
9169.4 TOTAL PROJECT COST
-293 -
Wales
6.7.21 Wales
6. 7. 21 . 1 Location:
Latitude: 65°37 1 N
Longitude: 168°05 1W
6. 7. 21.2 Community Description:
Wales contains 30 homes, 18 built by HUD in 1976. A
PHS washeteria serves sanitary needs.
6.7.21.3 Population (Year-round):
1980: 134
2000: 199
2030: 361
6.7.21.4 Economic Base:
Wales 1 economy is
transfer payments.
subsistence, reindeer herding, and
Trapping and ivory carving provide
additional income. Wales is the site of aircraft naviga-
tional aids because of its location on the Bering Strait.
6. 7 .21.5 Existing Electric Power Equipment:
Utility: AVEC
Generators:
Capacity:
Peak Demand:
Diesel
185 kW
39 kW
-294 -
6.7.21.6 Projected Electrical Demands:
1980: 126.8 mWh/yr
1990: 154 mWh/yr
2000: 191 mWh/yr
2030: 343 mWh/yr
6. 7. 21.7 Potential Growth Factors:
Deposits of tin, tungsten and gold, accompanied by
fluorite are found in the surrounding area. Should a
port be established on the Seward Peninsula, these might
be developed, but would probably not directly affect the
village.
6. 7 .21.8 Land Use:
Regional Native Corporation
6.7.21.9 Hydropower Plan (Figure 6.7.21-1):
Diversion dam on Kanauguk River. Transmission of
power to Wales.
-295 -
·. d:~ .!..-: .......
'~ .. ,.
:_:,~::: c () ..
·o 0
.• ·OOf: . ... ·d:J
.... ····~
.. ·····
• <
1:c:>9
.. ~·::~.
,· .. @:
+~
•.•• ;". _.l{r
'.,:.
,Q.'i; ' ~";'
<:::J
.
~
..
" ";Z.
0 ~ 0 I
'
<>'--
i
,;l
~
........
"' !·
0 ' ~Q
'>-
"""
~ ,;l
0:: ..
• • • • • • WATERSHED BNDRY.
r'\ DAM
FLUME . a CANAL
PENSTOCK
~---TRANSMISSION LINE
POWERHOUSE = ==== ACCESS R AD
Q
.1\
0
G
()f
1/2 0 6 Miles
FIGURE '6.7.21-1
Wales Hydro Site
296
6. 7. 21.9. 1 Streamflow Information
Stream: Kanauguk River
Location of Dam: Lat. 65°30 1 N; Long. 167°30'W
Elevation of Dam Above MSL: 400 ft.
Net Head: 50 ft.
Drainage Area: 7. 5 sq. mi.
50 Percentile 80 Percentile
Month Flow (CFS) Flow (CFS)
Jan 0.2 0.4
Feb 0.1 0.2
Mar 0.0 0.1
Apr 0.0 0.1
May 20 40
Jun 35 50
Jul 8.0 15
Aug 12 25
Sep 10 30
Oct 5 8
Nov 1. 0 1.5
Dec 0.4 0.6
Mean 7.6 14.2
-297 -
C/)
I=
<t
3:
0
...J
'X:
>-(!)
0::
IJJ z
IJJ
...J
<t
1-z
IJJ
1-
0
CL
100
oJ.===--------------J,L---4.----~.--_JL-__ J1----1~--_J~~ ~~~==~
I JAN. I FEB. MAR ' APR. MAY JUN. I .IUL AUG. SEP. OCT. NOV. DEC.
MONTHS
80 TH PERCENTILE
50 TH PERCENTILE
FIGURE 6.7.21-2
0 KANAUGUK RIVER
NEAR WALES
-298 -
6.7.21.9.2 Design Information
Description of Plan: Kanauguk River to Wales
Reference Figures: 6.7.21-1, 6.7.21-2
Diversion Design Flow (CFS): 10
Quantity and Type of Turbines: 1-Francis Reaction
Installed Capacity (kW): 36
Average Annual Hydroelectric Production (mWh): 124
Average Annual Plant Factor: 0. 39
1990 Annual Demand (mWh): 154
Environmental Constraints:
grayling are present.
sites in vicinity.
Whitefish and arctic
Known prehistoric
Cost:
Item Unit
1 10'x300' diversion L.S.
2 Canal and Flume ft.
3 Penstock ft.
4 Turbine, Gener-
ator, Valves,
Switchgear kW
5 20'x20' Power-
house sq. ft.
6 Transmission
Line mi.
7 Winter Haul Road mi.
8 Mobilization, Demobilization,
Contractor's Profit @ 30%
Q!Y.
1
0
4800
36
400
23
1. 3
9 Geographic Index Factor, 0.90
Cost/Unit
489,900
56
900
120
40,000
20,000
Subtotal
Subtotal
Total Construction Cost
10 Contingencies @ 20%
11 Planning and Engineering @ 16%
TOTAL PROJECT COST
-299 -
Cost
($1000)
489.9
0
268.8
32.4
48.0
920.0
26.0
1785.1
535.5
2320.6
2088.5
4409.1
881.8
705.5
5996.4
White Mountain
6.7.22 White Mountain
6. 7. 22.1 Location:
Latitude: 64°41'N
Longitude: 163°24'W
6.7.22.2 Community Description:
There are 22 homes in the village. Sanitation is taken
care of by a PHS washeteria. There is not a high
school, but one should be constructed as part of the
Hootch settlement.
6. 7. 22.3 Population (Year-round):
1980: 112
2000: 166
2030: 302
6.7.22.4 Economic Base:
The economy of White Mountain is subsistence, reindeer
herding, and commercial fishing. Many residents move
to Golovin for summer employment in fishing and fish
processing.
6. 7. 22.5 Existing Electric Power Equipment:
Utility: School
Generators:
Capacity:
Peak Demand:
Diesel
1 X 50 kW + 2 X 125 kW ::: 300 kW
20 kW
-300 -
6.7.22.6 Projected Electrical Demands:
1980: 60 mWh/yr
1990: 436 mWh/yr
2000: 545 mWh/yr
2030: 980 mWh/yr
6. 7. 22.7 Potential Growth Factors:
No new housing is scheduled for White Mountain, nor
any other developments.
6. 7.22.8 Land Use:
Regional Native Corporation
6.7.22.9 Hydropower Plan (Figure 6.7.9-1):
lntertie with Golovin. See Section 6. 7. 9. 9, Golovin, for
a more detailed description.
-301 -
Village of White Mountain
Diesel Generator at White Mountain.
Building Houses One 50kW and Two 125kW Units
-302 -
6.8 PRESENT VALUE OF HYDROPOWER
The purpose of this section is to compare the present value of
hydroelectric energy produced by each of the projects described
in Section 6. 7 to the present value of the cost of construction of
the project and its associated operation and maintenance.
6.8.1 Secondary Screening
It is apparent in Section 6. 7 that the estimated construc-
tion cost is quite high compared to the amount of energy
produced by the hydroelectric facility. This is com-
pounded by the assumed operation of the facility only
during the ice-free season. Plant factors as low as 20
percent have been computed.
Since the hydroelectric facility will operate only six
months a year, a diesel generator system must be con-
structed and maintained to meet the electrical demand
during the remaining six months of higher electrical use.
Additionally, none of the hydro projects presented can
be relied upon to provide the electrical requirements of
the community from May through October all the time.
Thus, the diesel-generator system must be operated to
meet peak loads not met by hydro during the hydro-use
season.
Because of the operation of the hydro facility during the
six lowest demand months per year, the maximum benefit
each hydroelectric facility could provide over a 50-year
period is less than half of the present value of the
entire energy demand over that period. Table 6.8.1.1
lists each hydropower plan, its cost, and half of the
present value of all future energy demands for the com-
-303 -
munity served, assuming a 5 percent fuel cost escala-
tion. The present value of future energy was extracted
from Table 5.3.1.
As shown in Table 6.8.1.1, only 7 hydropower plans
have maximum potential benefit to cost ratios greater
than 1.0. Only these plans are analyzed for their true
present value in the next section.
-304 -
TABLE 6.8.1.1
MAXIMUM POTENTIAL PRESENT VALUE
OF HYDROPOWER PROJECTS
Community Served
Allakaket
Allakaket & Alatna
Allakaket & Alatna
Ambler
Anaktuvuk Pass
Bettles
Brevig Mission
& Teller
Brevig Mission
& Teller
Brevig Mission
& Teller
Buckland
Elim
Elim
Elim
Elim
Galena
Golovin
Golovin
Golovin
Hydropower Plan Description PV 1
Unnamed Stream South of 5.20
Allakaket
Unnamed Stream Northwest of 5.69
of Alaska
Both Unnamed Streams 5.69
East Fork Jade Creek 1.61
lnukpasugruk Creek 6.30
Jane Creek 4. 77
Don River 3. 68
Right Fork Bluestone River 3. 68
Main Stem Bluestone River, 3.68
Below Nome -Teller Road
Hunter Creek 4.36
Creek at Elim 2.53
Quiktalik Creek 2.53
Creek at Elim & Quiktalik Creek 2.53
Creek at Elim, Quiktalik Creek, 2.53
and Peterson Creek
Kala Creek 10.74
East Tributary to Cheenik Creek 2.67
East Tributary and Upper 2.67
Cheenik Creek
East Tributary & Upper Cheenik 2.67
Creek same powerhouse and
penstock
Cost2
3.55
3.80
7.36
4.01
4.69
5.45
9.41
4.73
5.77
12.47
2.75
3.32
5.55
8.07
15.86
4.22
7.47
8.10
Ratio3
1.46*
1.50*
0. 77
0.40
1.34*
0.88
0.39
0.78
0.64
0.35
0.92
0.76
0.46
0.31
0.68
0.63
0.36
0.33
* 1
Hydropower plans analyzed for their actual present value in Section 6.8.2.
SO% of present value of future energy produced by existing method of
power generation with 5% fuel cost escalation ($1,000,000).
2 Total hydro project cost estimate ($1,000,000).
3 Maximum present value project cost ratio.
-305 -
TABLE 6.8.1.1
Continued
MAXIMUM POTENTIAL PRESENT VALUE
OF HYDROPOWER PROJECTS
Community Served Hydropower Plan Description PV 1
2.67
4.04
Golovin Eagle Creek
Golovin and Eagle Creek
White Mountain
Golovin
Hughes
Hughes
Kaltag
Kaltag
Kaltag
Kiana
Kobuk and
Shungnak
Koyukuk
Manley Hot
Springs
Nome
Nome
Nome
Nome
Nulato
West Tributary of Kwiniuk River 2.67
Two Creeks West of Hughes 1. 00
Creek Northwest of Hughes 1. 00
South Tributary of Kaltag River 1. 91
North Tributary of Kaltag River 1. 91
South & North Tributaries of 1. 91
Kaltag River
Canyon Creek 3.02
Dahl Creek 2.35
East Tributary to Nulato River 3.48
McCloud Ranch Creek 1.20
Penney River 46.03
Osborn Creek 46.03
Buster Creek and Osborn Creek 46.03
Osborn Creek, Buster Creek,
Basin Creek, Alfield Creek &
David Creek
West Unnamed Tributary to
Nulato River
46.03
2.68
Cost2
5.43
8.52
5.45
3.40
3.43
4.79
4.81
7.76
4.70
2.95
7.79
1.32
4.24
5.43
7.52
12.47
6.58
Ratio 3
0.49
0.47
0.49
0.29
0.29
0.40
0.40
0.25
0.64
0.80
0.45
0.91
10.86*
8.48*
6.12*
3.69*
0.41
*
1
Hydropower plans analyzed for their actual present value in Section 6.8.2
50% of present value of future energy produced by existing method of
power generation with 5% fuel cost escalation ($1 ,000,000).
2 Total hydro project cost estimate ($1,000,000).
3 Maximum present value project cost ratio.
-306 -
TABLE 6.8.1.1
Continued
MAXIMUM POTENTIAL PRESENT VALUE
OF HYDROPOWER PROJECTS
Communi!:>::: Served H:>:::droEower Plan DescriEtion PV 1
Nulato and East and West Unnamed Tribu-6.16
Koyukuk taries to Nulato River
Point Hope Akaluk Creek 4.94
Shungnak and Cosmos Creek 2.35
Kobuk
Tanana Bear Creek 3.18
Tanana Jackson Creek 3.18
Tanana Bear Creek and Jackson Creek 3.18
Wales Kanauguk River 0.59
White Mountain Eagle Creek 4.04
and Golovin
Cost 2 Ratio 3
14.98 0. 41
11.27 0.44
4.03 0.58
5. 11 0.62
4.06 0.78
9.17 0.35
6.00 0.10
8.52 0.47
*
1
Hydropower plans analyzed for their actual present value in Section 6. 8. 2
50% of present value of future energy produced by existing method of
power generation with 5% fuel cost escalation ($1, 000 ,000).
2 Total hydro project cost estimate ($1 ,000,000).
3 Maximum present value project cost ratio.
-307 -
6.8.2 Present Value of Hydroelectric Energy at Selected Com-
munities
As exhibited in Table 6. 8.1.1, only the communities of
Allakaket, Alatna, Anaktuvuk Pass, and Nome have run-
of-river hydropower sites in their vicinity which are
potentially economical to construct. The purpose of this
section is to assess their true economic value.
The value of constructing the proposed hydropower
plans is derived from the reduction in the community•s
diesel electric system fuel consumption and operation and
maintenance. The present value of fuel displacement and
operation and maintenance reduction by each hydropower
plan passing the second stage screening was computed
and is shown in Table 6.8.2.1.
The present value of fuel displaced by the hydropower
project was computed by reviewing reconnaissance sur-
vey information, published data, and previous studies to
estimate the November, 1980 cost of diesel fuel. Assum-
ing a diesel generator efficiency of 10 kWh/gal.
(12.5 kWh/gal. for Nome), the cost per kWh of diesel-
generation electricity was computed. Added to this cost
was an assumed cost of lubricants equal to 10 percent of
the fuel cost. The average annual hydropower produc-
tion was multiplied by the cost of diesel fuel and lubri-
cants, escalated at 0, 2 and 5 percent annually, and
discounted at 7-3/8 percent annually over a 50-year
period to determine the present value of displaced fuel.
In addition to displaced fuel and lubricant costs, the
benefit of reduced operation and maintenance costs was
estimated. Diesel generator operation costs were
assumed to be $30,000 labor per year. Maintenance
-308 -
costs were computed at 5 percent of the diesel generator
capital cost. The capital cost was estimated to be $575
per kW peak 1990 demand. Both the estimated annual
operation and maintenance costs were multiplied by the
ratio of 1990 hydropower production to 1990 electrical
demand to compute the average annual savings in opera-
tion and maintenance costs attributed to the hydropower
project. Assuming zero escalation rate and 7-3/8 per-
cent discount rate, the present value of reduced opera-
tion and maintenance costs was determined.
-309 -
Community
w Allakaket
_.
0
Allakaket
& Alatna
Anaktuvuk
Pass
Nome
Nome
Nome
Nome
TABLE 6.8.2.1
PRESENT VALUE OF FULE DISPLACEMENT AND OPERATION MAINTENANCE REDUCTION
BY EACH HYDROPOWER PLANT PASSING THE SECOND STAGE SCREENING
Present Value Total
of Displaced Fuel Present
and Lubricants Present Value Value Estimated
Assumed 1980 ($1,000,000) of Reduced at 5% Fuel Project
Fuel Cost Escalation: 0 & M Costs Escalation Cost
Stream(s) ($/kWh) O% 2% 5% ($1,000,000) ($1,000,000) ($1,000,000)
Unnamed Stream
South of Allakaket 0.230 0.96 1.24 2.05 0.13 2.18 3.55
Unnamed Stream
Northwest of Alatna 0.230 1 . 11 1.45 2.38 0.12 2.51 3.80
lnukpasugruk
Creek 0.180 2.38 3.94 5.11 0.23 5.34 4.69
Penney River 0.094 1.13 1.47 2.42 0.15 2.57 4.24
Osborn Creek 0.094 2.49 3.24 5.34 0.29 5.63 5.43
Buster Creek and
Osborn Creek 0.094 2.78 3.62 5.95 0.33 6.28 7.52
Osborn, Buster,
Basin, Alfield, David 0.094 3.75 4.89 8.05 0.44 8.49 12.47
Ratio of
Present
Value
at 5% Fuel
Escalation)/
(Estimated
Construe-
tion Costs)
0.61
0.66
1.14
0.61
1.04
0.84
0.68
CONCLUSIONS AND RECOMMENDATIONS
7.0 CONCLUSIONS AND RECOMMENDATIONS
Of the fifty communities in northwest Alaska investigated for small
hydroelectric power potential, only the communities of Allakaket,
Alatna, Anaktuvuk Pass, and Nome have potentially economical sites
in their vicinity. Of these, only the sites at lnukpasugruk Creek
near Anaktuvuk Pass and near Nome offer the potential of producing
energy over the next SO years at a present value in excess of the
cost of constructing the hydroelectric facilities, assuming a 5 percent
annual fuel cost escalation rate and a discount rate of 7-3/8 percent.
It is important to note that these conclusions are based on two major
assumptions: (1) the primary component of skilled labor hired to
build the facilities will be imported to the community 1 and (2) diver-
sion structures will be expensive to build. If a community could
adopt a type of "self-help" program which would significantly reduce
the reliance on imported labor, construction costs could be lowered as
much as 40 percent. Table 7.1 was prepared to show those commun-
ities which might have economical hydropower sites if construction
costs could be reduced 40 percent.
The second important assumption 1 expensive diversion structures, was
made due to unknown foundation, permafrost, and earth borrow area
conditions at each community. The estimated construction costs are
based on a concrete diversion structure with imported cement and re-
inforcing steel. If local sources of acceptable earth fill and shallow,
competent foundation bedrock are present, the diversion structure
costs could be significantly reduced. Table 7. 2 was prepared to show
those communities which might have economical hydropower sites if
diversion structure construction costs were eliminated.
It is recommended that the communities listed in Table 7.1 be studied
for possible development of political, legal and institutional frame-
works which would reduce reliance on imported skilled labor. The
Alaska Regional Native Corporations appear to be ideally suited for
developing such 11 self-help 11 arrangements.
-311 -
It is further recommended that reconnaissance geotechnical investiga-
tions be performed at the hydropower sites listed in Table 7 .2. The
information gathered from these investigations should be used to pre-
pare site specific conceptual designs of diversion structures. New
diversion structure construction cost estimates should be developed if
it appears that estimates in this study are high.
If diversion structure construction costs can be reduced, the poten-
tial benefit to cost ratio of the hydropower project should be re-eval-
uated. Similarly, if reliance on expensive imported labor can be
significantly reduced 1 the hydropower project economics should be
re-evaluated.
Finally, it is recommended that a feasibility study of small hydropower
sites in the vicinity of Anaktuvuk Pass and Nome be initiated. Al-
though the combined hydroelectrical potential of the sites around
Nome identified in this study is only 10 percent of Nome's project
1990 annual electrical demand, the savings in displaced diesel fuel and
operation and maintenance appears to economically justify construction
of these facilities. A larger hydropower project, involving a low dam
across the Nome River 1 which was studied by General Electric in
1979, also appears to warrant further study.
-312 -
TABLE7.1
COMMUNITIES WITH POTENTIALLY ECONOMICAL HYDROPOWER
SITES IF CONSTRUCTION COSTS ARE REDUCED BY 40%
Community
Allakaket
Allakaket
& Alatna
Allakaket
& Alatna
Bettles
Brevig
Mission &
Teller
Brevig
Mission &
Teller
Elim
Elim
Galena
Golovin
Kiana
Kobuk &
Shungnak
Manley Hot
Springs
Tanana
Tanana
(Maximum Present Value)/
(Project Cost) Ratio,
before 40% Construction
Stream Cost Reduction
Unnamed Stream
South of Allakaket 0. 61 **
Unnamed Stream
Northwest of Alatna
Both Unnamed
Streams
Jane Creek
Right Fork Bluestone
River
Main Stem Bluestone
River, below Nome-
Teller Road
Creek at Elim
Quiktalik Creek
Kala Creek
East Tributary to
Cheenik Creek
Canyon Creek
Dahl Creek
McCloud Ranch
Creek
Bear Creek
Jackson Creek
0.66 **
0.77 *
0.88*
0.78 *
0.64 *
0.92*
0.76*
0.68*
0.63*
0.64*
0.80*
0.91*
0.62*
0.78*
* From Table 6.8.1.1
** From Table 6.8.2.1
-313 -
Ratio after
40% Construction
Cost Reduction
1 .02
1.10
1.28
1.47
1.30
1.06
1.53
1.27
1.13
1.05
1.07
1.33
1. 52
1.03
1.30
TABLE 7.2
COMMUNITIES WITH POTENTIALLY ECONOMICAL HYDROPOWER
SITES IF DIVERSION STRUCTURE COSTS ARE ELIMINATED
Project Cost Project Cost (Maximum
w/Diversion w/o Diversion Present Value)/
Structure Structure (Project Cost)
Community Stream ($ Million) ($ Million) Ratio
Allakaket Unnamed Stream
South of Allakaket 3.55 1.86 1.17
Allakaket Unnamed Stream
& Alatna Northwest of Alatna 3.80 2.40 1.05
Allakaket Both Unnamed
& Alatna Streams 7.36 4.26 1.34
Bettles Jane Creek 5.45 4.75 1.00
Elim Creek at Elim 2.53 0.74 3.40
Elim Quiktalik Creek 2.53 2.27 1 . 11
Manley Hot McCloud Creek
Springs 1.32 1.12 0.93
Tanana Bear Creek 5.11 3.15 1. 01
-314 -
BIBLIOGRAPHY
Bl BLIOGRAPHY
Continued
Mauneluk Association, Inc., 1980. NANA Region Overall Economic Develop-
ment Plan Update.
Norton Sound Health Corporation, 1980. Long Range Health Plan 1980-1984.
Policy Analysts, LTD, June 1980. Alaska OCS Socioeconomics Studies Pro-
gram. Prepared by Peat, Marwick, Mitchell and Company for Bureau
of Land Management Alaska Outer Continental Shelf Office.
U.S. Army Corps of Engineers. Alaskan Communities Flood Hazard and
Pertinent Data. Flood Plain Management Services Program E-590.
U.S. Army Corps of Engineers, July, 1980. Regional Inventory and Recon-
naissance Study for Small Hydropower Projects Aleutian I stands,
Alaska Peninsula, Kodiak Island, Alaska. Draft Report. Contract
No. DACW85-80-C-0004.
U.S. Army Corps of Engineers, October 1979. Regional Inventory and
Reconnaissance Study for Small Hydropower Sites in Southeast Alaska.
Contract No. DACW85-79-C -0030.
U.S. Army Corps of Engineers, The Hydrologic Engineering Center, July
1979. Feasibility Studies for Small Scale Hydropower Additions. A
Guide Manual.
U.S. Bureau of Census, 1975. Bering Strait Regional Census.
U.S. Department of Energy, March 1980. Small Hydroelectric Workshop.
U.S. Department of Energy, Alaska Power Administration, December 1979.
Small Hydroelectric Inventory of Villages Served by A. V. E. C. for
Alaska Village Electric Cooperative.
U.S. Department of Interior, Alaska Power Administration, July 1975. A
Regional Electric Power System for the Lower Kuskokwim Vicinity.
U.S. Bureau of Land Management, Alaska Outer Continental Shelf Office,
June 1980. Alaska OCS Socioeconomic Studies Program Bering-Norton
Petroleum Development Scenarios Economic and Demographic Analysis.
Technical Report No. 50.
U.S. Bureau of Land Management, Alaska Outer Continental Shelf Office.
Bering-Norton Petroleum Development Scenarios Local Socioeconomic
Systems Analysis, Technical Report No. 53.
University of Alaska, 1976. Alaska Regional Profiles, Northwest Region.
University of Alaska, 1980. Comprehensive Publication List. Institute of
Social Aid and Economic Research.
BIBLIOGRAPHY
State of Alaska, 1980. Preliminary Annual Report 1980, State Aid to Local
Governments, Municipal Services Revenue Sharing Program.
State of Alaska -Coastal Management, January 1980. Alaska Coastal Bib-
liography and Index, Region A, Northwest Alaska.
State of Alaska -Coastal Management, January 1980. Alaska Coastal Bibli-
ography and Index, Region B, Bering Straits.
State of Alaska -Coastal Management, December 1979. Bibliography of Pro-
ducts, Program Office of Coastal Management.
Alaska Department of Commerce and Economic Development, February 1980.
1980 Alaska Power Development Plan, Draft Final Report, Volume II,
Division of Engergy and Power Development.
Alaska Department of Commerce and Economic Development, April 1979. A
Discussion of Considerations Pertaining to Rural Energy Policy Op--
tions, Arthur Young & Company.
Alaska Department of Commerce and Economic Development, 1979. Commun-
ity Energy Survey, Division of Energy and Power Development.
State of Alaska Department of Commerce and Economic Development, June
1978. Waste Heat Capture Study, Division of Energy and Power
Development.
Alaska Department of Community and Regional Affairs, March 1980. State
Aid to Local Governments Municipal Services Revenue Sharing p,::o:--
gram, Division of Local Government Assistance, Fiscal Year 1980.
Alaska Department of Environmental Conservation 1 1980. Village Sanitation
in Alaska, Village Safe Water Program Update.
Alaska Department of Transportation and Public Facilities, 1979 and 1980.
Western and Arctic Alaska Transportation Study.
Alaska Power Authority, June 1980. Assessment of Power Generation Alter-
natives for Kotzebue, Prepared by Robert W. Retherford Associates.
Alaska Power Authority, April 1980. Electric Power Generation Alternatives
Assessment for Nome, Alaska, Prepared by General Electric.
Arctic Environmental Information and Data Center, 1975. Community
Profiles.
Kawerak, Inc., 1980. Bering Straits Region Overall Economic Development
Plan.
APPENDICES
APPENDIX A
COST INDICES
1.0 GEOGRAPHIC COST INDEX
1 .1 OVERVIEW
A geographic construction cost index is required to aid the cost
estimating process to establish the varying costs of the hydroelec-
tric schemes for the different locations included in this study.
There is nothing finite or absolute about construction costs, and
because the construction of each hydroelectric project will be a cus-
tom design, there are inevitable problems in accurately measuring
price changes occurring over time or from place to place. How-
ever, there are a number of locational related factors that influence
construction costs, some of which are applicable to the project and
are in the following basic categories:
0
0
0
Labor Costs
Material Costs
Climatic Considerations
1. 2 LABOR COSTS
Labor rates vary in the State of Alaska, however, as all the proj-
ects to be reviewed are in an area north of Latitude 63N, basic
labor rates and fringe costs do not vary for each skill classification
and are published by the Department of Labor (latest edition June
1st, 1980).
Productivity is affected by working conditions and the degree of
automation. The latter is partly a matter of design and contractors'
sophistication and as such is difficult to qualify. Working condi-
tions fall into two categories --climatic and site conditions. Since
A -1
all the projects are near the Arctic Circle and are mostly remote
these conditions are considered equal for each location.
The local labor pool in the areas of the study are both small and
sometimes lacking in certain skills (electrical and mechanical trades
especially). It is therefore necessary to encourage labor to come
from the major centers, Fairbanks and Anchorage. This will re-
quire inducements and additional costs for such items as overtime
payments, rest and recreation ( R&R) allowances, and bonuses.
This is also true of Nome, which has a population of nearly 2, 900
people, however still has an insufficient labor pool for larger con-
struction programs.
It will therefore be necessary to provide construction camps and
provide per diem payments for this incoming labor force. As none
of the locations have sufficient existing facilities, a campsite would
be necessary for the duration of the construction project.
1.3 MATERIAL COSTS
The basic economic laws of supply and demand prevail in the pur-
chase of material. For the most part manufactured material costs do
not vary greatly from one part of the State to another. For
example, light fixtures vary little in cost from place to place as is
the case with most manufactured products used in the construction
industry that were not bulky or heavy and relatively easy to trans-
port. These products are, however, subject to national market
trends.
Basic construction materials such as concrete, timber, blocks, etc.,
are subject to great variations depending on the location. The
availability of concrete, gravel and other materials have a direct
impact on cost. Indeed in some areas, alternative materials may be
considered or used.
A - 2
The mode of transportation will effect the total cost dramatically.
Sites that are easily accessible by either sea or road have the
advantage over sites that need air freight transportation.
1.4 CLIMATE CONDITIONS
By its very nature the construction industry is affected by climatic
elements. This is especially true in Alaska. Many productive days
are lost as a result of bad weather 1 both for reasons of delayed
shipments of materials and reducing production. In these climates
careful planning is required to insure that projects can maintain the
optimum production using both winter and summer conditions to
achieve the best production rates possible. Needless to say 1 the
reduced natural light in the winter months has a negative impact on
productivity 1 as well.
The basic facts are that construction costs increase in colder cli-
mates as a result of lost production 1 weather delays and heating,
snow clearing and lighting requirements. Projects tend to take
longer to build and require a greater concentration of effort, plan-
ning and scheduling.
A - 3
2.0 LABOR COSTS
2.1 BASIC COST (Rate + Fringes and benefits
taxes and insu ranees)
Average = $33.00/per hour
40 hour week @ $33.00 = $1,320.00
2.2 REGULATORY CHARGE N/A
(All above Latitude 63°)
2.3 OVERTIME ALLOWANCES
A.) Allakaket, Anaktuvuk Pass, Bettles,
Brevig Mission, Buckland, Galena,
Golovin, Hughes, lgnalik, Kobuk,
Koyokuk, Tanana, White Mountain
6 days, 12 hours per day
Total 72 hours.
Overtime Costs (22 hours @ $33.00) :::: $ 726.00
B.) Nome, Manley Hot Springs:
6 days 10 hours per day
Total 60 hours.
Overtime (15 hours x $33.00) $ 495.00
2.4 CAMP COSTS + PER DIEM ALLOWANCE
Category 2.3A above:
7 days @ $135 per day :::: $ 945.00
Nome.
7 days @ $100 per day $ 700.00
Manley Hot Springs
6 days @ $80 per day $ 480.00
2.5 TRAVEL COSTS
(Airfare plus time in travel plus R&R,
assuming an 8-week work period and one
week R&R per employee)
Allakaket:
$148 + 2 (2 hours @ 33.00) + $1,320 = $ 200.00 8 weeks
Anaktuvuk Pass:
$230 + 2 (3 hours @ 33.00) + $1,320 = $ 218.50 8 weeks
A - 4
Bettles:
$148 + 2 (2 hours@ 33.00) + $1,320 =
8 weeks
Brevig Mission:
$440 + 2 (5 hours@ 33.00) + $1,320 =
8 weeks
Buckland:
$346 + 2 (5 hours@ 33.00) + $1,320 =
8 weeks
Galena:
$152 + 2 (3 hours@ 33.00) + $1,320 =
8 weeks
Golovin:
$350 + 2 (6 hours@ 33.00) + $1,320 =
8 weeks
Hughes:
$252 + 2 (5 hours@ 33.00) + $1,320 =
8 weeks
lgnalik:
$515 + 2 (16 hours@ 33.00) + $1,320 =
8 weeks
Kobuk:
$386 + 2 (8 hours@ 33.00) + $1,320 =
8 weeks
Koyukuk:
$192 + 2 (5 hours@ 33.00) + $1,320 =
8 weeks
Manley Hot Springs:
$62 + 2 (1 hour@ 33.00) + $1,320 =
8 weeks
Nome:
$252 + 2 (4 hours@ 33.00) + $1,320 =
8 weeks
Tanana:
$72 + 2 (2 hours@ 33.00) + $1,320 =
8 weeks
White Mountain:
$350 + 2 (6 hours@ 33.00) + $1,320 =
8 weeks
A - 5
$ 200.00
$ 261.25
$ 249.50
$ 225.25
$ 258.25
$ 237.75
$ 361.38
$ 279.25
$ 230.75
$ 16.00
$ 229.50
$ 190.50
$ 258.25
2. 5.1 Air Travel
Name From Distance Cost Airport
Allakaket Via Fairbanks 190 miles $148 2
Anaktuvuk Pass Via Fairbanks 250 miles $230 2
Bettles Via Fairbanks 180 miles $148 1
Brevig Mission Via Nome 70 miles $440* 2
Buckland Via Kotzebue 70 miles $346 2
Galena Via Fairbanks 280 miles $152 1
Golovin Via Nome 70 miles $350 2
Hughes Via Galena 120 miles $252 2
lgnalik Via Nome+ Wales 140 miles $515* None
Kobuk Via Kotzebue 150 miles $386 2
Koyukuk Via Galena 30 miles $196 2
Manley Hot Springs Via Fairbanks 90 miles $ 62 1
Nome Via Fairbanks 492 miles $252 1
Tanana Via Fairbanks 140 miles $ 72 1
White Mountain Via Nome 60 miles $350 2
2.5.2 Notes
Cost = Airfare roundtrip economy from Fairbanks September 10, 1980
Airport 1 = Good Quality; Airport 2 = Second Quality
Kotzebue 423 miles from Fairbanks.
Limited servcies to all locations other than Nome.
*Charter cost from Nome added to basic fare.
A - 6
2. 5. 3 Charter Costs
Brevig Mission 70 miles from Nome. Allow 2 hour round trip plus
half hour ground time.
2~ hours @ $150/hour = $375.00
A !low 2 seats used: cost per passenger $187. 50.
lgnalik 140 miles from Nome. Use of skiplane in the winter only.
Three hour round trip plus half hour ground time.
3\ hours @ $150/hour = $525.00
Allow 2 seats used: cost per passenger of $262.50.
Transportation not directly available during the summer; trips have
to be arranged through Wales by air and from there by boat to the
island. Assume similar costs as winter transportation system.
2.6 POPULATION/WORK FORCE RATIO
Assuming that a total of twenty-five operatives are required on the
project in an average week (peaking at forty). The local village
work force will normally be able to supply 20 percent of its total
work force. The remainder will be involved in other pursuits for
certain times of the year. However, the village may supply more
workers at the construction peak period or at another convenient
times.
The following example is for Allakaket, where there is a total of 21
workers. Normally, four workers will be employed on the project,
peaking at as many as ten. Assuming the normal work force will
work 66-2/3 percent of the time, while the peak work force works
33-1/3 percent of the time, an average six workers will be avail-
A -7
2. 6.1
able, or 19 percent of the total required. This fraction is adjusted
for Nome and larger projects to a maximum of 50/50.
Population Data
Approximate Estimate Labor Force
Name Population Laborers Carpenters Crafts
Allakaket 216 13 6 2
Anaktuvuk Pass 173 10 5 1
Bettles 90 5 2 0
Brevig Mission 147 9 4 1
Buckland 170 10 5 1
Galena 957 57 25 10
Goloviu 118 5 2 0
Hughes 98 5 2 0
lgnalik 125 5 2 0
Kobuk 61 3 1 0
Koyokuk 124 5 2 0
Manley Hot Springs 50 3 1 0
Nome 2,892 110 50 30
Tanana 499 30 15 5
White Mountain 115 5 2 0
Population climates for State of Alaska Department of Community and
Regional Affairs Estimates of Community and Regional Affairs. Esti-
mates of Labor force a subjective assessment based on Alaskan Vil-
lage names.
A -8
3.0 MATERIALS AND EQUIPMENT
Other than site specific materials such as gravel, which will have to
be analyzed on a site by site basis, all other materials will be im-
ported. The cost of transportation of these materials will vary
according to difficulty of access.
Therefore only transportation cost deltas will be considered for the
index. The following is a summary of the most economic mode of
transportation for the sites:
0
0
0
Sea + Lighterage: for Brevig Mission, Golovin, lgnalik and
Nome.
Road and Rail for Manley Hot Springs.
Air freight for all other locations.
A -9
3.1 TRANSPORTATION COSTS
3.1.1 Basic Costs. Barge to Anchorage and rail to Fairbanks (Assuming
40,000 lb. loads).
Barge to Anchorage
Rail to Fairbanks
3.1. 2 Sea & Lighterage:
9¢
6¢
Barge to Northern Port 11¢
Lighterage 5¢
3.1.3 Road+ Rail:
Basic Cost plus
90 miles 20 tons ($500)
($6,000 + $500)
3.1.4 Air From Anchorage:
Barge to Anchorage 9¢
40,000 lb. load Air ($12,000)
A -10
$ 6,000
$ 6,400
$ 6,500
$15,600
Name
Allakaket
Anaktuvuk Pass
Bettles
Brevig Mission
Buckland
Galena
Golovin
Hughes
lgnalik
Kobuk
Koyukuk
Manley Hot Springs
Nome
Tanana
White Mountain
* Not feasible access.
Cll Winter road
Airstrip River Road Sea --
X x*
X XCII
X x* XCII
X X
X x*
X X
X X
X x*
i1l X
X x*
X x*
X x* X
X X
X x*
X
i1l lgnalik Landing with small planes only by ski in the winter only.
All sea accessable sites require lighterage from the barge to the port.
A -11
4.0 CLIMATIC CONDITIONS
All locations experience severe cold conditions in the winter months.
It is normal for days to be lost owing to bad weather. Also, in the
winter months for 90 days there is no natural light. This will nor-
mally cause a project to shut down or experience expensive tem-
porary installation costs.
Alternatively, the long days in summer months allow work to con-
tinue, if necessary, 24 hours a day. This of course has a cost
effect but schedules can be produced to minimize the cost impact.
As Fairbanks is the base for this index and the index will be in a
percentage form, the cost effect will be equal to the base, and
therefore non-effective in the geographic index.
A -12
5.0 ADJUSTMENT (LABOR/MATERIAL RATIO)
A basic rule of thumb for construction costs is that labor repre-
sents 60 percent of all costs, and material 40 percent. This can be
verified by a review of construction cost data in various publica-
tions.
For the purpose of this study we shall assume these ratios. How-
ever, we have established that material costs will be affected only
by the transportation element of the material cost. It is assumed
that transportation is one third of the material cost.
Therefore we have a ratio as follows:
A II Labor Costs 60%
Material & Equipment Basic Cost 27%
Transportation of Materials 13%
Total 100%
A -13
6.0 GEOGRAPHIC INDEX
Name Index
Allakaket 1. 95
Anaktuvuk Pass 2.02
Bettles 2.04
Brevig Mission 1.83
Buckland 2.03
Galena 1. 81
Golovin 1.87
Hughes 2.06
lgnalik 2.11
Kobuk 2.08
Koyukuk 2.06
Manley Hot Springs 1.35
Nome 1.35
Tanana 1.88
White Mountain 2.07
(Fairbanks Base 1.00.)
A -14
6.1 PLACE: Allakaket
6. 1. 1 Labor Costs Local
Basic Cost 1,320
Regulatory N/A
Overtime Allowance 726
Camp + Perdiem N/A
Travel Cost N/A
Subtotal 2,046
Workforce Ratio 6
Total Weekly Cost 12,276
Average Cost per worker/week
Index factor (Base $1,320)
6.1.2 Materials
Material Costs Unchanged
6.1.3 Transportation Costs = $15,600
Index factor (Base $6,000)
6.1.4 Climatic Conditions
None effective.
6.1.5 Adjustment (Labor/Material Ratio)
(60:27:13 Basis) 2.24:1.00:2.60
Index Factor
A -15
Imported
1,320
N/A
726
945
200
3,191
4
76,584
= $2,962
= 2.24
= 1.00
= 2.60
= 1. 95
6.2 PLACE: Anaktuvuk Pass
6. 2.1 Labor Costs Local
Basic Cost 1,320
Regulatory N/A
Overtime Allowance 726
Camp + Perdiem N/A
Travel Cost N/A
Subtotal 2,046
Workforce Ratio 3
Total Weekly Cost 6,438
Average Cost per worker/week
Index factor (Base $1,320)
6.2.2 Materials
Material Costs Unchanged
6. 2. 3 Transportation Costs = $15,600
Index factor (Base $6,000)
6. 2. 4 C I imatic Conditions
None effective.
6.2.5 Adjustment (Labor/Material Ratio)
(60:27:13 Basis) 2.35:1.00:2.60
Index Factor
A -16
Imported
1,320
N/A
726
945
219
3,210
27
86,670
= $3,104
= 2.35
= 1.00
= 2.60
= 2.02
6.3 PLACE: Bettles
6.3.1 Labor Costs Local
Basic Cost 1,320
Regulatory N/A
Overtime Allowance 726
Camp + Perdiem N/A
Travel Cost N/A
Subtotal 2,046
Workforce Ratio 1
Total Weekly Cost 2,046
Average Cost per worker/week
Index factor (Base $1,320)
6.3.2 Materials
Material Costs Unchanged
6.3.3 Transportation Costs = $15,600
Index factor (Base $6,000)
6.3.4 Climatic Conditions
None effective.
6.3.5 Adjustment (Labor/Material Ratio)
(60:27:13 Basis) 2.39:1.00:2.60
Index Factor
A -17
Imported
1,320
N/A
726
945
200
3,191
29
92,539
= $3,153
= 2.39
= 1.00
= 2.60
= 2.04
6.4 PLACE: Brevig Mission
6.4.1 Labor Costs Local Imported
Basic Cost 1,320 1,320
Regulatory N/A N/A
Overtime Allowance 726 726
Camp + Perdiem N/A 945
Travel Cost N/A 261
Subtotal 2,046 3,252
Workforce Ratio 3 27
Total Weekly Cost 6,138 87,804
Average Cost per worker/week = $3,131
Index factor (Base $1,320)
6. 4. 2 Materials
Material Costs Unchanged
6.4.3 Transportation Costs = $6,400
Index factor (Base $6,000)
6.4.4 Climatic Conditions
None effective.
6.4.5 Adjustment (Labor/Material Ratio)
(60:27:13 Basis) 2.37:1.00:1.07
Index Factor
A -18
= 2.37
= 1.00
= 1.07
= 1.83
6.5 PLACE: Buckland
6.5.1 Labor Costs Local
Basic Cost 1 ,320
Regulatory N/A
Overtime Allowance 726
Camp + Perdiem N/A
Travel Cost N/A
Subtotal 2,046
Workforce Ratio 3
Total Weekly Cost 6,138
Average Cost per worker/week
Index factor (Base $1,320)
6.5.2 Materials
Material Costs Unchanged
6.5.3 Transportation Costs = $15,600
Index factor (Base $6,000)
6.5.4 Climatic Conditions
None effective.
6.5.5 Adjustment (Labor/Material Ratio)
(60:27:13 Basis) 2.36:1.00:2.60
Index Factor
A -19
Imported
1,320
N/A
726
945
250
3,241
27
87,507
= $3,122
= 2.36
= 1.00
= 2.60
= 2.03
6.6 PLACE: Galena
6.6.1 Labor Costs Local Imported
Basic Cost 1,320 1 '320
Regulatory N/A N/A
Overtime Allowance 726 726
Camp + Perdiem N/A 945
Travel Cost N/A 225
Subtotal 2,046 3,216
Workforce Ratio 15 15
Total Weekly Cost 30,690 48,240
Average Cost per worker/week = $2,631
Index factor (Base $1,320) = 1. 99
6.6.2 Materials
Material Costs Unchanged = 1.00
6.6.3 Transportation Costs = $15, 600
Index factor (Base $6,000) = 2.60
6.6.4 Climatic Conditions
None effective.
6.6.5 Adjustment (Labor/Material Ratio)
(60:27:13 Basis) 1.99:1.00:2.60
Index Factor = 1. 81
A -20
6.7 PLACE: Golovin
6. 7.1 Labor Costs Local
Basic Cost 1,320
Regulatory N/A
Overtime Allowance 726
Camp + Perdiem N/A
Travel Cost N/A
Subtotal 2,046
Workforce Ratio 1
Total Weekly Cost 2,046
Average Cost per worker/week
Index factor (Base $1,320)
6.7.2 Materials
Material Costs Unchanged
6. 7. 3 Transportation Costs = $6,400
Index factor (Base $6,000)
6. 7. 4 Climatic Conditions
None effective.
6.7.5 Adjustment (Labor/Material Ratio)
(60:27:13 Basis) 2.43:1.00:1.07
Index Factor
A -21
Imported
1,320
N/A
726
945
258
3,249
29
94,221
= $3,209
= 2.43
= 1.00
= 1.07
= 1.87
6.8 PLACE: Hughes
6.8.1 Labor Costs Local Imported
Basic Cost 1,320 1,320
Regulatory N/A N/A
Overtime Allowance 726 726
Camp + Perdiem N/A 945
Travel Cost N/A 238
Subtotal 2,046 3,229
Workforce Ratio 1 29
Total Weekly Cost 2,046 93,641
Average Cost per worker/week = $3,190
Index factor (Base $1 , 320) = 2.42
6.8.2 Materials
Material Costs Unchanged = 1.00
6.8.3 Transportation Costs = $15,600
Index factor (Base $6,000) = 2.60
6.8.4 Climatic Conditions
None effective.
6.8.5 Adjustment (Labor/Material Ratio)
(60:27:13 Basis) 2.42:1.00:2.60
Index Factor = 2.06
A -22
6.9 PLACE: lgualik
6. 9.1 Labor Costs Local
Basic Cost 1,320
Regulatory N/A
Overtime Allowance 726
Camp + Perdiem N/A
Travel Cost N/A
Subtotal 2,046
Workforce Ratio 1
Total Weekly Cost 2,046
Average Cost per worker/week
Index factor (Base $1,320)
6.9.2 Materials
Material Costs Unchanged
6. 9. 3 Transportation Costs = $6,400
Add handling problems + delays,
a factor 1 . 50
Index factor (Base $6,000)
6.9.4 Climatic Conditions
None effective.
6.9.5 Adjustment (Labor/Material Ratio)
(60:27:13 Basis) 2.51:1.00:2.57
Index Factor
A -23
Imported
1,320
N/A
726
945
361
3,352
29
97,288
= $3,308
= 2.51
= 1.00
= 2.57
= 2.11
6.10 PLACE: Kobuk
6.10.1 Labor Costs Local
Basic Cost 1,320
Regulatory N/A
Overtime Allowance 726
Camp + Perdiem N/A
Travel Cost N/A
Subtotal 2,046
Workforce Ratio 1
Total Weekly Cost 2,046
Average Cost per worker/week
Index factor (Base $1,320)
6.10.2 Materials
Material Costs Unchanged
6.10.3 Transportation Costs = $15,600
Index factor (Base $6,000)
6.10. 4 Climatic Conditions
None effective.
6.10.5 Adjustment (Labor/Material Ratio)
(60:27:13 Basis) 2.45:1.00:2.60
Index Factor
A -24
Imported
1,320
N/A
726
946
279
3,270
29
94,830
= $3,229
= 2.45
= 1.00
= 2.60
= 2.08
6.11 PLACE: Koyukuk
6.11.1 Labor Costs Local
Basic Cost 1,320
Regulatory N/A
Overtime Allowance 726
Camp + Perdiem N/A
Travel Cost N/A
Subtotal 2,046
Workforce Ratio 1
Total Weekly Cost 2,046
Average Cost per worker/week
Index factor (Base $1,320)
6.11 . 2 Materials
Material Costs Unchanged
6.11.3 Transportation Costs = $15,600
Index factor (Base $6,000)
6.11.4 Climatic Conditions
None effective.
6.11.5 Adjustment (Labor/Material Ratio)
(60:27:13 Basis) 2.41:1.00:2.60
Index Factor
A -25
Imported
1,320
N/A
726
945
231
3,222
29
93,438
= $3,183
= 2.41
= 1.00
= 2.60
= 2.06
6.12 PLACE: Manley Hot Springs
6.12.1 Labor Costs Local Imported
Basic Cost 1,320 1,320
Regulatory N/A N/A
Overtime Allowance 495 495
Camp + Perdiem N/A 480
Travel Cost N/A 16
Subtotal 1,815 2,311
Workforce Ratio 1 29
Total Weekly Cost 1 ,815 67,019
Average Cost per worker/week = $2,294
Index factor (Base $1,320) = 1. 74
6.12.2 Materials
Material Costs Unchanged = 1.00
6.12.3 Transportation Costs = $6,500
Index factor (Base $6,000) = 1.08
6.12.4 Climatic Conditions
None effective.
6.12.5 Adjustment (Labor/Material Ratio)
(60:27:13 Basis) 1 . 7 4: 1 . 00 : 1 . 08
Index Factor = 1.35
A -26
6.13 PLACE: Nome
6.13.1 Labor Costs Local
Basic Cost 1,320
Regulatory N/A
Overtime Allowance 495
Camp + Perdiem N/A
Travel Cost N/A
Subtotal 1,815
Workforce Ratio 15
Total Weekly Cost 27,225
Average Cost per worker/week
Index factor (Base $1,320)
6.13.2 Materials
Material Costs Unchanged
6.13.3 Transportation Costs = $6,400
Index factor (Base $6,000)
6.13.4 Climatic Conditions
None effective.
6.13. 5 Adjustment (Labor/Material Ratio)
(60:27:13 Basis) 1.73:1.00:1.07
Index Factor
A -27
Imported
1,320
N/A
495
700
230
2,745
15
41,175
= $2,280
= 1.73
= 1. 00
= 1.07
= 1.35
6.14 PLACE: Tanana
6. 14.1 Labor Costs Local
Basic Cost 1,320
Regulatory N/A
Overtime Allowance 726
Camp + Perdiem N/A
Travel Cost N/A
Subtotal 2,046
Workforce Ratio 10
Total Weekly Cost 20,460
Average Cost per worker/week
Index factor (Base $1,320)
6.14.2 Materials
Material Costs Unchanged
6.14.3 Transportation Costs= $15,600
Index factor (Base $6,000)
6.14.4 Climatic Conditions
None effective.
6.14.5 Adjustment (Labor/Material Ratio)
(60:27:13 Basis) 2.12:1.00:2.60
Index Factor
A -28
Imported
1,320
N/A
726
945
191
3,182
20
63,640
:::: $2,803
= 2.12
= 1.00
= 2.60
= 1.88
6.15 PLACE: White Mountain
6. 15.1 Labor Costs Local
Basic Cost 1 ,320
Regulatory N/A
Overtime Allowance 726
Camp + Perdiem N/A
Travel Cost N/A
Subtotal 2,046
Workforce Ratio 1
Total Weekly Cost 2,046
Average Cost per worker/week
Index factor (Base $1,320)
6.15.2 Materials
Material Costs Unchanged
6.15.3 Transportation Costs = $15,600
Index factor (Base $6,000)
6. 15.4 Climatic Conditions
None effective.
6.15.5 Adjustment (Labor/Material Ratio)
(60:27:13 Basis) 2.43:1.00:2.60
Index Factor
A -29
Imported
1,320
N/A
726
945
258
3,249
29
94,221
= $3,209
= 2.43
= 1.00
= 2.60
= 2.07
APPENDIX B
NORTHWEST ALASKA HYDROPOWER
HYDROLOGIC EVALUDATION OF POTENTIAL HYDROPOWER SITES
All USGS records of continuous streamflow in the Yukon Basin, Northwest,
and Arctic slope of Alaska were examined for their value in determining
hydropower potential. These stations are summarized on Table 1. Ex-
cluded are streamflow records taken in the 1907-1912 period. These
records were excluded because they were very short (usually 1 to 3
years), incomplete (usually July through October only) and of unknown
reliability. These records are also all located on the Seward Peninsula,
where adequate recent records exist. They do indicate that a wide range
of summer flows (expressed as runoff per square mile) exist in the region
and these differences are not easily correlated with hydrologic features
derived from topographic maps. Based on these fragmentary records,
errors in summer flow estimates for ungaged hydropower sites could be up
to 50 percent.
Summarizing the notes from Table 1: there were 24 stations with adequate
records for use in the multiple regression analysis, 15 stations with re
cords less than 5 years, 6 stations on the Yukon River, and 18 stations
outside of the study area (they were located south and east of Fairbanks).
Tables 2 and 3 show the 50 percentile and 80 percentile mean monthly
flows (dependent variables) for the 24 station records used in the multiple
regression analysis. Table 4 shows the independent variables for these
drainage basins.
In the BCS multiple regression model, mean monthly 50 percentile and 80
percentile flows are dependent variables. The independent variables are
drainage area, main channel stope, mean basin elevation, area of forest,
mean annual precipitation, mean annual snowfall, and mean minimum Janu-
ary temperature. Drainage area is in square miles and is the area
enclosed by the drainage divides upstream from the measuring site. The
main channel slope is in feet per mile and is the mean slope between two
B - 1
points 10 percent and 85 percent of the way up the main channel length.
The mean basin elevation, in feet above mean sea level, is the mean eleva-
tion of the basin as determined from a topographic map. The area of
forest is the percentage of the basin area that is forested. Mean annual
precipitation and mean annual snowfall, in inches, are determined from a
National Weather Service isohyetal map (1972). The mean minimum January
temperature, in degrees Fahrenheit, is obtained from an isothermal map
(shown in Lamke, 1979). Values for the independent variables came from
either a USGS Water Resources Investigation Paper (Lamke, 1979) or from
measurements of topographic maps.
In the BCS model, each of the percentile monthly flows is separately re-
gressed against the independent variables. The resulting regression
equations can then be used to predict streamflows at ungaged sites.
Tables 5 and 6 show the regression equations derived fro this study.
The range of the independent variables are indicated in Table 7. Use of
numbers outside this range is not advisable as the regression equations
will then produce inaccurate or nonsensical results. Multiple correlations
for the winter months of November through April were too crude to serve
any useful purpose. At most sites, winter flows are zero or very low all
winter. The May equation is often inaccurate because the 1 to 5 week
timing differences in spring breakup in this part of Alaska are not ac-
curately depicted by monthly mean flows.
The following procedure was used to estimate 50 and 80 percentile flows
for a potential hydropower site.
o Determine basin variables -area, precipitation, forest cover,
etc.
o Calculate 50 and 80 percentil flows from the multiple regression
equations for May through October.
B - 2
o From records at the nearest representative station or stations
calculate area proportioned 50 and 80 percentile flows for all
months.
o Adjust regression flows where they appear unreasonable based
on long-term representative station records.
o Adjust regression flows where they appear unreasonable based
on observed flows (from field trip), other representative short-
term flow records, and unusual basin characteristics not indexed
by regression equations (such as, unusual north or south as-
pects, hot springs, large lakes, large areas of muskeg, perman-
ent snow fields, anomalous measured precipitation, unusual
groundwater flow, etc.).
B - 3
REFERENCES
Flow Characteristics of Alaska Stream, R. D. Lamke, USGS Water Resources
Investigation, 78-129, 1979.
Water Resources Data for Alaska, USGS, 1971 to 1978.
Surface Water Supply of the United States, Part 15. Alaska, 1961-1970,
Water Supply Papers 1936 and 2136, USGS.
Compilation of Records of Surface Waters of Alaska, Pre-1950 to 1960,
Water Supply Papers 1372 and 1740, USGS.
8 - 4
Station
Number
15356000
15389000
15389500
15439800
15453500
15457800
15468000
15470000
15472000
15474000
15476000
15476300
15476400
15477500
15478000
15478040
15484000
15485000
15485200
15485500
15493000
15493500
15511000
15512000
15514000
15514500
15515500
15515800
15516000
15518000
15518350
15534900
15535000
15564600
15564800
15564875
15564877
15564885
15564900
15565200
15565235
15565447
TABLE 1
STREAMFLOW RECORDS
YUKON BASIN (excluding 1908-12 period)
Name
Drainage
Area
Yukon River at Eagle
Porcupine River near
Fort Yukon
Chandalar River near Venetie
Boulder Creek near Central
Yukon River near Stevens
Village
Hess Creek near Livengood
Yukon River at Rampart
Chrisana River at
Northway Junction
Tanana River near Tok
Junction
Tok River near Tok Junction
Tanana River near Tanacross
Berry Creek near Dot Lake
Dry Creek near Dot Lake
Clearwater Creek near Delta
Junction
Tanana River at Big Delta
Phelan Creek near Paxson
Salcha River near Salchaket
Moose Creek at Eielson AFB
Garrison Slough at Eielson AFB
Tanana River at Fairbanks
Chena River near Two Rivers
Chena River near North Pole
Little Chena River near
Fairbanks
Chena Slough near Fairbanks
Chena River at Fairbanks
Wood River near Fairbanks
Tanana River at Nenana
Seattle Creek near Cantwel I
Nenana River near Windy
Nenana River near Healy
Teklanlka River near Lignite
Poker Creek near Chatanika
Caribou Creek near Chatanika
Melozitna River near Ruby
Yukon River at Ruby
MF Koyukuk River near Wiseman
Wiseman Creek at Wiseman
Jim River near Bettles
Koyukuk River at Hughes
Yukon River at Kaltag
Ophir Creek near Takotna
Yukon River at Pi lot Station
B -5
113_,500
29,500
9,330
313
196,300
662
199,400
3,280
6,800
930
8,550
65.1
57.6
360
13,500
12.2
2,170
136
6.2
18,000
941
1,430
372
20
1,980
855
25_,600
36.2
710
1,910
490
23.1
9.2
2,693
259,000
1,200
49.2
465
18,700
296,000
6.2
321,000
Record
1950-
1964-
1963-73
1966-
1976-
1970-78
1955-67
1949-71
1950-53
1951-54
1953-
1971-
1965-69
1977-
1948-57
1966-78
1948-
1964-65
1964-65
1973-
1967-
1972-
1966-
1948-52
1947-
1968-78
1962-
1966-75
1950-73
1950-
1964-74
1971-78
1969-
1961-73
1956-78
1970-78
1970-78
1970-77
1960-
1956-66
1975-
1975-
Notes
(3)
(4)
(4)
(4)
(3)
(1)
(3)
(4)
(4)
(4)
(4)
(4)
(4)
(4)
(4)
(4)
(4)
(2)
(2)
(4)
(1)
(1)
(1)
(2)
(1)
(1)
(4)
(4)
(4)
(4)
(1)
(1)
(1)
(1)
(3)
(1)
(1)
(1)
(1)
(3)
(2)
(3)
TABLE 1
Continued
NORTHWEST ALASKA (excluding 1906 -10 period)
Station
Number
15621000
15668200
15712000
15743000
15744000
15744500
15746000
15748000
Name
Snake River near Nome
Crater Creek near Nome
Kuzitrin River near Nome
June Creek near Kotzebue
Kobuk River at Ambler
Kobuk River near Kiana
Noatak River at Noatak
Ogotoruk Creek near
Point Hope
Drainage
Area
85.7
2L9
1,720
10.9
6,570
9,520
12,000
35
ARCTIC SLOPE ALASKA
15798700
15799000
15799300
15803000
15829995
15830000
15880000
15896000
15896700
15904900
15910000
15975000
15976000
Notes
Nunavak Creek near Barrow
Esatkuat Creek near Barrow
Esatkuat Lagoon Outlet at
Barrow
Meade River at Kasuk
Teshekpuk Lake Outlet near
Lonely
Miguakiak River near Lonley
Col vi I le River near Nuiqsut
Kaparuk River near Deadhorse
Putul igayuk River near
Deadhorse
Atigun River Tributary
sagavanirktok River near
sagwon
Chamber! in Creek near
Barter Island
Neruokpukkoonga Creek near
Barter Island
Used in multiple regression.
2.79
1. 46
3.52
1,800
1,400
1,460
20,670
3,130
176
32.6
2,208
1. 46
123
Record
1965-
1975-
1962-73
1965-67
1965-78
1976-
1965-71
1958-62
1971-
1972-73
1972-73
1977
1977
1977
1977
1971-
1970-78
1976-
1970-78
1958
1958
Notes
(1)
(1)
(1)
(2)
(1)
(2)
(1)
(1)
(1)
(2)
(2)
(2)
(2)
(2)
(2)
(1)
(1)
(2)
(1)
(2)
(2)
(1)
(2) Record too short for inclusion in multiple regression (5 year
mini mum).
(3)
(4)
Yukon River drainage basin too large to be representative in
multiple regression.
Drainage Basin outside of study area (south of 64°N or east
of 148° W) and probably not representative of hydropower sites.
Dash (-) means station is in operation past 1978.
B - 6
TABLE 2
50 PERCENTILE MEAN FLOWS
Slalion
Number Jan Feb 1>1 a,~ Apr May June July Aug Sept Oct Nov Dec
15457800 .20 .13 .10 2,105 1,328 571. 5 177 103 319 63.2 6.1 .73
15493000 108 80.0 76 145 2,215 1,165 702 918 1,019 448 213 153
15Lt935QQ 134.5 91.0 76.3 190.5 2,415 1,269 940 888 1,360 671 317.5 212
15511000 29.2 19.65 16 49.75 684.5 329 248.5 208 247 143.5 60 43.1
15514000 326 269 241.5 351 4,279 1,895 1,842 1,687 2,006 1,131 508 439
15514500 97 100 95 130 582 987 1,207 1,270 585 269 136 100
15518350 185 175 165 190 764 1,418 1,628 1,234 723 328 230 206
15534900 4.5 3.7 3.1 5.3 31.4 13.1 12.9 10.7 18 11. 5 5 4.5
15535000 1.6 1.5 1.6 1.5 13.4 6.4 4.4 5.5 7.3 4.4 2.9 2.0
15564600 74.0 60 50 62.8 5,393 8,186 2,248 2,606 2,599 956 348 140
15564875 4.4 2.0 1.5 3.3 2,697 2,858 1,419 1,140 685 163 43.3 11.5
15564877 .01 .01 .01 .01 67.8 102 23.9 29.3 25 3.6 . 25 .01
15564885 34.7 20 20 26.8 1,495 1,193 289 733 459 174 68.9 38.9
15564900 756 540 444 470 31,245 52,520 21,510 20,610 18,910 7,504 2,262 1,052
15621000 29.4 22.3 20 20 306 443 225 158 186 162 75.8 41.7
15668200 2.55 1.61 1.0 1.0 26 167 72.4 73.6 171 37.5 11. 1 5. 31
15712000 27.9 9.0 .01 1.5 2,324 6,394 910 776 670 735 215 99.2
15744000 1,526 1,152 1,000 1,160 15,140 26,640 14,630 11,280 11,945 6,910 3,560 2,000
15746000 .01 .01 .01 .01 2,408 73,790 29,205 20,046 12,323 3,887 .01 .01
15748000 .01 . 01 .01 .01 25.6 111.9 79.2 54.6 56.7 12.9 .01 .01
15798700 .01 .01 .01 .01 .01 5.2 .99 . 13 . 11 . 01 .01 .01
15896000 .50 .10 .01 .01 .01 14,905 1,591 319.5 872 62.3 13.3 1. 0
15896700 .01 .01 .01 .01 .01 404 17.2 2.3 3.3 .04 .01 .01
15910000 2.3 1.4 1.4 1.4 678 7,458 4,726 3,331 1,690 392 105 10.1
TABLE 3
80 PERCENTILE MEAN FLOWS
Station
Number Jan Feb Mar Apr May June July Aug Sept Oct Nov Dec
15511000 47.5 41.0 26.6 110 1,013 518 366 521 367 229 117 54.5
15493500 149 106 100 361 3,526 1,998 1,382 1,530 1,595 968 473 223
15493000 158 130 117 201 2,965 1,482 1,181 1,817 1,352 674 284 199
15457800 .50 .50 .50 6.67 1,811 923 245 749 358 69.4 6.90 1. 00
15514000 400 365 328 458 6,440 3,554 2,502 3,050 2,666 1,508 640 600
15514500 130 125 120 150 714 1,284 1,334 1,425 632 333 186 130
15518350 217 210 200 224 1,077 2,764 1,997 1,389 945 392 271 246
15534900 5.4 5.4 5.4 7.58 43.9 18.3 20.9 19.4 17.9 16.8 8.4 6.0
15535000 2.00 1. 60 1.68 1. 89 19.7 7.62 9.01 8.13 8.07 5.37 4.00 3.00
15564600 160 84.8 80.0 82.8 8,454 10,570 4,010 6,323 2,899 1,555 490 222
15564875 5.16 3.00 3.00 5.20 2.159 3,515 1,500 1,515 1,146 317 91.2 21.6
15564877 0 0 0 0 106 134 4,514 44.1 35.0 6.87 .57 0
15564885 39.7 31.7 28.2 43 1,551 1,658 467 917 1,293 341 106 69.7
15564900 985 691 547 704 36,910 73,480 29,960 28,490 30,100 10,800 2,927 1,516
15621000 31.9 26.7 22.0 25.0 526 981 251 210 338 227 85.0 45.0
15668200 5.10 4.59 4.00 4.00 88.1 222 89.3 79.4 227 77.3 13.5 6.61
15712000 89.8 16.4 10 20 5,153 8,320 1,709 1,550 2,195 1,055 380 140
15744000 1,665 1,400 1,300 1,300 17,140 45,010 18,400 19,610 14,920 10,140 3,833 2,387
15746000 0 0 0 0 3,300 86,266 36,270 30,067 18,456 5,474 0 0
15748000 0 0 0 0 78.8 213 115 75.3 161 18.0 0 0
15798700 0 0 0 0 0 10.9 2.57 .29 .40 0 0 0
15896000 10 10 10 10 12.9 15,940 1,207 749 683 406 32.5 15.8
15896700 0 0 0 0 .44 483 29.3 3.52 6.06 .11 0 0
15910000 4.08 1. 60 1.60 1. 66 868 8,269 4,983 6,130 1,958 456 153 32.7
TABLE 4
INDEPENDENT VARIABLES
snow Jan.
Station Precip. Area Forest Fall Slope Elev. Temp.
No. (in.) (sg. m i . ) (percent) (in.) (ft./mi.) (ft.) (-OF)
15457800 12 662 49 50 24 1,400 16
15493000 18 941 58 100 24 2,270 19
15493500 15 1,430 77 90 150 1,800 18
15511000 15 372 94 100 17 1,480 18
15514000 15 1,980 80 90 126 1,770 18
15514500 14 855 28 60 40 2,720 12
15518350 25 490 65 90 490 3,420 8
15534900 14 23 62 90 180 1,600 18
15535000 14 9 97 90 229 1 .. 640 18
15564600 16 2,693 57 90 3 1,410 17
15564875 14 1,426 4 80 41 3,390 16
15564877 13 49 3 75 171 2,930 17
15564885 15 465 10 60 39 2,080 16
15564900 18 18,700 36 75 19 2,200 17
15621000 30 86 4 70 20 632 6
15668200 40 22 1 100 522 1,500 6
15712000 18 1,720 2 70 20 700 8
15744000 20 6,570 34 70 5 1,610 16
15746000 20 12,000 2 75 6 1,800 16
15748000 16 35 .01 38 48 380 16
15798700 4 4 .01 30 15 48 22
15896000 13 3,130 .01 40 12 900 18
15896700 7 157 .01 40 6 140 20
15910000 18 2,208 .01 60 30 3,220 16
B - 9
TABLE 5
50 PERCENTILE REGRESSION EQUATIONS
MAY
Q = .000395 p2.832572 A·722117 F·642707 R2 = .75
JUNE
Q = 1.563492 p.877747 A1.050665 -.135928 F
-.58978 -.616172 R2 s J = .99
JULY
Q = .010508 p1.600549 A1.007673 R2 = .96
AUGUST
Q = .000161 p1.994932 A·946468 E•443161 R2 = .95
SEPTEMBER
Q = .000150 p3.829742 A·870322 F·123069
sn -1.229975 J1.399993 R2 = .99
OCTOBER
Q = .000032 p3.256560 A·923088 F·227990 R2 = .93
Q = flow (cfs)
p = annual precipitation (inches)
A = area (sq. mi.)
F = forest cover (percent +1)
s = slope (ft./mi.)
s = n annual snowfa II (inches)
J = minus mean January temperature (oF)
E = elevation (ft.)
TABLE 6
80 PERCENTILE REGRESSION EQUATIONS
MAY
Q = .000598 p2.822231 A·849491 F·380638 R2 = .90
JUNE
Q = 61.642935 Al.121743 -F .121315 J-1.331777 R2 :: .97
JULY
Q = .036971 p1.372754 A•962094 R2 = .96
AUGUST
Q = .000626 p1.632289 A·98715s E·433836 R2 = .96
SEPTEMBER
Q = .002266 p2.4056 A·922725 R2 = .95
OCTOBER
Q = .000036 p3.324430 A·960282 F·178871 R2 = .95
Q = flow (cfs)
p = annual precipitation (inches)
A = area (sq. m i . )
F = forest cover (percent +1)
J = mean January temperature (-oF)
E = elevation (ft.)
B -11
TABLE 7
RANGE OF INDEPENDENT VARIABLES
Area (A)
Mean Annual Precipitation (P)
Forest Cover (F)
Mean Basin Elevation (E)
Mean January Temperature (T)
Stream Slope (S)
B -12
3.9 to 18.700 square miles
4 to 40 inches
1 to 97 percent
48 to 3,390 feet
(-)6 to (-)22°F
2.9 to 490 feet per mile
HARDING-LAWSON ASSOCIATES
APPENDIX C
POTENTIAL GEOTECHNICAL
ENGINEERING PROBLEMS ASSOCIATED WITH
CONSTRUCTING SMALL HEAD HYDROPOWER FACILITIES IN
NORTHWEST ALASKA
HLA Job No. 9650,003.08
Prepared for
Ott Water Engineers, Inc.
4790 Business Park Blvd.
Suite 8, Bldg. D
Anchorage, Alaska 99503
By
~~-CJ~~ Bernard N1dow1Ci
Project Engineer
Harding-Lawson Associates
624 West International Airport Road
Anchorage, Alaska 99502
( 907} 276-8102
December, 1980
1
I 1
III
IV
HARDING·LAWSON ASSOCIATES
TABLE OF CONTENTS
INTRODUCTION •••..••..
NORTHWEST CLIMATE •••. .......................................... 2
GEOLOGY ••.••.•
A.
B. c.
Bedrock ...•...•.••....••.•.
Unconsolidated Deposits .••.
Permafrost ..•.••.•.•....•.•
HYDROPOWER STRUCTURES ...•.•.
A.
B. c.
Diversion Structures ..•.••.
Power House .•••.••••....••.
Transmission Facilities •.•.
4
4
4
5
7
7
9
10
V CONSTRUCTION CONSIDERATIONS .••.•.••••.•.•..•.......•.••••...••• 12
VI CASE HISTORIES .• 15
VII CONCLUSIONS •..•...•...•....•.•••...••....••••....•.••...•....•. 17
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HARDING-LAWSON ASSOCIATES
INTRODUCTION
This report presents the results of our study on potential geotechnical
engineering problems associated with constructing small head hydropower
facilities in Northwest Alaska. The sites under consideration at this time
are shown on Plate 1.
Our work was authorized on October 28, 1980 by Mr. David Black of Ott
water Engineers, Inc., Anchorage, Alaska. The purpose of this report is to
provide insight into the technical aspects of constructing hydropower struc-
tures in permafrost areas. Our scope of work was limited to researching
current literature and reporting of our findings. At the time of this re-
port specific structural and site information was not known.
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HARDING-LAWSON ASSOCIATES
II NORTHWEST CLIMATE
The climate of northwest Alaska is characterized by long severe win-
ters. Temperatures as low as -60°F have been recorded at numerous vil-
lages. The summers are generally cool with temperatures ranging between
30° and 50°F in the southern part. Areas that are about 50 or more
miles inland can experience summer temperatures in the 60°-80°F range.
The sun angle is low throughout the winter. Areas located north of the
Arctic Circle experience days in which the sun does not raise above the
horizon. The mean annual temperature can differ dramatically at two loca-
tions a short distance apart depending upon their orientation~ North facing
slopes will generally be in shadow for much of the time during the winter.
Large temperature variations, both annual and diurnal, can be expected
within the project area. From September to the end of December the tempera-
tures drop rapidly. A slight decrease in temperature continues until Febru-
ary which is generally the coldest month of the year. These large tempera-
ture fluctuations can be observed from weather data collected at Kobuk.
This village has a record high of 90°F in June, 1969 and a record low of
-68°F in March, 1971.
Precipitation is generally less than 20 inches inland and slightly
higher along the coast and at higher elevations. Snow fall varies between
20 to 85 inches and has been reported every month of the year at the north-
ern locations. In the more southern locations June and July are free of
snow.
The winds are generally moderate to strong year-round and reach their
strongest during winter months. This, combined with extremely low air
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HARDING-LAWSON ASSOCIATES
temperatures, causes very high wind chill. It is not uncommon for the wind
chill to approach -l00°F. The coastal areas are often battered with ex-
tremely high winds that exceed 50 knots. Occasionally, storms in the Bering
Sea will cause flooding from wind-driven tides. In November, 1974 storm
winds swept seawater ashore that inundated much of Nome and numerous vil-
lages along the southern coast of the Seward Peninsula. During this partic-
ular storm, winds in excess of 70 miles per hour were recorded.
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HARDING-LAWSON ASSOCIATES
II I GEOLOGY
A. Bedrock
The principal rocks common to the project area include Mesozoic gray-·.
wacke, slate, and volcanic rocks, particularly in the area of Kiana and
Shungnak. Also in the Shung~ak area are Paleozoic sedimentary rocks includ-
ing Devonian to Triassic marine carbonates.
The ridge and lowland section north of the Kobuk River, extending east-
ward from Ambler, is generally underlain by early Paleozoic or older highly
metamorphosed rocks; Cretaceous graywacke and mudstone, chert, and argillite
with interbedded regolitic tuff and sandstone. Numerous thick beds of coal
are also present.
The western half of the Seward Peninsula is principally underlain by
Ordovician to Silurian limestone, slate and schist, pre-Selurian crystalline
limestone, schist and gneiss; intrusive granite rocks of uncertain age are
located near Wales. on the southern side bedrock includes extensive Quater-
nary basaltic lava flows and basaltic andesites in the Brevig Mission area,
and Paleozoic schist and gneiss. In the White Mountain area the same type
of rocks are encountered but the dominant types are metamorphosed sedimen-
tary and Paleozoic sedimentary rocks.
B. unconsolidated Deposits
unconsolidated deposits occur chiefly in low-lying, inhabited regions.
In this region unconsolidated materials are principally concentrated in the
lower regions of the Noatak Lowland, Kobuk-Selawik Lowland, northern coastal
plain of Seward Peninsula and the major river valleys. Most of these de-
posits are Pleistocene in age. During the Pleistocene mountain glaciers
advanced several times in the Brooks Range. Most of the area north of
c -4-
HARDING-LAWSON ASSOCIATES
Hughes was glaciated. As a result, much till mantles extensive areas in
these locales.
Deposits of windblown sand and silt mantle a major portion of the low-
lying areas of the Northwest Region. The thickness ranges from a few inches
to tens of feet.
During Pleistocene time streams deposited much sand and gravel. Areas
around Kobuk contain major alluvial deposits.
Prevailing winds develop a long shore current that can deposit fine sed-
iments along the coast. Fine materials such as clay, silt, and fine sand
are usually carried in suspension in the long shore currents; coarser parti-
cles of sand and gravel can be transported by wave wash.
C. Permafrost
Permafrost is usually defined as soil or rock material that has remained
below 32°F continuously for at least two years. Permafrost underlies most
of Northwestern Alaska. Local differences in climate~ topography, vegeta-
tion, geology~ and hydrology effect the areal extent and thickness of the
permafrost.
Terrain conditions such as surface relief and direction directly in-
fluence permafrost formation since the amount of solar radiation received
depends on the degree and direction of slope. The type of ground surface
cover and soil type beneath the cover is also an important factor. Gravels
and other coarse-grained materials contain smaller amounts of moisture than
do fine-grained soils such as silts. Granular materials generally have a
very deep active layer (the active layer is defined as that portion of the
ground which freezes and thaws each year). The fine-grained soils that are
commonly found in Northwest Alaska tend to be ice rich.
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HARDING-LAWSON ASSOCIATES
Removal or disturbance of vegetation effects the permafrost. Generally,
any disturbance will cause degradation of the permafrost to begin. Past
experience has shown that the vegetation is particularly susceptible to
repeated passes of vehicles. Once thaw occurs, possible local subsidence,
flooding, drainage diversion, and erosion problems may be encountered.
Numerous forms of ice may be encountered within frozen soil. The three
most common forms encountered are pore, segregated, and massive ice. Pore
ice is moisture that has been frozen between the soil grains. This is the
most commonly encountered ice found in granular (coarse sands and gravels)
deposits. Segregated ice (commonly referred to as ice lenses) is ice that
is located in horizontal lenses. These lenses are normally less than one-
inch thick. This type of ice is common to fine-grained soils such as silt.
It is formed by migration of water to the freezing front within the soil.
Massive ice is the term generally used to describe large wedge-shaped in-
clusions of ice. These features can be 5 to 10 feet thick at the top and
extend to 20 feet in depth. They are formed during the winter when the
ground contracts from the cold and subsequently fills in with water in the
spring.
Subsurface thermal conditions are dependent upon the surface heat flux.
Streams, lakes, and other bodies of water which do not completely freeze to
the bottom during the freezing season are generally underlain by unfrozen
zones of soil. The size of the unfrozen zones is a function of the size of
the surface feature. Small deep streams may have unfrozen zones less than
five feet below the lake bottom. Large deep streams may cause the perma-
frost to degrade completely.
c -6-
HARDING·LAWSON ASSOCIATES
IV HYDROPOWER STRUCTURES
The structures considered in this study are limited to low head concrete
and earth fill diversion structures and small capacity generating plants.
Ideally, these facilities will be in the immediate area of the village.
However, this probably will not be true in all cases, thus a transmission
1 i ne may extend severa 1 miles. For the purposes of this study the hydro-
electric complex may be divided into three basic elements.
A. Diversion Structure
B. Power House
C. Transmission Facilities
A. Diversion Structures
The effects of the diversion structures upon the thermal regime of the
permafrost can be analyzed in two parts: firstly, the effects of impounding
water; secondly, the effects of the structure.
Impounding water behind the structure will increase the surface area
that is inundated. This in turn will change the surface heat balance. The
permafrost may degrade under the area impounded. Once started, the thermal
erosion may continue forever. This is particularly true in those areas in
which the water depth is such that an unfrozen zone exists during the winter
and the existing permafrost is warm (temperature close to 32°).
The problems and effects of the structure may be further subdivided into
two areas; the structure itself, and the effect the structure has on the
underlying soils.
c-7-
HAROING·LAWSON ASSOCIATES
Two of the most common types of diversion structures are those con-
structed of either earth material or concrete. An earth fill structure may
be designed to function either in a frozen or unfrozen state.
If the structure is designed to perform in an unfrozen state, the foun-
dation material should be thaw-stable (thaw-stable soils are frozen soil or
rock that, on thawing, do not show loss of strength below normal long-time
thawed values or produce detrimental settlement). The presence of water on
the upstream face and the heat that could be transferred by seepage through
the structure may thaw the foundation material. It should be noted that the
presence of bedrock does not completely eliminate the potential problem of
settlement. Careful examination of drill cores is required to determine if
layers of ice exist in the bedrock.
A frozen structure is advantageous since the frozen core and permafrost
form a single mass which is stable. However, this configuration is thermal-
ly fragile and care must be exercised so that this frozen mass will not
thaw. Several methods of freezing the core of an earth fill dam are pos-
sible:
1. Layer by layer freezing of the body of the core by material freez-
ing during the construction process.
2. Freezing of the core of the structure on completion of its con-
struction but Defore completing the shell using artificial cooling.
3. Freezing of the core by natural cooling using ventilation ducts.
4. A combination of the above.
Within the project area the mean annual air temperature is not low
enough to maintain frozen cores within the structures considered. There-
fore, either ventilation ducts or heat tubes would have to be installed
within the structure to maintain the frozen state.
c -8-
HARDING-LAWSON ASSOCIATES
The construction of concrete dams in Northwest Alaska presents numerous
difficulties due to the extreme cold and remoteness of the sites. Concrete
structures require more stringent foundation requirements than earth fill
structures. In addition, the logistics and costs of concrete production and
quality control at remote sites must be considered.
One problem associated with thick concrete structure in the north is
cracking due to tensile stresses. The downstream face is exposed to large
temperature fluctuations. When a large temperature difference is present
between the two faces of the dam considerable tensile stresses may be
developed. These stresses can produce horizontal cracks within the struc-
ture.
Concrete is a good conductor of heat. During the warmer summer months
considerable heat will be conducted into the foundation soils. This may
cause degradation of the permafrost and eventual differential settlement
leading to large stress fields developing with the structure. This may
result in cracking. Seepage will introduce additional heat which will cause
further degradation of the permafrost. If the permafrost is shallow, pre-
construction thawing of the permafrost may be employed. This method, while
effective, is time-consuming and costly.
B. Power House
The power house will contain machinery that is sensitive to settlement
and horizontal movement. This machinery may also produce vibratory ground
impulses. In the design of these structures careful thought must be given
to the interaction between the structure and the frozen ground, if present.
If permafrost is not present at the power house, the site may be developed
using conventional foundation engineering procedures.
c -9-
HARDING-LAWSON ASSOCIATES
Permafrost will most likely be encountered beneath the power house. To
provide stability to the structure the thermal regime of the permafrost must
be maintained. Heat that is generated within the structure must be removed
before it is conducted into the soil which will in turn melt the frozen
soil. A pile foundation is one mode that will permit the heat to be removed
before it enters the ground. The type and size of the piles will depend
upon site specific conditions. The design of piles in frozen soils should
be accomplished by an experienced Arctic engineer.
If piles are not employed, the structure will be in direct contact with
the ground surface. To prevent degradation of the permafrost an active heat
extraction system should be installed. This system may be an insulated
gravel pad with either vents or heat tubes installed in the gravel pad be-
neath the insulation. This system works in the following manner: auring
the warm summer months the insulation slows the rate of advance of the thaw-
ing front; during the winter months when the structure is heated, the vents
or heat tubes extract the heat before it enters the native soil. If the
structure will not be heated during the winter, vents or heat pipes may not
be required.
C. Transmission Facilities
Ideally, the power site will be adjacent to the village. In situations
where this is not possible, power will need to be delivered through a
utility system. This system may be installed above or below ground. In
c -10-
HARDING-LAWSON ASSOCIATES
permafrost regions above ground piping has been used with success. This
provides easy access for maintenance, however, this is offset by the fact
that the system is exposed and subject to weather and vandalism. Above
ground piping greatly restricts the movement of pedestrians and vehicular
traffic. This tends to unnaturally segment the community. Consideration
must be given to the method of service lines that connect the numerous
structures within the village. The space under and near the above ground
utilidor cannot be used and tends to collect refuse and may become a drain-
age path.
The above ground system may be either supported by piles or on a gravel
pad. If piles are used they must be adequately designed to resist frost
heaving forces. Generally, the loads on the piles will be small; this will
require large embedment lengths be used to counter the heaving forces. If
bedrock is encountered close to the surface, piles may not be feasible.
Gravel pad installations may require large volumes of material which may not
be obtainable in the immediate project vicinity. Gravel is also difficult
to excavate and place in the winter. This type of installation also re-
quires that water passages not be blocked. This method is susceptible to
weather and erosion problems.
The disadvantages of buried utility systems include difficult and ex-
pensive foundation design and construction. Repairs will be more costly and
time consuming. However, the system once installed is out of sight and is
less of a problem concerning vandals and weathering.
e-ll-
HAROING·LAWSON ASSOCIATES
V CONSTRUCTION CONSIDERATIONS
This section is provided to give the reader an insight into the types of
problems that should be anticipated in the design of the hydropower sites.
1. A vulnerable place in frozen earth dams is the contact between the
dam and the floodgate or spillway. Thermal erosion is very likely to start
at these contact points and progress to the frozen core.
2. The local material that is to be used for the structure may be mar-
ginal in quality and high in ice content. The high ice content may require
that the material be stockpiled for one summer to allow the ice to melt out.
3. Compacting of frozen ice rich soils is very difficult and the de-
gree of compaction generally low. When thawing occurs, settlements in the
range of 10 to 20 percent or higher may occur.
4. The structure should be designed to withstand large ice and water
forces generated during spring break-up. Spring break-ups in Northwest
Alaska are characterized by high water and large ice floes which reach large
dimensions. The upstream face should be protected from scour by these floes
and the spillway designed so that it won't be ripped apart.
5. Although most small Alaskan streams freeze to the bottom during the
winter, sub-surface flow may still be present. If the structure is designed
to operate in a frozen configuration, this may cut off this flow during the
winter months. This may lead to the formation of large deposits of aufeis
upstream of the structure.
6. For sites that are located along the coast the effects of salinity
upon the permafrost should be considered in the design. These areas have
large freezing point depressions resulting in unbonded permafrost (unbonded
c -12-
HARDING-LAWSON ASSOCIATES
permafrost is defined as earth material that is below 32°, but not bonded
by ice due to a freezing point depression). It is common to find alternat-
ing layers of bonded and unbonded permafrost in a given soil profile.
7. Curing of concrete releases heat; this may induce thawing of perma-
frost in areas of warm permafrost.
8. Structures built on frozen bedrock may not be sound. The bedrock
may contain ice lenses between the strata.
9. Most diversion structures will probably be located on allivium,
i.e. sands/gravels. Although generally thaw stable, once thawed, the amount
of seepage may not be tolerable.
10. Soils underlying structures should be non-frost susceptible to re-
duce the amount of frost heave. Frost heave can be detrimental to hydraulic
structures by causing differential movement, cracking, etc.
11. A possible approach to the foundation design of the diversion
structure and powerhouse may be to excavate the overburden material and
place the structure on bedrock. It should be noted that excavation of fro-
zen gravels generally requires blasting and heavy ripping and thus is very
slow and expensive.
12. Diversion of water during construction may be necessary or possibly
only winter construction. Winter construction is slow and quality control
becomes very difficult. Numerous shutdowns may be required due to extremely
severe weather conditions.
13. Sufficient freeboard will be necessary to prevent overtopping of
the structure during spring break-up.
14. Care should be taken where the water flows down the spillway and
into the strean. This increased flow may cause rapid degradation of the
permafrost.
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HARDING·LAWSON ASSOCIATES
15. Structural concrete placed in late fall to early spring has shown
lower strength than anticipated or specified. Temperature of the air adja-
cent to the freshly poured concrete should be maintained at approximately
55°. This will require that thought is given to the construction of heat-
ed enclosures. Provisions should be included in all specifications to pre-
vent thermal shock at the time the enclosure is removed.
c -14-
HARDING-LAWSON ASSOCIATES
VI CASE HISTORIES
The first known dam built on permafrost was on the River t~y Kyrt at the
city of Petrovsk. It was constructed in 1729. It was an earthen dam 600
feet long and 30 feet high. It was constructed and operated in a frozen
state. From the time of construction until 1929 the dam operated in an
acceptable manner. During 1929 work was done to repair the wooden spill-
way. This disturbance was sufficient to induce thawing in the fill. At-
tempts to limit the infiltration of water failed.
In 1930 an earth fill dam about 20 feet in height was constructed on the
river Pravaya Magdagacha with a vertical concrete seepage barrier approxi-
mately 1.5 feet thick. The foundation material consisted of quaternary
deposits (sands/gravels) that were frozen to approximately 100 feet. During
the first year of operation the material thawed to depths exceeding 12
feet. This lead to considerable settlement and eventual failure.
A dam of approximately 20 feet was constructed on the Kolyma River that
suffered the same fate as the dam described above. In this case the founda-
tion material consisted of gravelly sand and silt. The soil was interbedded
with ice to a depth of 20 feet. Thawing of the foundation material resulted
in tremendous amounts of seepage and deformation.
The first dam on permafrost constructed in Alaska is the Hess Creek dam
near Livengood which was completed in 1946. The dam was approximately 75
feet high and constructed of a combination hydraulic and rolled earth fill.
The design included an artificial refrigeration system to assist the freeze-
back and bonding at the interface between the frozen gravel and the central
core of the hydraulic fill. The foundation base consisted of frozen sand
c -15-
HARDING-LAWSON ASSOCIATES
and gravel. An impervious central core and a steel sheet pile cutoff wall
was installed along the centerline of the fill to prevent seepage.
During the operation of the dam from 1946 to 1958 the reservoir was
drained each fall. Seepage was never reported as a problem nor was thawing
of the foundation base. In 1962 the overflow spillway section of the dam
was severely damaged when snow-melt runoff overfilled the reservoir causing
considerable erosion. It appears that the design of the gravel spillway was
inadequate.
c -16-
HARDING-LAWSON ASSOCIATES
VII CONCLUSIONS
The construction of low head diversion structures is feasible in North-
western Alaska. Careful planning and design is essential for successful
operation of these structures. A complete monitoring system should be in-
stalled at crucial locations of the various structures to provide perform-
ance data from which future sites and remedial action can be initiated,
should problems occur. A detailed site specific soil investigation is es-
sential and should be conducted at each location.
c -17._
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HARDING LAWSON ASSOCIATES
Consulting Engineers and Geologists
5875 •
Job No .. __ 9_6_50__,,'-'-0-'-0-=--3 .:.-=0--=-B_Appr· 81(" Date_-'1'-=2~/8=0,_
SITES LOCATIONS PLAN
OTT WATER ENGINEERS, INC.
NORTHWEST, ALASKA
J
PLATE
1