HomeMy WebLinkAboutLake Elva Reconnaissance Study 1980THE
CONTRACT NO. 9703
This report has been prepared by
Dora L. Gropp, P.E.
Carl H. Steeby, P.E.
Frank J. Bettine, E.I.T
Information on geology for
the hydro sites was
was provided by
C. C. Hawley Associates
Dillingham
APA18/G3
L
RECONNAISSANCE STUDY OF LAKE ELVA
AND ALTERNATE HYDROELECTRIC POWER POTENTIALS
IN THE DILLINGHAM AREA
TABLE OF CONTENTS
INTRODUCTION AND SUMMARY
A. Introduction
B. Summary
II. EXISTING SYSTEMS AND FUTURE ELECTRIC
POWER REQUIREMENTS
A. Introduction
B. Projection Parameters
C. Di 11 i ngham
D. Naknek
E. Iliamna/Newhalen/Nondalton
F. 10 Vi 11 ages
G. Togiak Bay
H. Bibliography and References
III. HYDROELECTRIC SITE EVALUATION
A. Lake Elva
B. Grant Lake
C. Lake Tazimina
IV. ECONOMIC FEASIBILITY ANALYSIS
A. Choice of Methods and Alternates
B. Alternate Development Plans
C. Evaluations and Conclusions
V. OTHER ELECTRIC ENERGY RESOURCES
A. Wind Power Potential
B. Transmission Interties
C. Conservation
VI. RECOMMENDATIONS
A. Di 11 i ngham
B. Regional Development
C. Further Investigations
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PAGE
I-3
I-3
I-3
II-1
II-1
II-6
II-9
II-15
II-21
II-24
II-48
II-49
III-1
III-1
II I-25
III-48
IV-1
IV-1
IV-2
IV-13
V-1
V-1
V-4
V-13
VI-1
VI-1
VI-2
VI-4
Dillingham
APA18/G4
APPENDICES
A. TECHNICAL DATA
A-1 Single Wire Ground Return Transmission
A-2 Distribution and Transmission Line Load
Limitations
A-3 Phase and Frequency Conversion in Power
Transmission
A-4 Determination of 11 Economic 11 Distance to
Supply center for SWGR Interties
A-5 Evaluation of Electric Heat and Hydro-
electric Power
A-6 Hydrological Analysis
B. COST ELEMENTS
B-1 Transmission System
B-2 Wind Generating Equipment
B-3 Frequency and Phase Conversion
c. Economic Evaluation -Detail Sheets
D. Environmental Impact, Land Status
D-1 State of Alaska, Department of Fish & Game,
PAGE
A-1
A-13
A-19
A-25
A-31
A-41
B-1
B-4
B-4
C-1
Letter of January 25, 1980 D-1
D-2 State of Alaska, Department of Fish & Game,
Letter of March 4, 1980 D-2
-ii -
Dillingham
APA18/G5
FIGURE
I-1
II-1
II-2
II-3
II-4
II-5
II-6
II-7
II-8
II-9
II-10
II-11
II-12
II-13
II-14
II-15
II-16
II-17
III-I
III-2
III-3
III-4
III-5
II I-6
III-7
III-8
III-9
III-10
III-11
I II-12
III-13
III-14
III -15
II I-16
III-17
LIST OF FIGURES
Vicinity Map
Bristol Bay Population
Dillingham -Power Requirements
Dillingham -Seasonal Electric Energy
Requirements
Naknek -Power Requirements
Naknek -Seasonal Electric Energy Requirements
Iliamna-Power Requirments
Clark's Point-Power Requirements
Egegik -Power Requirements
Ekuk -Power Requirements
Ekwok -Power Requirements
Igiugik -Power Requirements
Koliganek-Power Requirements
Levelock -Power Requirements
Manokotak -Power Requirements
New Stuyahok -Power Requirements
Portage Creek -Power Requirements
Rural Bristol Bay -Seasonal Electric Energy Use
Bristol Bay Intertied System
Lake Elva -General Layout
Lake Elva -Typical Dam Section
Lake Elva -Penstock Profile
Lake Elva -Area Capacity Curve
Lake Elva -Construction Schedule
Grant Lake -General Layout
Grant Lake -Dike Section
Grant Lake -Dam Section
Grant Lake -Penstock Profile
Grant Lake -Area Capacity Curve
Grant Lake -Construction Schedule
Lake Tazimina -Seismic Survey
Lake Tazimina -Facilities Layout (Photo)
Lake Tazimina -Forebay and Storage Dam Section
Lake Tazimina -Area Capacity Curve
Lake Tazimina -Construction Schedule
-iii -
PAGE
I-1
II-7
II-12
II-14
II-16
II-19
II-22
II-26
II-28
II-30
II-32
II-34
II-36
II-38
II-40
II-42
II-46
II-47
III-3
III-8
III-13
III-14
III-15
III-23
III-28
II I-35
III-36
III-37
II I-38
II I -46
III-52
III-59
III-60
III-61
III-70
Di 11 i ngham
APA18/G6
FIGURE
IV-1
IV-2
IV-3
IV-4
IV-5
IV-6
IV-7
IV-8 to IV-15
V-1
V-2
V-3
V-4
A-1.1
A-4.1
PAGE
Dillingham -Power Hydroelectric Power Potential
& Capacity Balance -1980-2000 IV-5
Dillingham-Power Hydroelectric Power Potential
& Energy Balance -1980-2000 IV-6
Dillingham/Naknek/10 Villages -Capacity IV-8
Oillingham/Naknek/10 Villages -Energy IV-9
Intertied System -(15 Communities ) -Capacity IV-11
Intertied System -(15 Communities ) -Energy IV-12
Tazimina -Busbar Cost for Electric Energy with
and without the Sale of Electric Heat IV-22
Bristol Bay -Busbar Cost of Power Graphs IV-22 to IV-29
Cost of Electric Energy -Wind/Diesel V-3
Dillingham/Naknek plus 13 Villages Intertie V-6
Busbar Cost of Electric Energy for Small
Communities V-8
Bristol Bay -Kuskokwim Transmission Intertie V-10
A-Frame Power Line Structure A-6
Line Mile Multiplier A-30
-iv -
Dillingham
APA18/G7
TABLE
I-1
I-2
Il-l
II-2
II-3
IV-1
IV-2
IV-3
IV-4
IV-5
V-1
V-2
A-2.1
A-5.1
A-5.2
A-6.1
A-6.2
A-6.3
A-6.4
LIST OF TABLES
Future Power Requirements
Busbar Cost of Electric Energy
Electric Energy & Power Requirements High Load
Growth
Electric Energy & Power Requirements Low Load
Growth
Existing Installed Capacity
Unit Cost of Power
Equivalent Unit Cost of Electrical Energy and
Sum of Present Worths of Accumulated Annual
Cost -Low Load
Equivalent Unit Cost of Electrical Energy and
Sum of Present Worths of Accumulated Annual
Cost -High Load
Cost Ratios
Cost Ratios
Wind Generator Energy and Power Output
Transmission Tie Lines
Line Loading Limits
Evaluation of Electric Heat High Load
Evaluation of Electric Heat Low Load
Lake Elva -Monthly Discharge
Nuyakuk River -Monthly Discharge
Grant Lake -Monthly Discharge
Tazimina River -Monthly Discharge
- v -
PAGE
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I-7
II-4
II-5
II-45
IV-5
IV-6
IV-8
IV-9
IV-11
V-3
V-7
A-17
A-36
A-37
A-46
A-53
A-54
A-62
Dillingham
APA18/G8
ACKNOWLEDGEMENTS
We would like to express our thanks to the local utilities: Nushagak
Electric Association, Naknek Electric Association and AVEC who made
their records available to us to provide base data for the economic
evaluation of the various plans, to the Alaska Power Administration
who released data from the preliminary 11 Bristol Bay 11 report to be
used in this study and to the U.S. Geological Survey for the coopera-
tion implementing stream gauging at various sites. The cooperation
of the State of Alaska, Department of Fish and Game, as well as the
Division of Natural Resources and the U.S. Department of the Interior,
Bureau of Land Management, assured more useful assessment of environ-
mental impacts and land status. Without their help this report
would not have been possible in its present form.
-vi -
I. INTRODUCTION AND SUMMARY
I
••
T 0 L
I .
I ALASKA \ ~0~ •
\ c,~" • FAtftBANKS .
\ ..
VICINITY IIAP
FIGURE I-1
I -1
Dillingham -Section I
APA013/G
I. INTRODUCTION AND SUMMARY
A. INTRODUCTION
This reconnaissance study has been performed for the Alaska Power
Authority (AKPA) under the contract 11 Reconnaissance Study for
Hydroelectric Development at Lake Elva Near Dillingham and on the
Kisaralik River Near Bethel 11 dated August 13, 1979. This study is
a follow on to an earlier study 1 . The purpose of this study is to
evaluate previously identified potential hydroelectric sites in the
Dillingham area in greater detail, including
• implementation of stream-gauging;
• site -reconnaissance and evaluation;
• conceptual design;
• economic feasibility analysis;
• investigation of other alternate electric energy resources.
A supplementary report will summarize the stream-gauging program
and its impact on the conclusions of this study after a period of
approximately one year.
B. SUMMARY
The questions to be answered by this study can be summarized as
follows:
• Can the Lake Elva hydropotential be developed economically
for Dillingham?
• Are there alternates which are also feasible?
Preliminary investigations described in the Bristol Bay study noted
earlier have identified three promising hydroelectric sites in the
Bristol Bay area:
1
Lake Elva
Grant Lake, and
Tazimina Lake
11 Bristo1 Bay Energy and Electric Power Potential -Phase I",
Draft -Oct. 79 prepared for the U.S. Department of Energy,
Alaska Power Administration.
I-3
Dillingham-Section I
APA013/G
Development of these sites had been assessed as feasible in regard
to cost, capacity, environmental impact, and land status. Since
implementation of construction of the three projects is judged
nearly mutually exclusive due to the high expenditures involved,
this study has assessed technical and economic feasibility of the
possible alternate plans. Sensitivity to load growth and various
interest rates has been determined. The area presently utilizes
diesel generation exclusively and is experiencing very high increases
in electric energy cost due to the recent escalation of fuel oil
prices. All alternate developments have therefore been compared to
the basic case of continued exclusive diesel generation.
The fo 11 owing paragraphs wi 11 summarize the main sections of the
report.
1. Existing Systems and Future Power Requirements
With the Tazimina potential under consideration, power require-
ments have been established for 15 communities in the Nushagak/
Kvichak/Iliamna area. With a forecasting period of 20 years
the possible developments are shown on Table I-1. Whether the
"high" or 11 1 ow" 1 oad growth scenario is rea 1 i zed wi 11 depend
greatly on the cost of electric energy. A low growth rate can
be expected with the continued use of diesel generation and
the steadily increasing cost. If a more cost-stable source of
electric energy is available, it is anticipated that the
historic growth rate will continue and industrial development
will be encouraged.
2. Hydroelectric Site Evaluation
To allow a more accurate assessment of the available power, a
stream-gauge has been installed at Elva Creek and low flow
(winter) measurements will be taken at the Tazimina River. A
series of historical measurements are avai 1 ab 1 e for Grant
Lake. Presently the prime capacity of the three sites is
assessed as follows:
Cost/kW
Capacity Capacity Total Cost* Installed
Site _(kW prime) (kW installed) (1979-1000$) (1979-$)
Lake Elva 955 2x750 12,940 8,630
Grant Lake 1385 2xl350 17,416 6,450
Tazimina
Stage I 9000 2x9,000 50,820 2,820
Stage II 18403 +2x9,000 +45 '774 +2,540
* Incl. transmission to load centers.
I-4
Electric Energy and Power Requirements Electric Energy and Power Requirements
LOW Load Growth HIGH Load Growth
'I
Location 1977 1980 1985 1990 1995 2000 Location 1977 1980 1985 1990 1995 2000
Dolhngham Dilling~
Energy (MWh/year) 4769 5930 8500 11070 13521 15972 Energy (MWh/yur) 4769 6574 12827 19080 32298 45516
Demand (kW) lZOO 1500 2040 2580 3115 3650 Demand (kW) 1ZOO 1500 2730 3960 6310 8660
Naknek/King Salmon ,,, Naknek/King S.almon
Energy (MWh/yea.-) 11691 12526 15648 ~ 18770 20923' 23076 Energy (MWh/year) 11691 14086 22044 ' 30002 40591 51180
Demand ~kWl 2700 2550 3190 3830 4265 4700 Demand ~kw~ 2400 2870 4495 6120 7930 9740
Subtotal Dillingham/Naknek Subtotal Dillingham/Naknek
Energy (MWh/yur) 16460 18456 24148 29840 34444 39048 Energy (MWh/ye.ar) 16460 20660 34871 49082 72839 96696
Demand ~kW2* 3600 4050 5230 6410 7380 8350 Demand ~ kW)• 3600 4370 7225 10080 14240 18400
Clark1s Point Clark's Point
Energy (MWh/year) 152.7 160 175 191 537 883 Energy (MWh/year) 152.7 184 879 1574 1894 2215
Demand (kW) 45 46 51 55 153 250 Demand (kW) 45 52 326 600 725 850
Egegik Egegik
Energy (MWh/year) 101.9 413 966 1517 1600 1683 Energy (MWh/year) 101.9 1040 2316 3591 3642 3692
Demand (kW) 40 600 645 690 730 770 Demand (kW) 40 600 980 1360 1380 1400
Ekuk Ekuk
Energy (MWh/year) 21.3 188 195 203 290 378 Energy (MWh/year) 21.3 198 233 '269 948 1628
Demand (kW) 6 214 224 233 260 287 Demand (kW) 6 226 267 308 619 930
Ekwok Ekwok
Energy (MWh/year) 167.4 178 198 218 257 297 Energy ·(MWh/year) 167.4 203 330 457 982 1507
Demand (kW) so 51 57 62 65 68 Demand (kW) so 58 94 130 238 345
Igiugig Igiugig
Energy (MWh/year) 79.1 145 155 166 199 232 Energy (MWh/year) 79.1 158 225 292 410 528 H Demand (kW) 25 41 45 48 51 53 Demand (kW) 25 45 65 85 103 120 I
U1 Koliganek Koliganek
Energy (MWh/year) 160.1 170 188 206 296 386 Energy (MWh/year) 160.1 190 356 523 1014 1505
Demand (kW) 50 50 54 58 73 88 Demand (kW) so 54 102 150 248 345
Levelock Levelock
Energy (MWh/year) 171.7 183 205 228 343 458 Energy (MWh/year) 171.7 209 419 629 948 1267
Demand (kW) 50 52 58 65 85 105 Demand (kW) 50 60 120 180 235 290
Manokotak Manokotak
Energy (MWh/year) 197.8 257 264 271 398 523 Energy (MWh/year) 197.8 338 678 1018 1728 2439
Demand (kW) 58 73 n 80 100 120 Demand (kW) 58 97 194 290 425 560
New Stuyahok New Skuyahok
Energy (MWh/year) 203.1 232 256 280 384 488 Energy (MWh/year) 203.1 267 460 653 118.3 1713
Demand (kW) 100 115 100 100 100 110 Demand (kW) 100 100 143 186 288 390
Portage Creek Portage Creek
Ene.-gy (MWh/year) 83.3 110 134 156 190 224 Energy (MWh/year) 83.3 120 198 275 372 468
Demand (kWl 24 31 38 45 48 50 Demand ~kW2 24 34 57 80 94 107
Subtotal -io villages Subtotal -10 vi II ages
Energy (MWh/year) 133841 2036 2736 3436 4494 5552 Energy (MWh/year) 1338.4 2907.0 6094 9281 13121 16982
Demand kW * 448 1273 1349 1436 1665 1901 Demand ~kW~• 448 1326 2348 3369 4355 5337
Iliamna Newhalen lliamna/Newhalen
Energy (MWh/year) 1000 1382 1571 1761 1955 2149 Energy (MWh/year) 1000 1543 2215 2837 5578 8270
Demand {kW}* 285 315 357 ' 400 445 490 Demand (kW)* 285 352 506 660 1190 1720
Total Total
Energy (MWh/year) 18798.4 21874 28455 35037 40893 46749 Energy (MWh/year) 18798.4 25110 43180 61250 91588 121948
Demand (kW) 4333 5638 6936 8246 9490 10741 Demand (kW) 4333 6648 10079 14109 19785 2~57
*Noncoincident 'j *Noncoincident >«' ' '' C'"j-1 '1 .i .. J., I
Electrical Energy and Power Requirements
Table I-1
Dillingham-Section I
APA013/G
Mitigation of the anticipated impact of plant development on salmo11
spawning grounds has led to the downscaled development proposals
for Grant Lake and Tazimina. Subsoil conditions found at the
planned Tazimina damsite limit construction of the dam to a height
less than previously considered.
Lake Elva is located in the proposed Wood River Lakes State Park
but is listed as a non-objectionable development in the park statutes.
Grant Lake is also within the proposed park but may be set aside as
a non-objectionable development. Tazimina is located in a wilderness
study area which is presently included in the 1978 federal emergency
withdrawal. Attempts to obtain a powersite exemption are underway.
3. Economic Feasibility Analysis
Alternate deve 1 opment p 1 ans have been eva 1 uated fol' the
Dillingham system and for a regional intertied system includ-
ing up to 15 communities. Utilizing annua 1 cost and present
worth comparisons the following scenarios have been found to
be the most advantageous developments:
Lake Elva for the Dillingham system only;
Lake Tazimina for a regional intertied system.
Transmission interties of 10 communities in the Kvichak/
Nushagak area to the central generating plants in Naknek and
Dillingham have been found feasible independent of hydroelectric
power potential development. This is mostly due to the high
fuel cost in remote locations and low generating efficiencies.
The following table will illustrate the cost differences for
the main alternate development plans investigated. Unit costs
for marketable energy are listed for a medium interest rate of
5%. Low load growth has been used to show the less advantageous
cases for the hydro developments.
I-6
Dillingham-Section I
APA013/G
TABLE I-2
Bus bar
Cost of Electr1c Energ~ in ¢/kWh
Alternate Plan 1980 1990 2000
1. Dillingham
Continued use of diesel 13.2 21.7 35.3
Lake Elva 20.0 28.3
Grant Lake 20.5 25.7
Lake Elva plus Grant Lake 30.2 22.7
2. Intertied S~stem
Continued use of diesel 1 14.1 22.2 35.8
Lake Elva plus Grant Lake 1 24.9 32.6
Lake Tazimina 1 '2 18.1 15.5
Lake Elva plus Lake Tazimina 1 '2 21.9 18.0
3. Small Communities
Continued use of local diesel 37.4 63.1 101.6
1 10 communities with Dillingham and Naknek.
2 Includes Iliamna, Newhalen and Nondalton.
It should be noted that the above are busbar costs --not costs to
the consumer.
4. Other Electric Ener~ Resources
The most viable alternate at this time to fuel oil or hydro-
electric resources appears to be wind energy conversion. The
available systems are still very costly and reliability of the
equipment in Alaska has not proven acceptable. With continued
improvements it is anticipated that utilization of WECS will
be economically feasible by individuals in remote locations as
well as by electric utilities to offset fuel cost. Applications
for pumping or heating appear to be even more promising. The
cost for electric energy generation by WECS at this time in
the Dillingham or Iliamna areas has to be anticipated between
30¢/kWh and 80¢/kWh. These costs do not include standby
generators.
I-7
Dillingham-Section I
APA013/G
To utilize diesel generation more efficiently--if no other
source of electric energy is available --central generation
with transmission i ntert i es promises cheaper energy, if the
transmission ties are economically feasible. The single wire
ground return0WGR) 1 i ne concept is anticipated to offer
savings of approximately 60% compared to conventional three
phase transmission or distribution lines.
A demonstration project to be built in 1980 in the Bethel area
is presently in the design stage. If the project is successful,
this type of line construction is expected to increase and
make i ntert i es between sma 11 communities and 1 oad centers
possible. For this report the feasibility of interties has
been investigated for 10 communities in the Nushagak/Kvichak
area. It is conceivable that busbar cost of electric energy
in the small communities could be lowered by up to 50% if the
interties to Dillingham and Naknek are built. This is mostly
caused by enhanced generating efficiency and lower fuel cost
in Dillingham and Naknek compared to the small remote communities.
The possibility of an intertie between the Bristol Bay and
Kuskokwim area has been briefly investigated, assuming that
the Tazimina and Kisaralik hydropotential are developed. This
preliminary evaluation indicates that this intertie could be
marginally feasible somewhere around 1995 when the load growth
in the Dillingham area would require implementation of the
Tazimina Stage 2 development. The possible reduction in
standby capacity has not been taken into account in this
evaluation.
The above mentioned i ntert i es actually represent a form of
conservation. It is anticipated that it will not be possible
to reduce electric energy consumption in this area, where
hookup saturation is still 1 ow. Other means of conservation
of fuel oil such as utilization of variable speed engines and
waste heat recovery are strongly encouraged.
5. Conclusions and Recommendations
The economic analysis clearly favors development of the Tazimina
hydropotential for an intertied system of 15 communities. In
order to pursue implementation of this project an institution
to accept responsibility for the construction and operation of
the project must be identified. The circumstances of today
indicate that any such institution would need the financial
strength of the State of Alaska to obtain the necessary funding
at the lowest cost for the communities involved. This institu-
tion could be in the form of a Regional Power Authority or a
Generation and Transmission Cooperative compassed of member
utilities in the region. Under existing Alaska statutes the
I -8
Dillingham -Section I
APA013/G
Alaska Power Authority could provide the financial support of
the state or could accept full responsibility for the project
if the local communities so desired.
If the Tazimina development is not pursued, lake Elva is the
next best choice for Dillin~ham alone. It is the project with
the shortest construction t1me and could be undertaken by the
local utility with REA financing.
Either project should be prepared for FERC license application
as soon as possible to assure the earliest possible start of
construction.
I-9
II. EXISTING SYSTEMS AND FUTURE ELECTRIC
POWER REQUIREMENTS
Dillingham-Section II
APAOll/E
II. EXISTING SYSTEMS AND FUTURE ELECTRIC
POWER REQUIREMENTS
A. INTRODUCTION AND SUMMARY
Although this reconnaissance study is focussing on Dillingham as
the population center in the Nushagak Bay area, it is prudent that
with the investigation of the relatively large hydro potential at
Lake Tazimina an assessment of possible transmission interties to
other communities in the area should be included.
Power requirements to the year 2000 have therefore been established
for the following communities:
Clarks Point
Di 11 i ngham
Egegik
Ekuk
Ekwok
Igiugik
lliamna/Newhalen/Nondalton
King Salmon/Naknek
Koliganek
Levelock
Manokotak
New Stoyahok
Portage Creek
The base data and forecasting parameters have been taken from the
recently completed report 11 Bristol Bay Energy and Electric Power
Potential 11 •1 A2 *
Electric energy for these communities is presently supplied exclu-
sively by diesel generators operated by REA cooperatives in Dil-
lingham, Naknek -King Salmon, Egegik and New Stuyahok. Manokotak
has a city owned power plant and in the remaining villages cannery,
school or private generators are the sources of electric power.
Use of electric energy in the area is low compared to other areas
in Alaska. This is mostly attributed to a low 11 hook-up saturation11
level, low population growth, and 1 ow economic deve 1 opment.
Historical increase in use of electricity supplied by the two major
utilities in the region has been 11% per year since 1970. This
implies that once electric energy becomes available on a reliable
* Superscript refers to Bibliography and References at the end of
this section.
11-1
Dillingham -Section II
APAOll/E
basis the usage will increase not only with new consumer connec-
tions but also with increased use by the individual consumers. The
rapid increase in the cost of electricity in the last few years has
not caused a reduction in consumption, mostly because the users in
the area are still in the process of applying electric energy to
more and more tasks. Generally it can be assumed that the use of
electricity will increase with the increase in family income if the
annual bill remains within a reasonable portion of that income. A
recently completed study for a south central utility 118 in Alaska
showed that over a 35 year period the average energy use by the
individual residential consumers has increased by 2700%, but that
the monthly bill has remained constant between 2.4 and 3.9% of the
family income.
The lowest expected increase of electric energy use for the region
has therefore been assumed to be at 4%/year (average) with a higher
growth during the first 10 years of the study period and a lower
growth during the second half from an estimated 18,900 MWh annually
in 1977 to 46,800 MWh in 2000. This growth can be expected if the
continued use of diesel generation increases the cost for electric
energy at the presently prevailing rate of escalation.
The hi(h ~rowth rate has been assumed to follow the historical
trend tw1ce the low growth rate). This rate implies that more
cost stable energy sources-e.g., hydro, are utilized and encourage
private and industrial use. If the fishing industry expands and
oil or gas development takes place the high growth rate is considered
to be conservative.
Individual power requirement forecasts prepared for certain
communities provide guidelines for evaluation of smaller areas in
regard to potential resource developments.
A bibliography at the end of this section lists studies and publica-
tions used to establish the electric power requirements.
The following tables show the 1977-base-year electric energy use
with demand and energy forecasts to the year 2000 for high and low
load growth scenarios. The various communities have been grouped
to allow assessment by area.
II-2
Dillingham-Section II
APAOll/E
The existing generating capacity (1979) is as follows:
Clarks Point
Egegik
Ekuk
Ekwok
Dillingham
Igiugik
Iliamna/Newhalen/Nondalton
King Salmon/Naknek
Ko 1 i ganek
Levelock
Manokotak
New Stuyahok
Portage Creek
II-3
100 kW
135 kW
75 kW
2600 kW
40 kW
275 kW
3870 kW
50 kW
135 kW
195 kW
100 kW
Dillingham -Section II
APA11/N1
TABLE 11-1
Electric Energy and Power Requirements
HIGH Load Growth
Location 1977 1980 1985 1990 1995 2000
ng
Energy (MWh/year) 4769 6574 12827 19080 32298 45516
Demand ( kW) 1200 1500 2730 3960 6310 8660
Naknek/King Salmon
Energy (MWh/year) 11691 14086 22044 30002 40591 51180
Demand (kW) 2400 2870 4495 6120 7930 9740
Subtotal Dillingham/Naknek
Energy (MWh/year) 16460 20660 34871 49082 72889 96696
Demand ( kW)* 3600 4370 7225 10080 14240 18400
Clark's Point
Energy (MWh/year) 152.7 184 879 1574 1894 2215
Demand (kW) 45 52 326 600 725 850
Egegik
Energy (MWh/year) 101.9 1040 2316 3591 3642 3692
Demand (kW) 40 600 980 1360 1380 '1400
Ekuk
Energy (MWh/year) 21.3 198 233 269 948 '1628
Demand (kW) 6 226 267 308 619 930
Ekwok
Energy (MWh/year) 167.4 203 330 457 982 '1507
Demand (kW) 50 58 94 130 238 345
Igiugig
Energy ( MWh/year) 79.1 158 225 292 410 528
Demand ( kW) 25 45 65 85 103 120
Koliganek
Energy (MWh/year) 160.1 190 356 523 1014 1505
Demand ( kW) 50 54 102 150 248 345
Levelock
Energy ( MWh/year) 171.7 209 419 629 948 1267
Demand (kW) 50 60 120 180 235 290
Manokotak
Energy ( MWh/year) 197.8 338 678 1018 1728 2439
Demand (kW) 58 97 194 290 425 560
New Stuyahok
Energy ( MWh/year) 203.1 267 460 653 118.3 1713
Demand (kW) 100 100 143 186 288 390
Portage Creek
Energy (MWh/year) 83.3 120 198 275 372 468
Demand ( kW) 24 34 57 80 94 107
Subtotal -10 vi II ages
Energy (MWh/year) 1338.4 2907.0 6094 9281 13121 16982
Demand ( kW)* 448 1326 2348 3369 4355 5337
lliamna/Newhalen
Energy (MWh/year) 1000 1543 2215 2887 5578 8270
Demand (kW)* 285 352 506 660 1190 1720
Total
Energy (MWh/year) 18798.4 25110 43180 61250 91588 121948
Demand (kW) 4333 6648 10079 14109 19785 25457
*Noncoincident
Note: System losses not included.
II-4
Dillingham -Section II
APA11/N2
TABLE 11-2
Electric Energy and Power Requirements
LOW Load Growth
Location 1977 1980 ·1985 1990 1995 2000
Dillingham
Energy (MWh/year) 4769 5930 8500 11070 13521 15972
Demand (kW) 1200 1500 2040 2580 3115 3650
Naknek/King Salmon
Energy (MWh/year) 11691 12526 15648 18770 20923 23076
Demand ( kW) 2700 2550 3190 3830 4265 4700
Subtotal Dillingham/Naknek
Energy (MWh/year) 16460 18456 24148 29840 34444 39048
Demand (kW)* 3600 4050 5230 6410 7380 8350
Clark's Point
Energy (MWh/year) 152.7 160 175 191 537 883
Demand (kW) 45 46 51 55 153 250
Egegik
Energy (MWh/year) 101.9 413 966 1517 1600 1683
Demand ( kW) 40 600 645 690 730 770
Ekuk
Energy (MWh/year) 21.3 188 195 203 290 378
Demand (kW) 6 214 224 233 260 287
Ekwok
Energy (MWh/year) 167.4 178 198 218 257 297
Demand (kW) 50 51 57 62 65 68
Igiugig
Energy (MWh/year) 79.1 145 155 166 199 232
Demand (kW) 25 41 45 48 51 53
Koliganek
Energy (MWh/year) 160.1 170 188 206 296 386
Demand (kW) 50 50 54 58 73 88
Levelock
Energy (MWh/year) 171.7 183 205 228 343 458
Demand (kW) 50 52 58 65 85 105
Manokotak
Energy (MWh/year) 197.8 257 264 271 398 523
Demand (kW) 58 73 77 80 100 120
New Stuyahok
Energy (MWh/year) 203.1 232 256 280 384 488
Demand (kW) 100 115 100 100 100 110
Portage Creek
Energy (MWh/year) 83.3 110 134 156 190 224
Demand ( kW) 24 31 38 45 48 50
Subtotal -10 villages
Energy (MWh/year) 13384 2036 2736 3436 4494 5552
Demand ( kW )* 448 1273 1349 1436 1665 1901
lliamna/Newhalen
Energy (MWh/year) 1000 1382 1571 1761 1955 2149
Demand (kW)* 285 315 357 400 445 490
Total
Energy (MWh/year) 18798.4 21874 28455 35037 40893 46749
Demand ( kW) 4333 5638 6936 8246 9490 10741
*Noncoincident
Note: System losses not included.
II-5
Dillinqham-Section II
APAOll/E
C. PROJECTION PARAMETERS
The historical growth pattern for the population of the Bristol Bay
Area is shown on Figure II-1. Possible extrapolations for future
growth assume the rate for 1960-1977 as the low growth rate. The
higher rates shown represent the predicted growth of 2% per year
and more from the Alaskan portion of the U.S. Department of Commerce
Study 11 Preliminary Forecast of Likely Use of Electric Energy to the
Year 2000 11 (11/1/78) and from the 11 Man in the Arctic'' Model used
for the Southwestern Region in the University of Alaska, Institute
of Social and Economic Research Publication 11 Alaska Electric Power
Requirements 11 (6/77). The growth beyond 1990 to the year 2000.
from the ISER publication has been extrapolated at the rate of
growth from 1980 to 1990.
Although the ISER study assumes an overall higher growth rate
caused by oil and gas development it is anticipated that small
villages will not particularly benefit from the capital intensive
petroleum developments.
Expansion and development of the fishing industry, agriculture etc
\>Jill tend to increase the population growth ·in rura 1 areas. The
population increase shown for the individual locations (parts C
to G of this section) takes this differentiation into account and
addresses it in greater detail.
ft is further assumed that the number of members per household will
follow the overall Alaska tendency and decrease from the average
1977 ratio of 5 10 '"' in the Bristol Bay Area at a rate of 1% per· year
to an average of 4 by the year 2000. Therefore the number of
r·e_?j de_~!!_L~-t~l ectri c energy users wi 11 increase at a higher rate
than the population. The number of small commercial energy users,
e.g. stores or shop facilities is assumed to increase in direct
proportion to that of residential consumers.
In Dillingham and Naknek, where power requirements forecasts were
available for the electY'ic utilities, population growth has not
bf?en projected.
tlectrical energy use has been historically low compared to other
a·r'eas in Alaska, but if a central power supply becomes available
for the i ndi vidual villages it is expected that the demand #OU 1 d
gradually increase to levels that are comparable to the projected
use in the Kodiak area.
The intens in the individual use of electrical energy (kWh per
mont per· consumer) has been escalated under two d ifferePt
assumptions:
II -6
/
I ;'
I
I
I
/
/
/
/
.I
.I
/
'
HISTORICAL OATA 1$ U.S.
CENSUS INFORMATION
FOR IHO &. 1970
1971 DATA FltOM DEPARTMENT
OF e:•VIRONMENTAL
lfti'"OMIATION
8---e ISER !LOWI }
EJ..·-·<3 18£111 I HI6H l I.W. AREA
o---o U.S. DEPT. OF COMM.
1918-2000 ENERGY
FORECAST FOR
ALAS« A
~L---------~------+-~----------+---------~~
1960 1970 I 1980 9
7
7
YEAR
IMO
II-7
2000
BRISTOL BAY POPULATION
HISTORICAL a FUTURE TRENDS
FIGURE n: -I
Dillingham -Section II
APAOll/E
1. If electricity continues to be generated by small diesel en-
gines and the cost of fuel is escalated at a rate of 2% above
the general inflation rate, the individual increases in usage
will be less than the historical growth rates for the various
locations until 1990. After 1990 further decreases in growth
rates will be experienced, reflecting increased use of energy
conservation measures.
2. If a more !!cost stable11 source of power (hydro) becomes avail-
ab 1 e the higher intensity of use wi 11 reflect the increased
utilization of electricity for appliances and some electric
heating.
The economic backbone of the Bristol Bay area at this time is the
salmon fisheries. Large Power Consumers (LPs) are therefore mostly
fish processors. A total of 20 fish processing facilities are
operable and processing an average of 60-70,000,000 lbs. of salmon
per year.103 At this time all canneries generate their own electric-
ity at peak season with diesel generator sets up to 600 kW in size.
The addition of freezing and cold storage facilities will increase
the demand by an average of 150 to 300 kW per cannery. The present
processing season (June/July) is expected to be extended by an
increase of Herring catches. Bottom fishing will have an impact on
the communities with ice-free ports on the Pacific ocean side of
the peninsula. It is expected that electric energy for all canneries
will be supplied by central plants within the next 20 years. A
dramatic increase in number of facilities and electric energy use
for the individual canneries beyond the above addressed parameters
is not anticipated. Therefore the following energy use will be
assumed for an average processing faci 1 ity:
Peak Demand:
Canning only
With additional freezing facilities
Monthly energy use during peak season
( ~lune/July):
Canning only
With additional freezing facilities
Year around average use:
200 -400 kW
300 -600 kW
80K -150K kWh/mo.
150K -250K kWh/mo.
3K -10K kWh/mo.
Development of Bristol Bay oil and gas reserves will begin with a
lease sale in the Southwest Bristol Bay uplands in 1981 1 . Offshore
exploration and development is still very controversial and not
expected until the late 1980's or early 1990's. Exploration in
1 Oil and Gas Journal 2/26/79
II-8
Dillingham -Section II
APAOll/E
itself is not expected to have a major impact on the electric power
requirements. Development and operation of a reservoir will have
power requirements in the magnitude of 50 -200 MW and depend
greatly on location (offshore/land) and size of the reservoir.
Therefore attempts to assess these possibilities at this time are
virtually impossible.
C. DILLINGHAM (INCLUDES ALEKNAGIK, KANAKANAK AND OLSONVILLE
Dillingham serves as a major transportation hub for the surrounding
villages. The economy is based on the fishing industry, government
and native corporation expenditures, and trapping. Development
potential exists for oil exploration with the first lease sale
anticipated in 1981 1 . The exploration activities are expected to
cause only a temporary increase of the population in the Dillingham
area by 50 to 100. If commercial amounts of natural gas or oil are
found a permanent increase in population to 4 to 6 times the present
is conceivable. This development would start after 1986 and not
culminate until after the year 2000. For this study the impact of
oi 1 and gas deve 1 opment on popu 1 at ion has not been taken into
account.
The historic growth for Nushagak Electric since 1970 has been as
follows:
Number of Consumers
Energy Use
Peak Demand
5% increase per year
12% increase per year
13% increase per year
It is anticipated that with or without oil development the population
and with it the number of consumers in the Dillingham area will
continue to grow at a rate above the growth rate for the overall
Bristol Bay Region.
The latest power requirements study for the co-op was prepared in
1977 and used the following growth rates for the next 10 years:
Number of Consumers
Energy Use
Peak Demand
5% increase per year
11% increase per year
11% increase per year
The above rates follow the historical pattern with a slight decrease
in growth rate for energy use. The study does not anticipate
drastic changes in the development of the Dillingham area.
1 The Oil and Gas Journal -February 26, 1979
II-9
Dillingham-Section II
APAOll/E
Agricultural potential has been investigated and preliminary find-
ings indicate relatively good potential 102 for certain grains in
the Nushagak valley, although further tests will have to be conducted.
It is anticipated that major agricultural developments will mostly
influence the villages in the valley and Dillingham only by the
influx of small commercial enterprises.
The fishing industry is expected to expand but year around operation
is precluded due to pack ice conditions during the winter months.
The two possible development scenarios shown on ''Dillingham-Power
and Energy Requirement 1977-2000" and in the table "Dillingham-
Electric Power Requirements 1977 -2000" are based on the following
parameters:
1. Low Growth Scenario
The number of residential consumers increases in relation to
the population growth with a 1% per year reduction in family
size. Overall energy use is anticipated to reflect the rapidly
increasing cost of diesel-generated electric power.
Use by residential consumers is expected to grow in accordance
with the previously mentioned power requirements study until
1990 (7% per year) and then reduce to 4%/year reflecting
energy conservation measures. Consumption by small commercial
consumers will generally follow the trend established for
residential users.
Industrial use and other large power consumers use has been
evaluated as follows;
a. Schools and Public Buildings -
To increase at population growth rate.
b. Fish Processing Industry -
The existing cannery and cold storage facility are ex-
pected to be supplied by the central utility; no further
additions are anticipated.
2. Accelerated Growth Scenario
This scenario would fit two possible developments:
a. The individual energy usage grows as assumed under the
"low growth 11 scenario but the population growth is accel-
erated due to oil and gas or other industrial development.
I I -10
Dillingham -Section II
APAOll/E
b. If a cost stable source of power becomes available -such
as hydro-it is conceivable that the individual use will
increase to more than twice the use anticipated at low
load growth. This increase would account for some utiliza-
tion of electric heat. In this case the number of consumers
is assumed to grow as described under the 11 1 ow growth"
scenario.
While the system projections on Figure II -2 11 Power and Energy
Requirements" can be used for either development, the "cost
stab 1 e" source has been used for the resident i a 1 and sma 11
commercial consumer category in the table.
Again the small commercial consumers and their usage follow
the trend of the residential consumers. For large power users
the base estab 1 i shed in the 11 1 ow growth" scenario has been
utilized and one additional processing facility has been
added.
3. Existing systems and Seasonal Use
Nushagak Electric Cooperative, the Dillingham local electrical
utility, supplied historical usage data 113 . During the calendar
year 1977, the utility generated electricity at an average
rate of 12.20 kWh/gallon of fuel. The cannery was not connected
to the central utility and its electrical consumption was
estimated. Waste heat from the power plant is utilized to 1
heat Nushagak Electric's office and warehouse space.
Nushagak Electric is a federally financed (REA) utility which
had 2600 kW of generating capacity in 1977. Nushagak distributes
power over a dual voltage distribution system. The in-town
distribution feeder is in the process of being converted from
a 2400 volt three-phase system to a 7.2/12.5 kV three phase
system.
The following Figure II-3 "Dillingham-Seasonal Electric
Energy Use" attempts a corre 1 at ion between demand and energy
use on a monthly basis if fish processors are centrally supplied.
It should be noted that this graph is only valid if the assumed
ratio between normal system load and processing load remains
constant (1977 base plus 2 processors with cold storage).
II-11
000
000
000
000 40,
eo, nnn
IOpoiJ • 000
000 •
7'000
15000
5000
000
000
DILLINGHAM
POWER REQUIREMENTS 1977-2000
~ HIGH
~
/
~ , ~ ~
LOW
L ....,..-
/' _,. _ ...
HIGH
/..,-..,.,.
~ /'
MWH _.L_.,.,.
qJ _,/ ,..,.,.. """""'---....
LOW
{~~ , -----~i ..... 1-
.. ...:>... .,........-----,. ......... __.. .......... -
"""' ........
( UKW
-------
1980 ,. .. !9i)0 1995 2000
FIGURE li -2
TJ -] ~
DILLINGHAM£ ALEKNAGIK£ KANAKANAK£ OLSENVILLE
{NUSHAGAK ELECTRIC ASSOCIATION)
ELECTRIC POWER REQUIREMENTS 1977-2000
1977 1980 1990 2000
POPULATION 1025
( 1) # of residential 359 (high) 404 590 750
consumers (low) 404 590 750
(2) average kWh/mo/ 370 (high) 478 799 1690
consumers (low) 413 558 630
(3) MWh/year 1596 (high) 2317 5655 15210
residential cons. (low) 2000 3950 5670
(1)x(2)x12
(4) # of small commercial 80 (high) 90 133 170
consumers (low) 90 133 170
(5) average kWh/mo/ 1224 (high) 1581 2633 5542
consumer (low) 1278 1911 2158
(6) MWh/year 1175 (high) 1707 4202 11306
sm. com. cons. (low) 1380 3050 4402
(4)x(5)x12
(7) # of large 61 (high) 62 66 72
cons. + public buildings (low) 62 66 71
(8) average kWh/mo/cons 2730 (high) 3427 11645 21991
(low) 3427 5139 6925
(9) MWh/year 1998 (high) 2550 9223 19000
LP 1s (low) 2550 4070 5900
(7)x(8)x12
(1 0) System MWh/year 4769 (high) 6574 19080 45516
(3)+(6)+(9) +200 (low) 5930 11070 15972
+ cannery in 1977
(11) System .45 (high) .5 .55 .6
Load Factor .47 (low) .45 .49 .5
(12) System Demand 1200 (high) 1500 3960 8660
kW 1200 (low) 1500 2580 3650
(10)+8760+(11)
Note: MWh listed are sold -not generated.
II-13
DILLINGHAM
SEASONAL ELECTRIC ENERGY USE
10 'Yo
~;-
. "'"
!I%
1!1 %
I
I
T o/o -----·----~ -----· ~--
I
I 8 % ----~~ ----~---------------------· ----------~-~ ----·----
1-'
.t::.>
...J
<( ...
0 --!! % ...
...J
<!
::>
z 4 % -~-·-~------------~--
2
<!
"-I
0
# ·-! %
I
' ------. I 2 'X
I
I
I 'X j
,JAN r:E8 MAR J'P!> ~~,\)" JUNE JULY AUG SEPT ocr NOV OEt-:
FIGURE JI -3
Dillingham-Section II
APAOll/E
D. NAKNEK/KING SALMON
General economic and population patterns are considered similar to
the Dillingham area, therefore the general system growth has been
assumed at the same rates as the Dillingham system.
The military installations at King Salmon are expected to remain
constant in their electric energy use for the time considered in
this study. With 9 fish processing facilities presently located in
the Naknek/South Naknek area it is assumed that eventually all the
electric energy used by these facilities will be supplied by a
central utility. It is further expected that most processors that
presently exclusively can fish will add fresh-freezing equipment 1
and cold storage facilities. A gradual extension of the fishing
season from 2 to about 4 months is expected when other fish than
salmon will increasingly be utilized. Herring appear to have good
potential when the harvesting techniques are adapted.
The energy use for the large power consumers reflects the above
parameters by assuming 9 processors operating canning and freezing
equipment for 4 months in the year 2000 in the accelerated development
scenario. The low growth parameters have been established with the
following fish processing facilities in 2000:
4 processors canning 2 months
4 processors canning and freezing 2 months
1 processor canning and freezing 4 months
Load and consumer projections have been based on a 1978 REA power
requirements study for Naknek Electric Association.
State of Alaska, Department of Fish and Game, Letter of 3/19/79
II-15
100,000
90,000
80,000
70,000
60.000
60,000
40,000
ro,ooo
to,OOO
11000
8000
7000
6000
1000
NAKNEK
POWER REQUIREMENTS 1977-2000 --
HIOH -------~
~~ LOW
~ ~ ~
(~MWH
-·-HIGH ---·~
-.,..,...... --.-.....
,_..,. .....--~-----LOW
----
,.. ..
~,.,..... -j-tEA.R t,<.'#l~-----.......
~--( ~KW
--
ltllO 19&5 199() IS> ill ?000
F JGURE TI --4
II-16
Section Ill -Demand Projections
APA011/B3
NAKNEK -SOUTH NAKNEK -KING SALMON
ELECTRIC POWER REQUIREMENTS 1977-2000
1977 1980 1990 2000
-----~-
POPULATION 500
( 1 ) # of residential 203 (high) 258 410
consumers (low) 258 410 525
(2) average kWh/mo/ 534 (high) 618 888 1690
consumers (low) 528 620 643
(3) MWh/year 1302 (high) 1913 4367 10647
residential cons. (low) 1635 3050 4050
(1)x(2)x12
(4) # of small commercial 76 (high) 104 165 2'11
consumers (low) 104 165 211
(5) average kWh/mo/ 2680 (high) 2847 4090 7740
consumer (low) 2300 2960 3003
(6) MWh/year 2444 (high) 3553 8098 19600
sm. com. cons. (low) 2871 5860 7603
(4)x(5)x12
(7) # of large 13 (high) 18 20 21
cons. + public buildings (low) 18 19 "19
(8) average kWh/mo/cons 50929 (high) 39907 73071 83068
(low) 37130 43246 5010'1
(9) MWh/year 7945 (high) 8620 17537 20933
LP's (low) 8020 9860 11423
(7)x(8)x12
( 10) System MWh/year 1169'1 (high) 14086 30002 51180
(3)+(6)+(9) 1440 (low) 12526 18770 23076
+ cannery in 1977
( 11 ) System .56 (high) .56 .56 .6
Load Factor .56 (low) .56 .56 .56
(12) System Demand 2400 (high) 2870 6120 9740
kW 2700 (low) 2550 3830 4700
( 10 )787607( '11)
Note: MWh listed are sold -not generated.
II-17
Dillingham-Section II
APAOll/E
1. Existing Systems and Seasonal Use
El ectri ca 1 energy usage information was supplied 1-Jy Naknek
Electric Association 114 (NEA) and by the U.S. Air Force 105 .
N. E. A. is a federally financed (REA) utility which serves
Naknek, South Naknek, portions of King Salmon and Egegik.
Although Egegik is officially part of the N.E.A. system it has
its own generation and distribution facilities. While the
majority of the canneries in the Naknek area are connected to
the electric utility, they use their own generation facilities
when fish processing begins. During the calendar year 1977,
Naknek Electric Association generated electricity at a rate of
11.86 kWh/gallon of fuel. During the same period of time the
military generated at 13.22 kWh/gallon. Waste heat from the
NEA generating plant is utilized to heat the Naknek High
Schoo 1.
Naknek Electric Association distributed electrical energy to
the Naknek area over two 7.2/12.5 kV 3 phase feeders. It is
currently in the process of converting one of these feeders to
a 14.4/24.9 kV 3 phase system and with it wi 11 eventually
supply power for the U.S. Air Force Base in King Salmon.
The Air Force is presently operating a 2400 Volt delta system.
Naknek Electric Association had 1400 kW of installed power in
1977. An additional 2320 kW was installed in 1978.
The Air Force has an installed generating capacity of 1950 kW.
If all canneries are centrally supplied it is anticipated that
the system will be a summer peaking system with load charac-
teristics approximately as shown on Figure II-5 ''Naknek-
Seasonal E 1 ectri c Energy Use''
Il 18
~\ ~ \ \ \ l ' 'it ~ ~ ' v I
I ,, ·:/ .. • I """' , v ,. ,... ~"'
/ , .. ' i v ,..
v
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\ " -r--...... "" lf ~ ...... .......... ~ z ... .... ~ I ..........
......
I \ I ' I
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I Ill z
Ill
• II
J ' I
\
/~
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/ ,.
"#. #. if. .,. .,. ' .,.
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ONYIIJO )IYJ<II 1YnNNY .40 "'
# .,. .,. ~ ~ • ,
1YJ.OJ. 1YnNfn' ;10 %
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CONSULTING
ENGINEERS
ROBERT W. RETHERFORD ASSOCIATES
o;STRICT IWERNATION.AL ENGI'<EERING . INC
0 BOX 6410 ANCHOf1AGE AlASKA 99502
PHONE (907) J44-2585 TELEX 626 380
April 28, 1980
Alaska Power Authority
333 W. 4th Avenue, Suite 31
Anchorage, Alaska 99501
Attn: Mr. Robert Mohn , Director of Engineering
Subject: Reconnaissance Study of the Lake Elva
and other Hydroelectric Power Potentials
in the Dillingham Area
Dear Mr. Mohn:
9703-114
We are pleased to submit the final report on the 11 Reconnaissance
Study of the Lake Elva and other Hydroelectric Power Potentials in
the Dillingham Area 11
• The following potential hydroelectric sites
have been found feasible to be developed:
Lake Elva
Grant Lake
Tazimina Lake
1.5 MW prime capacity
2.7 MW prime capacity
9.0 MW prime (1st stage) capacity
+9.4 MW prime (2nd stage) capacity
The demand for electric power in Dillingham is anticipated to
increase from 1.2 MW in 1977 to 3.7-8.6 MW in the year 2000. The
energy from the Lake Elva Project -located only 29 miles from the
existing Nushagak Electric Association's distribution system could
be completely utilized by the time it is built. If the potential
is developed as a 11 minor 11 project (1,500 kW installed or less) the
licensing process is expected to be short and construction could be
completed in 1983. The project is, however, relatively expensive
with total construction cost estimated at $12,940,000.
Grant Lake -Located at a greater distance from the loadcenter and
less accessible -is expected to be more difficult to develop and
require a greater amount of mitigative measures to protect existing
salmon spawning grounds. Development could follow the Lake Elva
project if warranted by load growth.
The Tazimina Lake hydroelectric potential appears to be very attrac-
tive economically in spite of the great distance to the load centers.
It is obviously too large for a single community like Dillingham,
INTERNATIONAL ENGINEERING COMPANY, INC.
A MORRISON-KNUDSEN COMPANY
Mr. Robert Mohn
Page 2
April 28, 1980
9703-114
but if a regional system with approximately 15 communities in the
Bristol Bay area is considered, the capacity balance indicates that
the staged development could accommodate the projected load growth
very effectively. The cost of construction will, however, require
the financial backing of the Alaska Power Authority and the number
of communities involved calls for a regional entity capable of
constructing and operating such a system. Other restraints on this
project are land status and ownership and the environmental impact
of the necessary long transmission lines.
Realization of the Lake Elva project promises fastest relief in
regard to the dependency on diesel fuel for electric energy genera-
tion at this time, while the Tazimina project appears to be the
long-range solution for a larger number of communities. Therefore,
it is recommended that:
1. The Lake Elva project be implemented as soon as possible, and
that a FERC license application to build it as a 11 minor project11
be prepared if it is determined to be under FERC jurisdiction.
2. A regional entity be established so that the Tazimina potential
can be brought to FERC license status.
A regional system with low cost transmission lines connecting small
communities to the larger load centers of Dillingham/Naknek will
result in less costly electric energy in the small villages even
with continued diesel generation due to the more efficient use of
fuel in larger engines and the lower fuel cost in the centers. It
is therefore strongly recommended to investigate these interties at
greater depth for the individual communities.
It has been a challenge working on this study and we trust the
resulting report will help in the decision process for alternate
energy resources.
Sincerely,
l fe;lf
Dora L.
Project
Gropp, P. E.
Engineer
DLG: kye
Enclosures
Dillingham-Section II
APAOll/E
E. ILIAMNA -NEWHALEN -NONDALTON
This area has been evaluated separately, because only development
of the Lake Tazimina hydro potential will have a significant impact
on the electric power supply in these communities.
Iliamna is rapidly developing into the center of activities in the
entire Lake Iliamna area. The economy is based on fishing and
tourism during the summer and in Iliamna itself on employment in
government and state offices as well as lodges.
A system planning study 117 for forming an electric co-op has been
used as a base for the power requirements in this area. The growth
projections in the system study are considered very conservative
and have therefore been used as the 11 low ijrowth 11 scenario. For the
11 accelerated growth 11 scenario it has aga1n been assumed that the
availability of less cost intensive hydro-power will encourage the
use of electricity by residential and small commercial consumers to
an extent where the individual use will reflect the utilization of
some electric heat, ranges, clothes dryers, water heaters, etc. and
larger residences. In the large consumer category the addition of
a third school between 1980 and 1990 and cold storage facilities or
a similar consumer between 1990 and 2000 have been assumed.
There are no existing central electrical systems in Iliamna, New-
halen or Nondalton. There are however, private individuals and
several organizations in the area that maintained private generation
facilities. The schools in Newhalen and Nondalton each have an
installed capacity of 150 kW. The Federal Aviation Administration
facility in Iliamna has an installed capacity of 125 kW and generated
an average of 23,000 kWh/month. The FAA distribution system operates
at 2400V.
Without a central utility in the past, historical or seasonal
electricity use is not available. The system is expected to be
winter peaking with an annual load factor of .5 to .55.
The following figure 11 Iliamna -Power Requirements 1977 -2000 11 and
Table 11 Iliamna -Electric Power Requirements 1977 -2000 11 show the
anticipated use for the area.
II-21
10,000
fl
eooo
7
non
000
6000
000
2000
tO 00
00 •
7 00
r. 00
400
00
00 -·
100_
(.:)MWH
~)KW
1971
ILIAMNA I NEWHALEN/NONDALTON
POWER REQUIREMENTS 1977-2000
/
/
~ ......
~ ~ ~ ----
/
7
_.,/
_.,.:'' .,.,.,....._.
_,....,.,..... . ..-------_.._.. PE~l( -~----..;_~ -
--i--·
/
HIGH
/
/
~
-LOW
~
//
/
// ....,..
IUOH
---· ---LOW
~
1960 1985 19110 199& ?000
FIGURE n-S
ll-22
Section Ill -Demand Projections
APA011/B4
I L I AMNA/N EWHALEN/NON DALTON
ELECTRIC POWER REQUIREMENTS 1977-2000
1977 1980 1990 2000
POPULATION 389 (high) 409 484 573
(low) 402 448 500
(1) # of residential 61 (high) 97 165 210
consumers (low) 97 165 210
(2) average kWh/mo/ 280 (high) 438 597 1200
consumers (low) 360 360 360
(3) MWh/year 206 (high) 510 1181 3024
residential cons. (low) 419 713 907
(1)x(2)x12
(4) # of small commercial 27 (high) 26 44 56
consumers (low) 26 28 38
(5) average kWh/mo/ 971 (high) 1260 1716 3461
consumer (low) 1035 1214 1300
(6) MWh/year 314 (high) 393 906 2326
sm. com. cons. (low) 323 408 602
(4)x(S)x12
(7) # of large 3 (high) 4 4 6
cons. + public buildings (low) 4 4 4
(8) average kWh/rna/cons 13344 (high) 13333 16666 40556
(low) 13333 13333 13333
(9) MWh/year 480 (high) 640 800 2920
LP's (low) 640 640 640
(7)x(8)x12
(10) System MWh/year 1000 (high) 1543 2887 8270
(3)+(6)+(9) (low) 1382 1761 2149
(11) System .4 (high) .5 .5 .55
Load Factor (low) .5 .5 .5
(12) System Demand 285 (high) 352 660 1720
kW (low) 315 400 490
(10)+8760+(11)
Note: MWh listed are sold -not generated.
II-23
Dillingham-Section II
APAOll/E
F. TEN VILLAGES IN RURAL BRISTOL BAY
The communities addressed in this section are located close enough
to present load centers to allow assessment of a transmission
intertie to existing central utilities in Dillingham or Naknek.
The ten villages are:
Clark's Point
Egegik
Ekuk
Ekwok
Igiugig
Koliganek
Levelock
Manokotak
New Stuyahok
Portage Creek
Historical population growth for the villages has been varied and
will be addressed individually. To determine future power require-
ments it has generally been assumed that a central station will
supply electric energy. The effect of improved electric service is
anticipated to be an increase in the intensity of use as compared
to individually operated generators.105 Further with the subsis-
tence economy changing in many communities into a cash economy and
subsequent improvements in the quality of life, new electric loads
will require service.111 The HUD houses planned for various villages
will be larger than existing older housing and be equipped with
more appliances using electricity.
Water and sewage treatment plants, new and larger schools and cold
storage facilities are expected to be installed in all villages
during the time covered by this study.
The scenarios of low or accelerated growth will again greatly
depend on the cost of power and the economy in the individual
community. By assessing the villages individually or within the
geographic setting it has been attempted to arrive at projections
that are most likely to be realized. Power requirement studies
prepared for the REA-Co-op supplied communities Togiak, New
Stuyahok and Egegik have been used as guidelines for other villages
with similar conditions.
II-24
Dillingham-Section II
APAOll/E
1. Clark's Point
Similar to Ekuk this village has experienced flooding and
relocation has been planned. The population has declined from
130 in 1960 to approximately 70 in 1977. With new housing
units p 1 an ned by HUO and increased incomes in the fishing
industry the growth potential is considered good and has been
assumed at 5% per year (high) to 1990, dropping to 2.5% per
year after that year for this study. Low growth has been set
at 1% per year. School, community buildings and eventually
fish processing facilities are anticipated in the large consumer
section between 1980 and 1990.
II-25
toOO
tiOOO
l'tlQt'!
toOO
lltlOO
<tllOO
1000
toot!
1000
1100
1100
100
1100
800
400
11100
lroO
( D"'WH
100
91'1
10
l'O
•o -
50
G DKW"
40
!oO
!()
10
CLARK 1 S POINT
POWER REOUIREMEN;TS 1977-2000
'
--
/ ~
_,
/
I' ....-
/ ~-/ /
/ ./
/ //
lL J/
~ ~
MWH/YEAI!/
__....-
//
f _, , .,-
f ...,..---~
.U..~----
-----L
/
/
/ v
)
/
/
/
"""
·-
HIGH
LOW
HIGH
LOW
1980 1911 , ... l!OOO
FIGURE lr -7
II-2(
Section II I -Demand Projections
APA011/B5
CLARK'S POINT
ELECTRIC POWER REQUIREMENTS 1977-2000
1977 1980 1990 2000
POPULATION 62 (high) 72 117 150
(low) 62 64 65
( 1 ) # of residential 15 (high) 18 32 43
consumers (low) 15 17 19
(2) average kWh/mo/ 121 (high) 179 468 1000
consumers (low) 135 205 234
(3) MWh/year 21.9 (high) 39 180 516
residential cons. (low) 24 42 53
(1)x(2)x12
(4) # of small commercial 2 (high) 2 4 5
consumers (low) 2 2 3
(5) average kWh/mo/ 805 (high) 1208 3111 6646
consumer (low) 833 1375 1667
(6) MWh/year 19 (high) 29 149 399
sm. com. cons. (low) 20 33 60
(4)x(5)x12
(7) # of large 3 (high) 3 4 4
cons. + public buildings (low) 3 4 4
(8) average kWh/mo/cons 3099 (high) 3222 25938 27083
(low) 3222 3222 16042
(9) MWh/year 111.6 (high) 116 1245 1300
LP's (low) 116 116 770
(7)x(8)x12
(10) System MWh/year 152.7 (high) 184 1574 2215
(3)+(6)+(9) (low) 160 191 883
(11) System .4 (high) .4 .3 .3
Load Factor (low) .4 .4 .4
(12) System Demand 45 (high) 52 600 850
kW (low) 46 55 250
(10)+8760+(11)
Note: MWh listed are sold -not generated.
II-27
Dillingham-Section II
APAOll/E
2.
10 ,000
51000 aooo
7000
eooo
!IOOC
400C
:.000
t'ooO
1000
900
eoo
700
600
:.oo
400
!-(){)
11'00
too
fJn
110
70
60
~
40
30
:ro
10
The population has been stable at around 100 people for the
last 17 years. The existing two canneries have only operated
during high eye l e sockeye runs in the past. It can be ex-
pected that the canneries will diversify in the future 108 and
also add freezing equipment. This would influence the village
economy favorably ana a moderate growth of 1% per year (high)
or .2% per year (low) is anticipated.
The demand shown for 1980 includes 2 operating fish proces~ot~.
EGEGIK
POWER REQUIREMENTS 1977-2000
'
----/ v
v MWH I Yl AR
~ ~---f.-----
."?
.,.."'/
--:77 ICVI PEA~ 1/'!'.f:A.Ji --z...z __
~-----""""" -7
17
{ ";\MWH
-
1 l-\KW
HIGH
LOW
HIGH
LOW
19110 1911& 1~0 19~!1 1!'000
FIGURE JI -8
II 28
Section Ill -Demand Projections
APA011/B9
EGEGIK
ELECTRIC POWER REQUIREMENTS 1977-2000
1977 1980 1990 2000
POPULATION 148 (high) 152 168 186
(low) 149 152 155
(1) # of residential 21 (high) 22 40 44
consumers (low) 22 30 31
(2) average kWh/mo/ 183 (high) 193 212 230
consumers (low) 183 190 195
(3) MWh/year 46.4 (high) 51 101 121
residential cons. (low) 48 68 73
(1)x(2)x12
(4) # of small commercial 7 (high) 7 8 9
consumers (low) 7 7 7
(5) average kWh/mo/ 661 (high) 702 885 1028
consumer (low) 661 700 710
(6) MWh/year 55.5 (high) 59 85 111
sm. com. cons. (low) 55 59 60
(4)x(5)x12
(7) # of large (high) 3 6 6
cons. + public buildings (low) 3 6 6
(8) average kWh/mo/cons (high) 25833 47292 48056
(low) 8611 19306 21528
(9) MWh/year (high) 930 3405 3460
LP's (low) 310 1390 1550
(7)x(8)x12
(10) System MWh/year 101.9 (high) 1040 3591 3692
(3)+(6)+(9) +400 (low) 413 1517 1683
+ cannery in 1977
(11) System (high) .2 .3 .3
Load Factor . 1 (low) . 1 .25 .25
(12) System Demand 40 (high) 600 1360 1400
kW +600 (low) 600 690 770
(10)+8760+(11)
Note: MWh listed are sold -not generated.
11-29
Dillingham-Section II
APAOll/E
3. Ekuk
The population has grown very slowly since 1960 to approx-
imately 50 people in 1977. The summer population, however, is
up to 10 times as high due to commercial and subsistence
fishing. Relocation of the village site is planned to prevent
seasonal flooding. The relocation would probably halt decline
in the population and provide employment. Growth has there-
fore been assumed at 2% per year (high) and at 1% per year
(low). Community buildings, a school, and addition of freezing
equipment in the cannery are the expected increases in the
large consumer section.
The projected demand in 1980 includes the cannery which did
not operate in the base year.
EKUK
POWER "EOU1R[II[NT8 1!177-2000
000 --10000
""'
"""" ,, ·-
.....
"""' I
.. ....
""" .....
.L. -/..-
000 -4" -..,.,. -1-----?' /
=---·~~_c:_~ __..e:;---
""" .. ...
'::' ..,
•of--· --
""
...,
... -..,
..,~ ~;· .. .. .., .... ·-, ... . -fOGUII( ll -ll
II-30
Section Ill -Demand Projections
APA011/B6
EKUK
ELECTRIC POWER REQUIREMENTS 1977-2000
1977 1980 1990 2000
POPULATION 57 (high) 60 74 90
(low) 59 65 72
( 1 ) # of residential 8 (high) 9 12 14
consumers (low) 8 9 10
(2) average kWh/mo/ 121 (high) 179 468 1000
consumers (low) 135 205 234
(3) MWh/year 11.7 (high) 19 67 168
residential cons. (low) 13 22 28
(1)x(2)x12
(4) # of small commercial 1 (high) 1 1 2
consumers (low) 1 1 1
(5) average kWh/mo/ 803 (high) 1208 3111 6646
consumer (low) 833 1375 1667
(6) MWh/year 9.6 (high) 14 37 160
sm . com . cons . (low) 10 16 20
(4)x(5)x12
(7) # of large 0 (high) 2 2 4
cons. + public buildings (low) 2 2 3
(8) average kWh/mo/cons 0 (high) 6875 6875 27083
(low) 6875 6875 9167
(9) MWh/year 0 (high) 165 165 1300
LP's (low) 165 165 330
(7)x(8)x12
(10) System MWh/year 21.3 (high) 198 269 1628
(3)+(6)+(9) (low) 188 203 378
+ cannery in 1977 +200
( 11 ) System .4 (high) . 1 . 1 .2
Load Factor . 1 (low) . 1 . 1 . 15
(12) System Demand 6 (high) 226 308 930
kW +252 (low) 214 233 287
(10)+8760+(11)
Note: MWh listed are sold -not generated.
I 1-31
Dillingham-Section II
APAOll/E
4) Ekwok
This community has experienced a slight decline in population
from 130 in 1950 to approximately 109 in 1977. A new school
is planned be be built in 1979/80 and other community improve-
ments are anticipated. The population growth has been assumed
at 1% per year for the high development and .2% per year for
the low development alternate.
EKWOK
POWER REQUIREMENTS 1977-2000
10 ,000
v.xx>
8000
1'000
8000
!'llYYl
4000
3000
1':000
1000 /
eoo --eoo _/
./ 100 ~ 600
&00 ./ _,_.. ~
400 ~ soo /
~ __.-::;-
: ..•. :,., ~
roo ..,........ (~MWH
~,.,...... ,...,..-...
~ I .• < "" --• Lll-, ...
eo ... ~ ....
70 -------1.---"" ----•o
KW --r--"
B() -
40
so ---
ro
10
HIGH
HIGH
LOW
LOW
1977 1980 19118 •~o , ... 1!000
FIGURE TI-10
II-32
Section Ill -Demand Projections
APA011/B24
EKWOK
ELECTRIC POWER REQUIREMENTS 1977-2000
1977 1980 1990 2000
POPULATION 109 (high) 112 124 137
(low) 110 111 113
(1) # of residential 25 (high) 27 32 39
consumers (low) 26 28 31
(2) average kWh/mo/ 121 (high) 179 468 1000
consumers (low) 135 205 234
(3) MWh/year 36.5 (high) 58 180 468
residential cons. (low) 42 69 87
(1)x(2)x12
(4) # of small commercial 2 (high) 2 3 4
consumers (low) 2 2 2
(5) average kWh/mo/ 803 (high) 1208 3111 6646
consumer (low) 833 1375 1667
(6) MWh/year 19.3 (high) 29 112 319
sm. com. cons. (low) 20 33 40
(4)x(5)x12
(7) # of large 3 (high) 3 3 4
cons. + public buildings (low) 3 3 3
(8) average kWh/rna/cons 3099 (high) 3222 4583 15000
(low) 3222 3222 4722
(9) MWh/year 111.6 (high) 116 165 720
LP's (low) 116 116 170
(7)x(8)x12
(10) System MWh/year 167.4 (high) 203 457 1507
(3)+(6)+(9) (low) 178 218 297
(11) System .4 (high) .4 .4 .5
Load Factor (low) .4 .4 .5
(12) System Demand 50 (high) 58 130 345
kW (low) 51 62 68
(10)+8760+(11)
Note: MWh listed are sold -not generated.
11-33
Dillingham-Section II
APAOll/E
S. Igiugig
1000
~
•oo
700
eoo
aoo
400
100
10
0
The population has been stable for the last 17 years and the
growth is expected at 1% per year (high) or . 2% per year
(low). Community improvements such as water and sewer systems,
community building, etc. are the additions expected.
IGIUGIG
POWER REQUIREMENTS 1977-2000
..,.. Hle.ti
~
~
~ ~ ____....-
~vr•111 -to-
""" --.,. ~---
H18H
~
-H -·-\ ._...-_.,. ......
.~ LOW
-,.,.,..,.,. --· ~----..:w PEAI(/Y£Ait------
(DKw
, ... , ... 1000
FIGURE
II-34
Section Ill -Demand Projections
APA011/820
IGIUGIG
ELECTRIC POWER REQUIREMENTS 1977-2000
1977 1980 1990 2000
POPULATION 40 (high) 41 45 50
(low) 40 41 42
( 1 ) # of residential 12 (high) 13 16 19
consumers (low) 12 14 15
(2) average kWh/mo/ 121 (high) 179 468 1000
consumers (low) 135 205 234
(3) MWh/year 17.5 (high) 28 90 228
residential cons. (low) 19 34 42
(1)x(2)x12
(4) # of small commercial 1 (high) 1 1 1
consumers (low) 1 1 1
(5) average kWh/mo/ 803 (high) 1208 3111 6646
consumer (low) 833 1375 1667
(6) MWh/year 9.6 (high) 14 37 80
sm. com. cons. (low) 10 16 20
(4)x(5)x12
(7) # of large 1 (high) 3 3 3
cons. + public buildings (low) 3 3 3
(8) average kWh/rna/cons 4334 (high) 3222 4583 6~111
(low) 3222 3222 4722
(9) MWh/year 52 (high) 116 165 220
LP's (low) 116 116 170
(7)x(8)x12
(10) System MWh/year 79.1 (high) 158 292 528
(3)+(6)+(9) (low) 145 166 232
( 11 ) System .4 (high) .4 .4 .5
Load Factor (low) .4 .4 .5
( 12) System Demand 25 (high) 45 85 120
kW (low) 41 48 53
(10)78760-:-(11)
Note: MWh listed are sold -not generated.
II-35
Dillingham -Section II
APAOll/E
6. Koliganek
This community has grown from 90 people in 1950 to approxi-
mately 140 in 1977. Fifteen new housing units are planned by
HUD.109 A local freshwater fishing industry is considered
possible and desirable.100 Presently, however, income is
mostly derived from salmon fishing during the summer and fur
trapping in winter. Accelerated or low growth will depend on
whether the freshwater fishing industry can be established and
whether the fur prices will stabilize.
KOLIGANEK
POWER REQUIREMENTS 1977-2000
10 ,000 = '
700C
6000
IIOOC
4000
»000
rooo
K)()() /
~ ./
800
roo ~
~ ~
[/""' &00
_/
400 ~ ~ JIIVI
~ ------=::: --:;:.,~ ,...,..
roo -(~MWH MWH/YEAR --~ ... ,..,.,
//
tOO ./
IHl --eo ---lO
__ ... --eo ~ ----
8C / KW KW PEAK/YEA~-~-----
40
~
to
10
HIGH
LOW
HIGH
LOW
li80 11185 li110 189!1 2000
FIGURE II-12
II-36
Section Ill -Demand Projections
APA011/B25
KOLIGANEK
ELECTRIC POWER REQUIREMENTS 1977-2000
1977 1980 1990 2000
POPULATION 142 (high) 146 161 178
(low) 143 146 149
(1) # of residential 20 (high) 21 25 30
consumers (low) 21 23 25
(2) average kWh/mo/ 121 (high) 179 468 1000
consumers (low) 135 205 234
(3) MWh/year 29.2 (high) 45 140 360
residential cons. (low) 34 57 70
(1)x(2)x12
(4) # of small commercial 2 (high) 2 3 4
4 consumers (low) 2 2 2
(5) average kWh/mo/ 803 (high) 1208 3111 6646
consumer (low) 833 1375 1667
(6) MWh/year 19.3 (high) 29 112 319
sm. com. cons. (low) 20 33 40
(4)x(5)x12
(7) # of large 3 (high) 3 4 5
cons. + public buildings (low) 3 3 4
(8) average kWh/mo/cons 3099 (high) 3222 5646 13767
(low) 3222 3222 5750
(9) MWh/year 111.6 (high) 116 271 826
LP 1s (low) 116 116 276
(7)x(8)x12
(10) System MWh/year 160.1 (high) 190 523 1505
(3)+(6)+(9) (low) 170 206 386
( 11) System .4 (high) .4 .4 .5
Load Factor (low) .4 .4 .5
(12) System Demand 50 (high) 54 150 345
kW (low) 50 58 88
(10)+8760+(11)
Note: MWh listed are sold -not generated.
II-37
Dillingham-Section II
APAOll/E
7. Levelock
10 000
9000
eooo
TOOO
eooo
&XX)
4000
~
rooo
1000
s.oo
800
TOO
600
&00
400
300
roo
100
s.n
eo
TO
60
~
40
30
ro
10
The population has increased slightly from 75 in 1950 to
approximately 95 in 1977. Extension of the school and other
community facilities are anticipated within the next 10 years.
The population growth has been assumed at 1% per year for the
"accelerated growth" scenario and at .2% per year for the "low
growth'' alternate.
LEVELOCK
POWE,R REQUIREMENTS 1977-2000
'
-----~ --..,.......
--~ __.,..,.
~ ~
/ ~
/ ~ ------CDh4WH MWH ..,..., ... 1.-
/
/
,..,.,.. -/ -... ~ --'" --J'--, v.W PS!.,.~ -~
I' KW ~---
HIGH
LOW
HIGH
LOW
11177 l!il80 198& 19110 IIIII !I P.OOO
FIGURE n -13
II-38
Section Ill -Demand Projections
APA011/B26
LEVELOCK
ELECTRIC POWER REQUIREMENTS 1977-2000
1977 1980 1990 2000
POPULATION 95 (high) 98 108 119
(low) 96 101 106
( 1 ) # of residential 28 (high) 30 36 44
consumers (low) 29 32 35
(2) average kWh/rna/ 121 (high) 179 468 1000
consumers (low) 135 205 234
(3) MWh/year 40.8 (high) 64 202 528
residential cons. (low) 47 79 98
(1)x(2)x12
(4) # of small commercial 2 (high) 2 3 4
consumers (low) 2 2 2
(5) average kWh/mo/ 803 (high) 1208 3111 6646
consumer (low) 833 1375 1667
(6) MWh/year 19.3 (high) 29 112 319
sm. com. cons. (low) 20 33 40
(4)x(5)x12
(7) # of large 3 (high) 3 4 4
cons. + public buildings (low) 3 4 4
(8) average kWh/rna/cons 3099 (high) 3222 6563 8750
(low) 3222 3222 6667
(9) MWh/year 111.6 (high) 116 315 420
LP's (low) 116 116 320
(7)x(8)x12
(10) System MWh/year 171.7 (high) 209 629 1267
(3)+(6)+(9) (low) 183 228 458
(11) System .4 (high) .4 .4 .5
Load Factor (low) .4 .4 .5
(12) System Demand 50 (high) 60 180 290
kW (low) 52 65 105
(10)+8760+(11)
Note: MWh listed are sold -not generated.
II-39
Dillingham-Section II
APAOll/E
8. Manokotak
The population has grown from just over 100 in 1950 to approx-
imately 300 in 1977. The number of families is appro xi mate ly
40. The economy is mostly based on fishing and trapping.
Potential for reindeer herding has been pointed out. 100
The population growth has been assumed to continue above
average with 5% per year for the 11 accelerated deve l opment 11
scenario and with . 5% per year for the 11 1 ow growth 11 scenario.
Expansions of schools and public buildings are the only increases
that are anticipated in the large consumer section.
MANOKOTAK
~OWER RlQUIREIIENTS 1171-2000
1000.----r-
-----_..,...._ Mlllll
~ v
-000 -7 -./ ~ -7 ~---v ~..,.. .... -~ -JwwM/¥HO --· _,..,...
/.,
v ....... ---''"' .. .. ---:-~a~ ' ...
" --·----
•o .. ..
.. .. , .... ... ·-.... I
f IWRE ][ -14
!I-40
Section Ill -Demand Projections
APA011/B7
MANOKOTAK
ELECTRIC POWER REQUIREMENTS 1977-2000
1977 1980 1990 2000
POPULATION 300 (high) 347 565 723
(low) 304 320 336
(1) # of residential 39 (high) 50 89 120
consumers (low) 43 47 51
(2) average kWh/mo/ 143 (high) 265 468 1000
consumers (low) 202 204 234
(3) MWh/year 67 (high) 159 500 1440
residential cons. (low) 104 115 143
(1)x(2)x12
(4) # of small commercial 2 (high) 5 9 12
consumers (low) 4 4 5
(5) average kWh/mo/ 803 (high) 1050 1880 4021
consumer (low) 771 833 1000
(6) MWh/year 19.3 (high) 63 203 579
sm. com. cons. (low) 37 40 60
(4)x(5)x12
(7) # of large 3 (high) 3 4 4
cons. + public buildings (low) 3 4 4
(8) average kWh/mo/cons 3099 (high) 3222 6563 8750
(low) 3222 3222 6667
(9) MWh/year 111.5 (high) 116 315 420
LP 1 s (low) 116 116 320
(7)x(8)x12
(10) System MWh/year 197.8 (high) 338 1018 2439
(3)+(6)+(9) (low) 257 271 523
( 11) System .4 (high) .4 .4 .5
Load Factor (low) .4 .4 .5
(12) System Demand 58 (high) 97 290 560
kW (low) 73 80 120
(10)+8760+(11)
Note: MWh listed are sold -not generated.
II-41
Dillingham-Section II
APAOll/E
9. New Stuyahok
Historical population growth has been high from 95 in 1950 to
approximately 240 in 1977. With a recent (1976) REA power
requirement study avai 1 ab 1 e for this community, consumer
growth has been based on that study, with approximately 1. 5~6
increase per year.
fhe individual energy use will depend greatly on the overall
economic deve 1 opment and the cost at which power wi 11 be
available. The two development scenarios assume continuation
of diesel generation for the low growth alternate and a trans-
mission tie to a less expensive source for the 11 accelerated
gt'owth 11 scenal'i o. Community improvements, schoo 1 expansions
and cold storage facilities have been assumed to contribute to
a moderate system growth.
10 000 •
0000
•
•000
7 OClO
6000
r> ·000
000
eoo
700
CIOO
r.oo
400
00
roo
100
( ~WK
KW
NEW STUYAHOK
POWER REQUIREMENTS 1977-2000
--
-
v
/
./
-;;7'
..... ~
~ v _.,/
·~ . ___.... ~ /-;;;;---v ---1.--"" v"" wwH/YEAR ..,.. -,.....,
.,.,.,.. ... 1---
.....-.....-_,__....
~---~-----KW PEAK/YEAR --
IIIG H
1.0'-A'
HIGH
LOW
llHf 1980 198$ llillfO l91t& t'OOO
FIGURE II-15
II-42
Section Ill -Demand Projections
APA011/B27
NEW STUYAHOK
ELECTRIC POWER REQUIREMENTS 1977-2000
1977 1980 1990 2000
POPULATION 230 (high) 242 286 339
(low) 238 266 297
( 1) # of residential 42 (high) 44 52 60
consumers (low) 44 52 60
(2) average kWh/mo/ 174 (high) 237 482 1000
consumers (low) 182 210 236
(3) MWh/year 87.5 (high) 125 301 720
residential cons. (low) 96 131 170
(1)x(2)x12
(4) # of small commercial 2 (high) 2 3 3
consumers (low) 2 3 3
(5) average kWh/mo/ 256 (high) 1083 2250 4639
consumer (low) 833 917 1167
(6) MWh/year 6.1 (high) 26 81 167
sm. com. cons. (low) 20 33 42
(4)x(5)x12
(7) # of large 2 (high) 3 4 5
cons. + public buildings (low) 3 3 4
(8) average kWh/mo/cons 4564 (high) 3222 5646 13767
(low) 3222 3222 5750
(9) MWh/year 109.5 (high) 116 271 826
LP's (low) 116 116 276
(7)x(8)x12
( 1 0) System MWh/year 203.1 (high) 267 653 1713
(3)+(6)+(9) (low) 232 280 488
( 11) System .23 (high) .3 .4 .5
Load Factor (low) .23 .3 .5
(12) System Demand 100 (high) 100 186 390
kW (low) 115 100 110
(10)+8760+(11)
Note: MWh listed are sold -not generated.
II-43
1000
soo
800
700
600
GOO
400
:!00
1"00
D i 11 i nqham -Section I I
APAOll/E
10. Por·tage Creek
r-----
--
Historical population information is not available. Moderate
to low growth (+ 1%/year to + . 2%/year) have been assumed for
the purpose of this study. The geographic proximity to
Dillingham (approximately 30 miles) has influenced the popu-
lation and economy in the village in the past and it is ex-
pected that this trend will continue. Major new developments
are not anticipated.
PORTAGE CREEK
POWER REQUIREMENTS 1977-2000
~ HIGH
~ I--
~
,.,.., ----.LOW
,.......
~ r--? ~
0 r---10
v
eo
ro
60
(;)~WH -~ ---HIGH -0 ----..-"' _,_
4
./'
,,.
--t-·
Ef/.V..J_YEAR_ ~------__..---/ ~~ r-/-0 ----~--.
0
LOW
( D KW
0
10 -
11177 19110 191!1!1 11190 ~IU '-000
FIGURE li -16
Il-44
Section Ill -Demand Projections
APA011/B8
PORTAGE CREEK
ELECTRIC POWER REQUIREMENTS 1977-2000
1977 1980 1990 2000
POPULATION 25 (high) 26 29 32
(low) 25 27 29
( 1) # of residential 11 (high) 11 13 14
consumers (low) 11 12 12
(2) average kWh/rna/ 121 (high) 179 468 1000
consumers (low) 135 205 234
(3) MWh/year 16.1 (high) 24 73 168
residential cons. (low) 18 29 34
(1)x(2)x12
(4) # of small commercial 1 (high) 1 1 1
consumers (low) 1 1 1
(5) average kWh/rna/ 803 (high) 1208 3111 6646
consumer (low) 833 1375 1667
(6) MWh/year 9.6 (high) 14 37 80
sm . com . cons . (low) 10 16 20
(4)x(5)x12
(7) # of large 3 (high) 3 3 3
cons. + public buildings (low) 3 3 3
(8) average kWh/rna/cons 1600 (high) 2500 4583 9167
(low) 1944 3083 7083
(9) MWh/year 57.6 (high) 90 165 220
LP's (low) 70 111 170
(7)x(8)x12
(10) System MWh/year 97 (high) 132 302 515
(3)+(6)+(9) (low) 121 172 246
( 11) System .5 (high) .4 .4 .6
Load Factor (low) .4 .4 .6
(12) System Demand 210 (high) 298 701 937
kW (low) 272 394 438
(10)+8760+(11)
Note: MWh listed are sold -not generated.
II-45
Dillingham-Section II
APAOll/E
Existing Systems and Seasonal Use
Historical data have only been available for the REA coop supplied
communities of Egegik and New Stuyahok. Manokotak's city operated
power plant did supply energy for only part of the year and the
data are incomplete. The other villages rely on school, cannery,
or private generators for their electric energy supply. Base use
has been established by correlation to historical use in other
villages of similar size. The following table provides information
on the existing installed capacity and the owner/operator in the
various communities.
TABLE II-3
Installed
Location Capacity Owner/Operator
Clark's Point 100 kW School District
Egegik 135 kW Naknek Electric
Ekuk Unknown Private
Ekwok 75 kW School District
Igiugik 40 kW School District
Koliganek Unknown Private
Levelock 50 kW School District
Manokotak 75 kW Village Owned
+ 60 kW School District
New Stuyahok 120 kW AVEC
+ 75 kW School District
Portage Creek 100 kW School District
Generating efficiencies in Egegik and New Stuyahok were 4.5 kWh/gal.
and 5.8 kWh/gal. respectively.
The seasonal energy use pattern will reflect greatly whether fish
processing facilities are operating in a community or not. The
following figure 11 Rural Bristol Bay-Seasonal Energy Use" has been
compiled by utilizing the 1977 data for Togiak, New Stuyahok, and
Egegik for the curve representing 11 Energy Use Without Fish Processing
Facilities 11 • One cannery or freezing plant operating with a usage
of 100-150 MWh/month during June and July but without any winter
use has been added to arrive at the curve representing 11 Energy Use
With Fish Processing Facilities 11
•
II-46
10%
_j~/~
7 "· .J c ....
0 ....
II 'Yo
.J H c H :> I z
4::-z
-..J c
' % ...
0
~
4 "'"·----
I %
2 'Yo
I o/o
-·-r ... -+···
-----1-· I
I
JAN FE!!
' \
'
""'" liP !I
RURAL BRISTOL BAY
SEASONAL ELECTRIC ENERGY USE
(TYPICAL)
\
MAY JUNE JULY
FIGURE Ir -17
""'
"'
1
~~-
1
[N£t8Y IJSf WITtiOUT
I"ISH I>I'IOCI'!!!IING FACILITIES
----ENE
PltO
AUQ !II!PT
WIT1 FISH
FACI ITII!!
--J
OCT NOV Of~
Dillingham-Section II
APAOll/E
G. TOGIAK BAY
Togiak and Twin Hills are located approximately 93 miles west of
Dillingham and separated from the Nushagak Bay Area by a low mountain
range. If the possibility of a transmission tie to the Kuskokwim
region is evaluated these two communities will most likely be on
the transmission route. Therefore, power requirements have been
established as follows:1 32
1977 1980 1990 2000
Togiak
Energy (MWh/year) 512 High 1080 3857 7402
Low 835 1227 2076
Demand (kW) 150 High 500 llOO 1700
Low 240 560 790
Twin Hills
Energy (MWh/year) 145 High 166 331 ll72
Low 152 176 246
Demand (kW) 45 High 47 95 270
Low 45 50 56
Total
----rilergy (MWh/year) 657 High 1246 4188 8574
Low 987 1403 2322
Demand *(kW) 195 High 547 1195 1970
Low 285 610 846
* Noncoincident
Togiak is the only village in this subregion that has a central
power system. Togiak is part of the Alaska Village Electric
Cooperative (AVEC) which is a Rural Electrification Association
(REA) funded utility.
AVEC which has a total generation capacity in Togiak of 481 kW,
generated at an average rate of 7.37 kWh/gallon.
The school in Togiak has an installed standby generation capacity
of 75 kW.
Besides the privately owned and operated small generators in Twin
Hills, the School has generation capacity of 150 kW.
II-48
Dillingham-Section II
APAOll/E
H. BIBLIOGRAPHY AND REFERENCES
100 Bristol Bay -The Fishery and the People, 1975. Bristol Bay
Area Development Corporation.
101 Bristol Bay -Its Potential and Development, 1976. Bristol
Bay Regi ona 1 Deve 1 opment Co unci 1 and Bri sto 1 Bay Native
Association.
102 Bristol Bay -An Overall Economic Development Plan, Nov.
1976. by Andrew Golia, Economic Plans Bristol Bay Area
Planning Grant.
103 Bristol Bay-A Socioeconomic Study, 1974. Institute of
Social, Economic and Government Research -University of
Alaska.
104 Electric Power in Alaska 1976 -1995, August 1976. Institute
of Social, Economic and Government Research-University of
Alaska.
105 A Regional Electric Power System for the Lower Kuskokwim
Vicinity, July 1975. United States Department of the Interior -
Alaska Power Administration prepared by R. W. Retherford
Associates.
106 Waste Heat Capture Study -June 1978. State of Alaska -
Department of Commerce and Economic Development, Division of
Energy and Power Development, prepared by R. W. Retherford
Associates.
107 Alaskan Electric Power -An Analysis of Future Requirements
and Supply Alternatives for the Railbelt Region, Volumes I
and II, March 1978. State of Alaska, Department of Commerce
and Economic Development, prepared by Battelle.
108 State of Alaska, Department of Fish and Game. Letter of
March 19, 1979.
109 1978 -Community Energy Survey by State of Alaska, Department
of Commerce and Economic Development, Division of Energy and
Power Development.
110 Alaska Industry and Oil, April 1979.
111 State of Alaska -Public Utilities Commission. 11 Alaska
Village Electric Cooperative Cost of Service Study 11 , November,
1977.
II-49
Dillingham-Section II
APAOll/E
112 United States-Depar-tment of the Interior'. Alaska Power
Administration. 11 Alaska Electric Power Statistics 1960 -
1976 11
, July 1977.
113 "The 1976 Alaska Power Survey''. Volumes 1 and 2 by The
Federal Power Commission.
114 11 Alaska Regional Energy Resources Planning Project -Phase
I", Volume 1, October 1977. By Alaska Division of Energy
and Power Development.
115 The A 1 aska Economy. Year-End Performance Report 1977. By
State of A 1 as ka, Department of Commerce and Economic
Development.
116 Overall Economic Development Program. Bristol Bay Borough,
Alaska by Arne G. Erickson, Administrative Assistant, Bristol
Bay Borough, August 1976.
117 System Planning Study, Iliamna -Newhalen Electric Cooperative,
by R. W. Retherford Associates, September 1978.
118 System Planning Study, Matanuska Electric Association, by R.
W. Retherford Associates, December 1978.
119 "Inventory of Rural Sanitation Services 11
, March 1977. State
of Alaska, Department of Environmental Conservation.
120 "Community Profi 1 es 11
, 1978. State of A 1 aska, Department of
Community and Regional Affairs.
121 ''Alaska Regional Profiles, Southcentral Region and Southwest
Region 11
, June 1974, published by the State of Alaska in
cooperation with the Joint Federal State Land Use Planning
Commission for Alaska.
122 11 School Generation Survey'', December 1978. Performed by
Industrial Services for the Southwest Regional School District.
123 Letter regarding energy use by military installations in the
Bristol Bay area, March 1979. By Mr. Bodnar, Department of
the Air Force.
124 Letter regarding fue 1 use and generation i nsta 11 at ions,
April 26, 1979. By Don Anderson, The Lake and Peninsula
School District.
125 Letter regarding fuel use and generation installations,
April 23, 1979. By Gust S. Bartman, City of Manokotak,
Manokotak, Alaska.
II-50
Dillingham-Section II
APAOll/E
126 Letter regarding fuel deliveries made to villages in the
Bristol Bay area. March 8, 1979. Moody Sea Lighterage,
Aleknagik, Alaska.
127 Letter regarding cannery installations, March 19, 1979. By
Don Wanie, State of Alaska, Department of Fish and Game.
128 Year end REA Form 12F and monthly REA Form 7 for 1977,
Nushagak Electric Cooperative, Dillingham, Alaska.
129 Year end REA for 12F and monthly REA Form 7 for 1977, Naknek
Electric Association, Naknek, Alaska.
130 Written communication regarding electrical use in New Stuyahok
and Togiak, March 1979, from Alaska Village Electric Cooperative.
131 11 1978-1980 Construction Work Plan 11 for Kodiak Electric
Association by R. W. Retherford Associates.
132 11 Bristol Bay Energy and Electric Power Potential 11 , Draft -
October 1979 for the U.S. Department of Energy, Alaska Power
Administration by R.W. Retherford Associates.
II-51
III. HYDROELECTRIC SITE EVALUATION
Dillingham-Section III
APA016/A
III. HYDROELECTRIC SITE EVALUATION
The evaluation of three sites with hydroelectric potential has been
prompted by the preliminary findings in the uBristol Bay Energy and
Electric Power Potential 11 study. They are:
Lake Elva
Grant Lake, and
Lake Tazimina
These sites had been judged technically and economically feasible
with the least adverse environmental impact and institutional
constraints.
Detailed site descriptions and development plans are outlined in
the following parts of this section.
Figure III-1 shows the location of the hydroelectric power potentials
in relation to the Bristol Bay Communities.
A. LAKE ELVA PROJECT -GENERAL DESCRIPTION
1. Introduction
Lake Elva is located in a glacial valley about 45 miles NNE of
Dillingham, Alaska above and between Little Togiak Lake and
Amakuk Arm of Lake Nerka. The water surface elevation is 302
feet mean sea level. The area is shown on U.S.G.S. Topographic
Sheet Goodnews Bay (C-1) Alaska at a scale of 1:63,360. (See
Figure III-2).
Elva Creek, which drains Lake Elva, flows 3 miles into Lake
Nerka and has eroded a re 1 at i ve ly narrow winding channe 1
through the glacial drift at the outlet of Lake Elva. This
changes gradually to a narrow rock defile at the damsite about
6,000 feet downstream from the lake. The stream gradient is
relatively flat between the lake and the damsite. Downstream
from the damsite, the stream flows through a winding rock
gorge for approximately a mile where it emerges into the
gravel outflow fan-like deposit formed from the glacial debris
from the Lake Elva valley.
The drainage area above the damsite is 10.5 square miles as
determined from the U.S.G.S. Goodnews Bay (C-1) map. There
are no stream flow records for the basin. The U.S. Geological
Survey, Water Resources Branch, installed a gage at the mouth
III-1
AL,\Sii.A J•OlVI~U AlT'l'IIOU.I'I'l'
LAKE ELVA HYDROELECTRIC PROJECT
FEASIBILITY STUDY
FINDINGS AND RECOMMENDATION
April 30, 1981
A preliminary assessment of the Lake Elva Hydroelectric Project was
initially made and presented in the "Bristol Bay Energy and Electric Power
Potential" study conducted by Robert W. Retherford Associates for the Alaska
Power Administration in 1979. This study prompted a ''Reconnaissance Study of
the Lake Elva and Other Hydroelectric Power Potentials in the Dillingham Area"
which was conducted for the Alaska Power Authority by Robert W. Retherford
Associates, also in 1979. For the community of Dillingham, the reconnaissance
study indicated that the Lake Elva Project was the most cost effective option,
although the cost of Lake Elva power was projected to be slightly higher than
v1ould result from development of a significantly larger regional project on
the Tazimina River.
The ensuing feasibility study was prompted by the reconnaissance study
recommendation and from strong local support for the Lake Elva Project. Fund-
ing for this feasibility study was made available to the Power Authority in
July of 1980 and R. W. Beck and Associates was the engineering firm selected
to conduct the investigations.
If developed, the Lake Elva Project would feed into the Nushagak Electric
Cooperative distribution system which currently supplies diesel power to the
communities of Aleknagik and Dillingham. The 1980 load for the Cooperative was
approximately 7,632,000 KWH with a peak demand of 1,452 KW.
PROJECT DESCRIPTION:
The Project site is located in Southwest Alaska within the Wood-Tikchik
State Park approxinJcJtely 45 air 111iles NNW of Dillingham, and is situated
between Little Togiak Lake on the south and Amakuk Arm of Lake Nerka on the
north. Hydrologic investigations conducted for the project indicate that the
basin yields an average of 39,800 acre-feet (55 cfs) of runoff in an average
year.
The Project would include a 120-foot high rockfill dam located about 8,500
feet downstream from the outlet of the existing Lake Elva; a reservoir which
would provide 26,300 acre-feet of active storage; a 6,700-foot long power conduit
comprised primarily of buried concrete cylinder pipe; a steel-framed powerhouse
containing two horizontal shaft Crossflow-type turbines each capable of delivering
750 KW under a rated net head of 280 feet; a 10-mile temporary construction road
leading from the north end of Lake Aleknagik to the dam and powerhouse sites;
about 1.5 miles of permanent site access roads; and approximately 33 miles of
new 34.5-KV transmission line extending from the Project to the Village of
Aleknagik, plus upgrading of approximately 22 miles of existing single-phase
transmission line which extends from Aleknagik to Dillingham.
..
The 1,500 KW Project, as planned, would provide dependable capacity of 1,200
KW. It would be capable of delivering 7,961,000 kwh of energy in an average
year, and 7,769,000 kwh of firm annual energy, to the load center in Dillingham.
FINDINGS:
The Lake Elva Hydroelectric Project has been found to be feasible from a
technical and environmental standpoint and could provide a reliable source of
electricity for Nushagak Electric Cooperative, Inc. by early 1985. Field in-
vestigations and studies revealed nothing unusual about the project site with
respect to hydrological, geotechnical and other technical aspects. The project
design concept is straightforward and typical of designs for similar size pro-
jects of this type.
Environmental concerns identified in the study include the impacts of flow
interruptions, flow regime changes, and the loss of flow over a portion of Elva
Creek. These impacts could alter groundwater flows to the Lake Nerka beaches
where salmon spawn and could change water quality, most notably temperature and
possibly cadmium concentrations. Other concerns include the impacts of access
road and transmission line corridors upon anadromous waterways, accessability
to prime moose habitat, and visual resources.
The total estimated construction cost of the project is high, primarily due
to its remote location. The estimated total construction cost based on January
1981 price levels is $29,449,000. According to Power Authority criteria for
conducting econon1ic analyses using discounted life cycle costs, the Project is
equal in cost to the alternative of continued expansion of NEC's diesel electric
generation system. In other words, the benefit-to-cost ratio is 1 to 1.
The Project cannot be financed without state assistance. The Governor's
financing program contained in HB 310 permits the project to be financed while
minimizing state financial assistance. Of the three state assisted financing
plans evaluated, a three percent loan for a 35-year term would provide the
lowest cost energy to consumers, but the greatest cost to the State.
RECOMMENDATIONS:
If the Lake Elva Hydroelectric Project is to be pursued, the next step
would be preparation and submittal of a license application, followed by
continued environmental studies and project design. Construction could begin
immediately after receipt of the license which can be anticipated not earlier
than July 1982.
The Lake Elva Project would provide 74 percent of the projected Dillingham
electrical energy demand in 1985 and a decreasing proportion thereafter. The
project was found to be marginally feasible with the same life cycle cost as
continued use of diesel, utilizing established Power Authority economic criteria.
These criteria include an assumption of 3.5 percent diesel fuel escalation over
and above the rate of inflation for twenty years. The Lake Elva Project does
have the benefit, however, of producing inflation free renewable energy so
that in the event fossil fuels escalate at higher rates than those assumed in
the economic analysis, the cost of Lake Elva power would be less than continued
diesel generation. The project also has the benefit of providing power on line
three or more years earlier than the larger regional Tazimina River Hydroelectric
Project.
The Tazimina Project has the potential of fully satisfying the electrical
energy requirements of fifteen communities within the Bristol Bay Region, in-
cluding Dillingham for at least 20 years. Furthermore, the Tazimina Project
could possibly produce electrical energy at a lower unit cost than Lake Elva,
primarily due to better site conditions and economies of scale. However, the
Tazimina Project would not come on line until early 1988, provided no serious
environmental problems are encountered. The Tazimina Project has not had the
benefit of a detailed feasibility study as has the Lake Elva Project, so there
is some degree of uncertainty as to its technical, economic and environmental
feasibility. There appears to be a high degree of local support for both pro-
jects.
Beginning in June 1981, the Power Authority will conduct a feasibility
study of the Tazimina Hydroelectric Project, and an interim assessment of the
project 1 s feasibility will be available in February, 1982. In the event the
Tazimina Project does not prove feasible, one year would be lost in advancing
the Lake Elva Project if licensing is not pursued immediately.
It is therefore the recommendation of the Power Authority that a license
application for the Lake Elva Project be prepared and submitted to the Federal
Energy Regulatory Commission. When the interim assessment of Tazimina 1 S fea-
sibility becomes available in February of 1982, a decision should be made at
that time to proceed with final design and construction of the Lake Elva Project
or instead to turn to Tazimina hydroelectric development or another more cost
effective project.
L-Y~~
Eric P. Yould
Executive Director
LAKE ELVA
PLAN OF FINANCE
Prepared by the
Alaska Power Authority
April, 1981
A plan of finance is prepared for any new power project identified in a
feasibility study as the most feasible alternative for development. The
purpose of a plan of finance is to present various alternatives available
to finance the power project and to identify the most appropriate means to
achieve the lowest cost electric power for consumers while minimizing the
amount of state assistance required.
The Lake Elva project is marginally feasible based upon a life cycle cost
present worth analysis as compared to the base case plan of all diesel
generation. The alternative means available to finance the projects are
low interest loans from the Rural Electrification Administration (REA),
Power Authority tax exempt revenue bonds, and state financing assistance in
some form. REA loan funds may not be available due to federal budget
reductions which may seriously impact the REA program. The Power Authority,
under the current financing program, could not finance the project since
the credit of the local community is not sufficient to provide security
to bond purchasers of its capacity to repay the large debt. Therefore, state
assistance in some form will be necessary to finance the project.
Table I presents the annual costs of the Lake El~a project under 35 year
levelized debt service for interest rates of 8. and 10.0%. Cost of
energy for the Lake Elva plan is reflected in Table II. The analysis is
based upon hypothetical financing conditions including 7% general inflation,
8.5% interest rate, and 3. escalation of fuel prices above the general
inflation rate for 20 years. Cost of energy for the base case plan of con-
tinued all diesel generation is ected in Table III which is based on
the same factors.
The 8.5% interest rate used herein is the standard rate currently used by
the Power Authority to make its cost of power analysis of projects. Since
the project can not be financed without state assistance, the cost of
energy was also analyzed based upon a financing interest rate of the previous
years average from municipal bond yield rates reported in the 30 year
revenue index of the Weekly Bond Buyer, which is currently approximately
10%. Table IV presents the cost of energy in ¢/KWH.
Lake Elva Lake Elva
and Diesel and Diesel All Diesel
Year l r 8. 35 r 8.5%/20 year
1985 54.3 45.3 20.4
1990 52.5 45.3 30.7
1995 61.1 55.0 51.7
2000 73.7 72.3 80. l
State assistance employed to finance the project could be accomplished in
various ways, including direct grants, or equity investments, low interest
loans, and graduated interest loans, or with a combination of financing
measures as presented in HB 310. Three alternatives for st~te assistance
will be analyzed.
l. A state grant of 60% of the Total Construction Cost and Power Authority
revenue bond financing of 40% of the Cost at a rate estimated to be
ll% in the current market.
2. A state loan for a 35 year term at a subsidized interest rate of 3% on
the unpaid balance.
3. A state grant of $4,707,500 based upon $2,500 per capita for the 1656
residents of Dillingham and 227 residents of Aleknagik, revenue financing
at 10.5 of the remaining construction costs (improved interest rate
based upon the completion fund feature of HB 310 and the debt adjust-
ment funding of the project, which is also a characterization of HB
310), and an appropriation of $12,000,000 for a debt assistance loan
fund for the project.
FINANCING ALTERNATIVE l.
Total Construction Cost (l/81 Bid)
Grant (60% of TCC)
To be Financed
Escalation (7% per year)
Total Remaining Construction Cost
Interest During Construction (ll%)
Total Investment Cost
Financing Expenses
Reserve Fund
Total Capital Requirements
Annual Debt Service
Annual O&M, Administration, Insurance
and Interim Replacements
TOTAL ANNUAL COST
$29,499,000
17,699,400
$11,799,600
l ,498,400
$13 '298' 000
l , 732 '000
$15,030,000
494,000
l ,976,000
$17,500,000
$ l ,976,000
331 ,000
$ 2,307,000
Table V presents the cost of energy for financing alternative l. The
present worth cost of the state assistance is the value of the grant which
is $17,699,400.
FINANCING ALTERNATIVE 2.
Total Construction Cost (l/81 Bid)
State Loan (3% for 35 years)
To Be Financed
$29,499,000
29,499,000
Interest During Construction and Construction Inflation
could be paid from investment earnings on the loan
amount.
Annual Debt Service
Annual O&M, Administration, Insurance and
Interim Replacements
TOTAL ANNUAL COST
$ l '37 3 '000
331 ,000
-rT;7 04 '006
Table VI presents the cost of energy for financing alternative 2. The
present ~orth of the state assistance is the present value of the dif-
ference between the annual debt service presented in Table IV and the
annual debt service for financing alternative 2 for the 35 years of debt
service repayment. The effective debt service in Table IV is the annual
debt service of $4,360,000 less the interest earnings on the reserve fund,
or $3,924,000. Therefore, the annual difference is $3,924,000-$1,373,000 =
$2,551,000. The present worth value at 10% of $2,551,000 of annual assistance
over 35 years discounted at l is $24,602,000.
INANCING ALTERNATIVE 3.
Total Construction Cost (1/81 Bid)
Grant
To Be Financed
Escalation (7% per year)
Total Remaining Construction Cost
Interest During Construction (10.5%)
Total Investment Cost
Financing Expenses
Reserve Fund
TOTAL CAPITAL REQUIREMENTS
Annual Debt Service
Annual O&M, Administration, Insurance, and
Interim Replacements
TOTAL AtlNUAL COST
$29,499,000
4,707,500
$24' 701 , 500
3,173,500
$27,965,000
3,535,000
$31,500,000
l ,036,000
3,964,000
$36,500,000
3,964,000
331,000
$ 4,295,000
Table VII presents the cost of energy for financing alternative 3. The
present worth cost of state assistance for this alternative is the value of
the per capita grant, or $4,707,500. Table VIII illustrates the rate
impacts and funding provided by the debt assistance feature of the financing
program in HB 310. Each year a loan is made to the utility to lower the
cost of energy sold to utility consumers to the rate which would have been
charged for continuation of the present diesel generation. The loan interest
rate is the same as the revenue bond yield rate (assumed to be 10.5% in
this alternative), and principal and interest payments are deferred as
necessary to permit the utility and consumers to repay the debt assistance
loans whe~ the benefits of the project are realized. Since the return to
the state is ultimately realized at market rates, the present value of the
assistance provided by this financing feature over the full term of this
loan is zero. The debt assistance fund must be capitalized at $12,000,000
for the project. This should be sufficient, together with assumed i~vest
ment earnings of l , to fund the annual debt assistance loans.
SUMMARY AND CONCLUSIONS
Summarized below is the estimated system cost of energy (¢/kwh) for various
years for the three state assisted financing options analyzed and the
estimated present value of the state assistance. This can be compared to
the previously summarized cost of energy examples wherein no state assistance
is provided.
.....
-i
Alternative Alternative ')
L Alternative 3
Year Grant Loan 3
1985 29.1 25.0 20.4
1990 32.5 29.2 30.7
1995 44.2 41 . 4 51.7
2000 62.7 60.2 80. 1
2004 87.1 34.8 116.0
Present Value
of state Assistance $17,699,400 $24,602,000 $4,707,500
In the early years of project operation, Alternative 3 provides lowest
system cost of energy and minimized the amount of state assistance. Alter-
natives 1 and 2 provide a higher cost of energy in the first 5 years of
project operation due to the particular terms of the respective financing
plans. In Alternative 1, the percentage of the total construction cost of
Lake Elva to be financed by a grant could be increased. In Alternative 2,
the state loan to finance construction could be made at lower interest
rates. Either of these scenarios, which would lower the cost of energy in
the early years, would also consequently increase the present value of the
state assistance.
A feature of Alternative 3 which is less attractive is that the local
consumers may not realize the benefits of the hydroelectric project until
beyond the 40th year of project operation, when all state debt assistance
loans are repaid. This time period for realizing the benefits would be
advanced in relation to the actual increases in the cost of diesel genera-
tion. Table VIII illustrates the relationship between the cost of energy
and the rate of repayment of the state debt assistance loans. If diesel
fuel costs escalate above 3.5% over the rate of general inflation for a
period in excess of 20 years, the state debt assistance loans would be
repaid more rapidly. Alternative 3 assumes that the cost of energy to be
charged consumers would be equivalent to the cost of energy with an all
diesel system. Table VIII shows that an all diesel system would generate
power cheaper than the system with Lake Elva for the first 13 years of Lake
Elva operation, therefore, annual state debt assistance loans would be
necessary. In succeeding years, the higher cost of energy associated with
an all diesel system would be charged to customers in order to achieve a
revenue return to repay the state debt assistance loans.
The analysis was based upon nominal dollars which illustrate the impacts of
a general inflation rate of 7% per annum and a fuel escalation rate of 3.5%
for only 20 years. If the cost of energy in future years is discounted at
7% the assumed rate of inflation, the real cost of energy in the market
area of the project would actually decrease for Alternatives 1 and 2, and
only increases gradually due to the r·ising costs of diesel fuel and the
repayment of the debt assistance loans in Alternative 3. The discounted
cost of energy would be:
Alternative Alternative 2 Alternative 3
r rant HB l
1985 29. l 25.0 20.4
1990 23.2 20.8 21.9
1995 22.5 21.0 26.3
2000 22.7 21.8 29.0
2004 24. l 23.4 32. l
In conclusion, Alternative 2 provides the lowest cost energy, but with the
greatest state assistance Alternative 3 minimizes state assistance but
results in appreciably higher energy costs. The reason the project does
not provide significant benefits to the market area is that the economic
feasibility of the project based upon specific assumptions is marginal in
that the benefit to cost ratio of the system with Lake Elva compared to an
all diesel system is 1.0. The benefits of lower cost energy in future
years from the project are largely based upon the state assistance or
subsidy provided with each financing alternative. All other benefits
derived from the renewable resource generation are provided by the infla-
tion free nature of the investment of the project.
CAPITAL COSTS:
Interest Rates
TABLE I
LAKE ELVA PROJECT
PROJECT ANNUAL COSTS
COST OF POWER ANALYSIS
Total Construction Cost ...................... .
(January 1981 Bid)
Escalation (7% per year) .................... .
Total Construction Cost ...................... .
(January 1983 Bid)
Net Interest during Construction ............ .
Total Investment Cost ........................ .
Financing Expenses (2.5% of TCR) ........... .
Reserve Fund (One Year's Debt
Service) ................................. .
TOTAL CAPITAL REQUIREMENTS (TCR) ............. .
ANNUAL COSTS: ( 1)
Net Debt Service ............................. .
Operating Costs:
Operation and Maintenance ................... .
Administrative and General
(34% of O&M) ............................. .
Insurance (0.15% of TCR) .................. .
Interim Replacements (0.14% of TCR) ........ .
TOTAL ANNUAL COST ........................... .
(1) -Annual Costs for Operation in 1985.
8.5% 10.0%
$29,449,000 $29,449,000
~01,000 3,701,000
$33,150,000 $33,150,000
2,978,000 3,503,000
$36,128,000 $36,653,000
1, 021 '000 1,050,000
-3,683,000 4,360,000
$40,832,000 $42,063,000
$ 3,683,000 $ 4,360,000
159,000 159,000
54,000 54,000
61,000 62,000
57,000 59,000
$ 4,014,000 $ 4,694,000
TABLE II
LAKE ELVA PROJECT
COST OF PROJECT GENERATI
8. LOAN FOR 35 YEARS
Total
Annual Project Diesel Total
Generation Debt Interest Project Diesel Fuel Annual Cost of
Required Service rnings O&M Cost O&M Cost Cost Cost Power
Year (fv1wh) ($000) ($000) ( $OO_Qj__ .JJ..QQQl_ ($000) ($000) (¢/kwh)
1985 10,692 9,844 3,683 ( 313) 331 2,731 384 371 4,456 45.3
1986 11,219 10,324 3,683 (313) 354 3,258 410 490 4,624 44.8
1987 11,761 10,818 3,683 (313) 379 3,800 440 631 4,820 44.6
1988 12,317 11,323 3,683 (313) 405 4,356 470 799 5,044 44.6
1989 12,888 11 ,840 3,683 ( 313) 434 4,927 503 999 5,306 44.8
1990 13,4 72 12,368 3,683 ( 313) 464 5,511 538 1,235 5,607 45.3
1991 13' 2 12 ,834 3,683 ( 313) 497 6,021 828 1,491 6,186 48.2
1992 14,487 13, 3,683 (313) 532 6,526 886 1,786 6 '574 49.5
1993 ,989 13,750 3,683 ( 313) 569 7,028 948 2,125 7,012 51.0
1994 15,498 14,213 3,683 ( 313) 609 7,537 1,014 2,518 7,511 52.8
1995 16,003 14 ,671 3,683 (313) 651 8,042 1 ,085 2,969 8,075 55.0
1996 16,430 15,057 3,683 ( 313) 697 8,469 1 '161 3,455 8,683 57.7
1997 16,848 15,433 3,683 ( 313) 745 8,887 1,243 4,006 9,364 60.7
1998 17,257 15,801 3,683 ( 313) 798 9,296 1 '3 4,630 10,127 64.1
1999 17,647 16,149 3,683 (313) 853 9,686 1,423 5,331 10 '977 68.0
2000 18,032 16,492 3,683 (313) 913 10,071 1,5 6,125 11,930 72.3
2001 18,400 16,820 3,683 ( 313) 977 10,439 1,629 7,015 12,991 77.2
2002 18,750 17,100 3,683 (313) 1,046 10,789 1,743 8,012 14,171 82.9
2003 19,100 17,350 3,683 ( 313) 1,119 11 '139 1,865 9,140 15,494 89.3
2004 19,500 17,725 3,683 (313) 1,197 11 , 539 1,995 10,463 17,025 96.1
TABLE III
OF DIESEL GENERATI
New New
Total Diesel Diesel Diesel
Annual Interest Capacity Debt Diesel Fuel Annual Cost
les rnings Required Service O&M t Cost Cost Power
r (Mwh) .JiQ_QQL (kw) ($000) ($000) ($00Ql (¢/kwh)
1985 10,692 9,844 0 0 10,692 0 552 1,454 2,006 20.4
1986 11,219 10' 324 0 0 11,219 0 590 1,686 2,276 22.1
1987 11,761 10,818 0 0 11,761 0 632 1,9 2,585 23.9
1 12,317 11, 0 0 12,317 0 2,260 2,936 .9
1989 12,888 11,840 0 0 12' 0 723 2,614 3,337 . 2
1990 13,472 12,368 0 0 13,472 0 774 3,019 3,793 30.7
1991 13,982 12,834 (22) 1,2 13,982 255 1,052 3,462 4,747 37.0
1992 14,487 13, ( ) 14,487 255 1,172 3,964 5,369 40.4
1993 14' 13 '7 ( ) 0 14,989 255 1 '2 4,532 6,021 43.8
1994 15,498 14,213 ( ) 0 15,498 255 1,344 5,178 6,755 . 5
1995 16,003 14,671 (22) 0 16,003 255 1,438 5,908 7,579 51.7
1996 16,430 15,057 (22) 0 16,430 255 1,538 6,702 8,473 56.3
1997 16,848 15,433 (22) 0 16,848 255 1,646 7,594 9,473 61.4
1998 17,2 15,801 (22) 0 17,257 255 1,761 8,596 10,590 67.0
1999 17,647 16,149 (22) 0 17,647 255 1,884 9,713 11,830 73.7
2000 18,032 16,492 (22) 0 18, 2 2,016 10,967 13,216 80.1
1 18,400 16,820 (22) 0 18,400 255 2,157 12,365 14,755 87.7
2002 18,750 17,100 (22) 0 18,750 255 2,309 13,924 16,466 96.3
2003 19,100 17,350 (22) 0 19,100 255 2,470 15,673 18,376 105.9
2004 19,500 17,725 (22) 0 19,500 255 2,643 17,681 20, 116.0
LE IV
LAKE ELVA PROJECT
COST OF PROJECT GENERATI
1 LOAN FOR 35 YEARS
tal New
Annual Project Diesel Diesel Tota 1
Generation Debt Interest Project Debt Diesel Fuel Annual Cost of
Required Service Earnings O&M Cost Service O&M Cost Cost Cost Power
Year ( lvlwh) ($000) ($000) ($000) ($000) ($000) ($000) ($000) (¢/kwh)
1985 10,692 9,844 4,694 (436) 1 2,731 0 384 371 5,344 54.3
1986 11 '219 10,324 4,694 (436) 354 3,258 0 410 490 5,512 53.4
1987 11,761 10,818 4,694 (436) 379 3,800 0 440 631 5,708 52.8
1988 12,317 11 ,323 4,694 (436) 405 4,356 0 470 799 5,932 52.4
1989 12,888 11,840 4,694 (436) 434 4,927 0 503 999 6,194 52.3
1990 13,472 12,368 4,694 (436) 464 5, 511 0 538 1,235 6,495 52.5
1991 13,982 12,834 4,694 (436) 497 6' 1 0 828 1,491 7,074 55.1
1992 14 '487 13,293 4,694 (436) 532 6,526 0 886 1,786 7,462 56.1
1993 14,989 13,750 4,694 (436) 569 7,028 0 948 2,125 7,900 . 5
1994 15,498 14,213 4,694 (436) 609 7,537 0 1,014 2,518 8,399 59.1
1995 16,003 14,671 4,694 (436) 651 8,042 0 1,085 2,969 8,963 61.1
1996 16,430 15,057 4,694 (436) 697 8,469 0 1,161 3,455 ,571 63.6
1997 16,848 15,433 4,694 (436) 745 8,887 0 1,243 4,006 10,2 66.4
1998 17,257 15,801 4,694 (436) 798 9,296 0 1,329 4,630 11,015 . 7
1999 17,647 16,149 4,694 (436) 853 9,686 0 1,423 5,331 11 ,865 73.5
18,032 16,492 4,694 (436) 913 10,071 0 1,522 6,125 12,818 77.7
2001 18,400 16,820 4,694 (436) 977 10,439 0 1,629 7,015 13,879 82.5
2002 18,7 17,100 4,694 (436) 1,046 10,789 0 1,743 8,012 15,059 88.1
2003 19,100 17,350 4,694 (436) 1,119 11,139 0 1,865 9 '140 16,382 94.4
2004 19,500 17,725 4,694 (436) 1,197 11, 0 1,995 10,463 17,913 101.1
TABLE V
LAKE ELVA PROJECT
COST OF PROJECT GENERATI
Financing Alternative 1
Total
Annual Total Project Diesel Diesel Tota 1
Generation Annual Debt Interest Project Generation Fue 1 Annual Cost of
Required Sales Service Earnings O&M Cost Required Cost Cost Power
Year ( M~Jh) ( ~1wh) ($000) ($000) ($000) (Mwh) ($000) ($000) (¢/kwh)
1985 10,692 9,844 1,976 (197) 331 2,731 384 371 2,865 29.1
1986 11,219 10,324 1,976 (197) 354 3,258 410 490 3,033 29.4
1987 11,761 10,818 1,976 (197) 379 3,800 440 631 3,229 29.9
1988 12,317 11 ,323 1,976 (197) 405 4,356 470 799 3,453 30.5
1989 12,888 11 ,840 1,976 ( 1 ) 434 4,927 503 999 3 '715 31.4
1990 13,472 12,368 1,976 (197) 464 5 '511 538 1 ' 5 4,016 32.5
1991 13,982 12,834 1,976 (197) 497 6,021 828 1,491 4,595 35.8
1992 14,487 13,293 1,976 (197) 532 6,526 886 1,786 4,983 37.5
1993 14,989 13 '750 1,976 (197) 569 7,028 948 2' 125 5,421 39.4
1994 15,498 14,213 1,976 ( 197) 609 7,537 1,014 2,518 5,920 41.7
1995 16,003 14,671 1,976 ( 197) 651 8,042 1,085 2,969 6,484 44.2
1996 16,430 15,057 1,976 (197) 697 8,469 1 '161 3,455 7,092 47.1
1997 16,848 15,433 1,976 ( 197) 745 8,887 1,243 4,006 7 '773 50.4
1998 17,257 15,801 1,976 ( 197) 798 9,296 1,329 4,630 8,536 54.0
1999 17,647 16,149 1,976 ( 197) 853 9,686 1,423 5,331 9,386 58.1
2000 18,032 16,492 1,976 (197) 913 10,071 1,522 6,125 10,339 62.7
2001 18,400 16,820 1,976 (197) 977 10,439 1,629 7,015 11,400 67.8
2002 18,750 17,100 1,976 ( 197) 1,046 10,789 1,743 8,012 12,580 73.6
2003 19,100 17,350 1,976 (197) 1 '119 11 '139 1,865 9,140 13,903 80.1
2004 19,500 17,725 1,976 (197) 1,197 11 '539 1,995 10,463 15,434 87.1
TABLE VI
LAKE ELVA
COST OF PROJECT GENERATION
Financing Alternative 2
Tota 1
Annual Total Project Diesel Diesel Total
Generation Annual Debt Interest Project Generation Diesel Fuel Annual Cost of
Required Sales Service Earnings O&i•1 Cost Required O&M Cost Cost Cost Power
Year (Mwh) (Mwh) ($000) ($000) -($000) (Mwh) ($000) ($000) ($000) (¢/kwh)
1985 10,692 9,844 1,373 0 331 2,731 384 371 2,459 25.0
1986 11,219 10,324 1, 373 0 331 3,258 410 490 2,627 25.5
1987 11,761 10,818 1,373 0 331 3,800 440 631 2,823 26.1
1988 12,317 11,323 1,373 0 331 4,356 470 799 3,047 26.9
1989 12,888 11,840 1,373 0 331 4,927 503 999 3,309 27.9
1990 13,472 12,368 1,373 0 331 5, 511 538 1,235 3,610 29.2
1991 13,982 12,834 1, 373 0 331 6,021 828 1,491 4,189 32.6
1992 14,487 13,293 1,373 0 331 6,526 886 1,786 4,577 34.4
1993 14,989 13,750 1,373 0 331 7,028 948 2,125 5,015 36.5
1994 15,498 14,213 1,373 0 331 7,537 1 ,014 2,518 5,514 38.8
1995 16,003 14,671 1,373 0 331 8,042 1,085 2,969 6,078 41.4
1996 16,430 15,057 1, 373 0 331 8,469 1,161 3,455 6,686 44.4
1997 16,848 15,433 1,373 0 331 8,887 1,243 4,006 7,367 47.7
1998 17,257 15,801 1,373 0 331 9,296 1,329 4,630 8,130 51. 5
1999 17,647 16,149 1, 373 0 331 9,686 1,423 5,331 8,980 55.6
2000 18,032 16,492 1,373 0 331 10,071 1,522 6,125 9,933 60.2
2001 18,400 16,820 1,373 0 331 10,439 1,629 7,015 10,994 65.4
2002 18,750 17,100 1,373 0 331 10,789 1,743 8,012 12,174 71.2
2003 19,100 17,350 1,373 0 331 11,139 1,865 9,140 13,497 77.8
2004 19,500 17,725 1,373 0 331 11,539 1,995 10,463 15,028 84.8
TABLE VII
LAKE ELVA PROJECT
COST OF PROJECT GENERATION
Financing Alternative 3
Total
Annual Total Project Diesel Diesel Total
Generation Annual Debt Interest Project Generation Diesel Fuel Annual Cost of
Required Sales Service Earnings O&M Cost Required O&M Cost Cost Cost Power
Year (Mwh) (Mwh) ($000) {$000) ($000) (Mwh) ($000) ($000) ($000) (¢/kwh)
1985 10,692 9,844 3,964 (404) 331 2,731 384 371 4,646 47.2
1986 11,219 10,324 3,964 (404) 354 3,258 410 490 4,814 46.6
1987 11,761 10,818 3,964 (404) 379 3,800 440 631 5,010 46.3
1988 12,317 11 '323 3,964 (404) 405 4,356 470 799 5,234 46.2
1989 12,888 11,840 3,964 (404) 434 4,927 503 999 5,496 46.4
1990 13,472 12,368 3,964 (404) 464 5,511 538 1,235 5,797 46.9
1991 13,982 12,834 3,964 (404) 497 6,021 828 1,491 6,376 49.7
1992 14,487 13,293 3,964 (404) 532 6,526 886 1,786 6,764 50.9
1993 14,989 13,750 3,964 (404) 569 7,028 948 2,125 7,202 52.4
1994 15,498 14,213 3,964 (404) 609 7,537 1,014 2,518 7,701 54.2
1995 16,003 14,671 3,964 (404) 651 8,042 1,085 2,969 8,265 56.3
1996 16,430 15,057 3,964 (404) 697 8,469 1,161 3,455 8,873 58.9
1997 16,848 15,433 3,964 (404) 745 8,887 1,243 4,006 9,554 61.9
1998 17,257 15,801 3,964 (404) 798 9,296 1,329 4,630 10,317 65.3
1999 17,647 16,149 3,964 (404) 853 9,686 1,423 5,331 11,167 69.1
2000 18,032 16,492 3,964 (404) 913 10 '071 1,522 6,125 12,120 73.5
2001 18,400 16,820 3,964 (404) 977 10,439 1,629 7,015 13' 181 78.4
2002 18,750 17,100 3,964 (404) 1,046 10,789 1,743 8,012 14,361 84.0
2003 19,100 17,350 3,964 (404) 1 '119 11 ,139 1,865 9,140 15,684 90.4
2004 19,500 17,725 3,964 (404) 1,197 11 '539 1,995 10,463 17,215 97.1
I
TABLE VII I
LAKE ELVA PROJECT
COST OF POWER GENERATI
nancing Alternative 3
Assistance
Cost of Cost of Annual Deferred Loan Balance Annual
Power Power Debt Assist. Interest or Accrued Payment on
w/Lake Elva Diesel Only Loan Amount 10.5% Principal Loans
Year (¢/kwh) (¢/kwh) ($000) ($000) $000) ($000).
1985 47.2 9,844 20.4 2,638 0 2,638 0
1986 46.6 10,324 22.1 2,529 277 5,167 0
1987 46.3 10,818 23.9 2,423 543 8 '133 0
1988 46.2 11,323 25.9 2,299 854 11,286 0
1989 46.4 11,840 28.2 2,155 1,185 14,626 0
1990 46.9 12,368 30.7 2,004 1,536 18,166 0
1991 49.7 12,834 37.0 1,630 1,907 21,703 0
1992 50.9 13,293 40.4 1,396 2,279 ,378 0
1993 52.4 13 '750 43.8 1,183 2,665 29,226 0
1994 54.2 14,213 47.5 952 3,069 ,247 0
1995 56.3 14,671 51.7 675 3,491 ,413 0
1996 58.9 15,057 56.3 391 3,928 41,732 0
1997 61.9 15,433 61.4 77 4,382 46,191 0
1998 65.3 15,801 67.0 0 4,581 50' 772 269
1999 69.1 16,149 73.7 0 4,588 55,360 743
73.5 16,492 80.1 0 4 '725 60,085 1,088
1 78.4 16,820 87.7 0 4,745 64,830 1,564
2002 84.0 17' 100 . 3 0 4,704 69,534 2,
2003 90.4 17,350 105.9 0 4,612 74,146 2,689
2004 97.1 17,725 116.0 0 4,435 78,581 3,350
Continuation of this schedule beyond 2004 reflects an ability of the utility to increase
annual loan payments based upon the general rate of inflation and the diesel generators
in the all diesel system.
Debt Assistance (Cont.) }
Cost of Total Cost of Annual Deferred Loan Balance Annual
Power Annual Power Debt Assist. Interest or Accrued Payment on
w/Lake Elva Sales Diesel Only Loan Amount 10.5% Principal Loans
Year (¢/kwh) (Mwh) (¢/k~ . - ( $_Q()_Dl_ ---($000) ($000) ($000)
2005 101.0 18,000 122.1 0 4,453 83,034 3,798
2006 105.2 18,250 128.8 0 4,412 87,446 4,307
2007 109.7 18,500 135.8 0 4,354 91,800 4,828
2008 114.5 18,750 143.3 0 4,239 96,039 5,400
2009 119.5 19,000 151.2 0 4,061 100,100 6,023
2010 126.6 19,000 161.7 0 3,842 103,942 6,669
2011 134.2 19,000 172.9 0 3,561 107,503 7,353
2012 142.2 19,000 184.9 0 3,175 110,678 8,113
2013 150.9 19,000 197.8 0 2,710 113,388 8,911
2014 160.1 19,000 211. 5 0 2,140 115,528 9,766
2015 170.0 19,000 226.3 0 1,433 116,961 10,697
2016 180.6 19,000 242.0 0 615 117,576 11 ,666
2017 191.9 19,000 258.8 0 0 117,211 12 '711
2018 204.0 19,000 276.9 0 0 115,667 13,851
2019 217.0 19,000 296.2 0 0 112,764 15,048
2020* 191.3 19,000 320.7 0 0 100,018 24,586
2021 227.0 19,000 342.8 0 0 88,718 22,002
2022 242.9 19,000 366.4 0 0 74,568 23,465
2023 259.9 19,000 391.7 0 0 57,356 25,042
2024** 278.1 19,000 400.0 0 0 40,217 23,161
2025** 297.6 19,000 400.0 0 0 24,984 19,456
2026** 318.4 19,000 400.0 0 0 12,103 15,504
2027** 340.7 19,000 400.0 0 0 2,107 11,267
2028 364.5 19,000 376.8 0 0 0 2,328
2029 390.1 19,000 390.1 0 0 0 0
* An increased amount of funds are available in year 2020 for repayment of state debt
because revenue bond debt service has expired, and the Reserve Fund is also used to
reduce the state loan balance.
** Rates are held constant at $4.00/kwh until the debt service on state debt assistance
loans is repaid. The rate increases beyond year 2020 after retirement of Revenue
bond debt service could be decreased if it is desirable to extend the repayment period
on state debt beyond 44 years.
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LEGEND
IBJ HYDROELECTRIC GENERATING PLANT WITH
INSTALLED CAPACITY.
TRANSMISSION LINE, 138 KV 3f)
EXISTING DISTRIBUTION LINES ( UP TO 24KV)
ICJ OR 31/J
SINGLE WIRE GROUND RETURN
TRANSMISSION, 40 KV
DISTRIBUTION LINE ( UP TO 24 KV)
· • • • • • • • • • TRANSMISSION LINE, 69 KV 3f
PLIJ.S 10 YfLLA GES INTERTIE
1: I 000 000
FIGURE m"'
Dillingham-Section III
APA016/A
of Lake Elva in late 1979 for the Alaska Power Authority.
Runoff records for the Snake River and Nuyakuk River have an
annual average runoff of about 4 cfs per square mile. The
NOAA Technical Memorandum NWS AR-10, Mean Monthly and Annual
Precipitation Alaska (1974) indicates a mean annual precipita-
tion of 80 inches for the Lake Elva drainage and from under 40
to 80 inches for the two recorded river drainages, with a very
small portion within the 80 inch isohyet.
Study of available data including precipitation records at
Dillingham resulted in a group of estimates for runoff (See
Appendix A). The estimate based on relating the nearby river
drainage records to the Lake Elva basin (Method 1) is used in
this evaluation. At the estimated 5 cfs per square mile of
Elva watershed the annual average runoff become 38,000 acre-ft.
or 52.5 cfs. A check based on the 80 inches of rainfall with
an estimated 10% loss to evaporation and other losses develops
an estimated average annual runoff of 40,320 acre-ft or 55.7 cfs.
Using Dillingham precipitation records and constructing on
synthetic record for 20 years (Method 2) results in an estimated
39,440 acre-ft. or 54.5 cfs. This synthetic record provided a
set of data which was used to estimate the maximum regulated
runoff that could be assured with the 29,000 acre-ft. reservoir
as 50 cfs.
Installed capacity for the Lake Elva development was selected
to assure a 11 mi nor 11 project status with procedura 1 benefits.
The size of the project is small with regard to the electric
system so there is no compelling reason to match the system
load factor with an equivalent plant factor. The smaller kW
size units will save some investment, yet still produce all
the energy available. Further study after a season of stream
guaging will provide a better base for final determination of
project design.
III-5
MIS08/S3
SIGNIFICANT DATA
LAKE ELVA HYDROELECTRIC
RESERVOIR
Drainage Area
Normal Maximum Water Surface (msl)Elevation
Minimum Water Surface Elevation
Surface Area-Normal Maximum W.S.
Live Storage
Average Flow
Regulated Flow
DAM
Type
Height
Crest Elevation
Volume
Impervious Membrane
SPILLWAY
Type
Crest Elevation
Width
Design Discharge
WATER CONVEYANCE
Pipe Line, 48-inch Dia., Lenqth
Surge Tank 48'' Di a. , Length
Penstock 42-inch to 36-inch Dia, Length
POWER PLANT
Capacity
Maximum Gross Head
Type of Turbines
TRANSMISSION LINE
Voltage
Length
Conductor Size
ANNUAL ENERGY
Prime
Average Annual
Secondary
III-6
10.5 square miles
350
305
720 Acres
29,000 Ac-Ft.
52.5 c.f.s.
50 c. f. s.
Rockfill
137 ft.
357
80,000 c.y.
Aluminum Alloy
Ungated Side Channel
350
100 Ft.
7,400 c.f.s.
4,100 ft.
150 ft.
3,200 Ft.
1,500 kW (2 Units)
300 Ft.
Horizontal Francis
24.9 kV
29 mi.
4/0 ACSR
7, 972 MWh
8,370 MWh
398 MWh
Dillingham -Section III
APA016/A
2. Geology
The regional geo 1 ogy of the Good news Bay quad rang 1 e was
published by USGS in 1961 (Hoare and Coonrad). There is
little additional geologic information on the area. The bed-
rock surrounding the lake and valley are part of the Gemuk
group of rocks that extend northward into the Bethel quad-
rangle. These rocks are characterized by siliceous silt-
stones, cherts and mafic volcanic rocks. At Lake Elva the
bedrock is generally a dark green, siliceous, lightly metamor-
phosed siltstone. The valley bottom is filled with outwash
and alluvium with coalescing talus fans descending from the
steep valley walls.
The proposed dams i te is 1 ocated about one-and-one-quarter
miles downstream from the present out 1 et. At this point, a
sill of bedrock obstructs the flat bottom of the valley and
Elva Creek is forced into a narrow meandering gorge cutting
into bedrock. The rocks strike very close to north-south,
with a near vertical attitude. Two major joint sets cut the
unit; one subparallels the north-south trend on rocks, the
other strikes N45E and dips near vertically. Aside from
jointing, the rocks are massive and uniform.
The axis of the proposed dam would traverse exposed bedrock in
the vicinity of the gorge itself (~100 feet across) and thinly
veneered bedrock (1-5 feet) on the gentler slopes above the
gorge. The 30 foot stream channel contains minimal alluvial
fill of not more than 15 feet in depth.
Large amounts of earthfill and/or concrete aggregate can be
obtained a short distance upstream of the gorge from the
alluvial terraces (up to 30 feet in height) adjacent to the
present stream channel. Originally the valley was blocked off
by the more resistant bedrock at the gorge site. For a time,
the stream channel flowed through a low pass at the northern
end of the proposed dam. Another channel developed closer to
mid-valley and slowly eroded a channel deeper and deeper,
which has become the present gorge. As the base level of Elva
Creek dropped, the channel above the gorge cut into the valley
fill leaving these high terrace deposits.
A spillway could utilize the old stream channel on the northern
end of the dam axis. A penstock line could be routed along
the gentle slopes of the northern side of the valley to a
powerhouse situated on the sandy gravels of the Elva Creek
alluvial fan.
The steep valley walls surrounding Lake Elva show some evidence
of landslides and avalanches and a dam should be designed to
withstand overtopping.
III -7
>--<
>--<
>--<
I
'XJ
'"0
0
~ m
:lJ
I
§~
m
tl
z
ALASKA POWER AUTHORITY
LAKE ELVA PROJECT
2 X750KW
GENERAL PLAN & LOCATION
FIGURE ill -2
DATE DEC. 1979 CGITRACT 9703-3
Dillingham-Section III
APA016/A
No evidence was observed for recent faulting in the area and
the area falls within a relatively low earthquake hazard area.
Sealing the joint sets in the keyway of the dam will probably
be the most significant problem. Overall, the damsite, penstock,
and powerhouse sites are in favorable geologic terrain.
3. Project Arrangement
The Lake Elva Project will consist of the following principal
elements:
a. A rockfill dam across the creek, founded on bedrock, at
stream mile 1.5 with an uncontrolled spillway through a
saddle approximately 1000 feet north of the dam with the
crest at elevation 350.
b. A low pressure pipeline approximately 4100 feet in length
and 4'-011 diameter roughly following the 300 foot contour
from the dam to a surge pipe up the side of the mountain
to the 400-foot contour.
c. A power penstock approximately 3200 feet in length and a
diameter varying from 3'-611 at the top to 3'-011 to convey
the water from the low pressure pipeline at the surge
pipe location to the powerhouse at elevation 50.
d. A surface powerhouse containing two Francis type horizontal
turbines rated at 1000 HP, two 935 kVA horizontal generators,
and electrical switchgear.
e. Switchyard and transmission line to Dillingham.
4. Hydroelectric Power Production
The powerplant will contain two horizontal Francis type turbine-
generator units rated at 750 kW. The plant will produce
7,927 MWh of prime energy with an average energy of 8,370 MWh
per year operating at a net head of 260 feet and an average
flow of 52.5 cfs. The 398 MWh of secondary energy will be
usable within the larger energy requirement of the community
power system.
III-9
Dillingham Section III
APA016/A
5. Description of Project Facilities
a. Dam
The dam will be a rockfill type, founded on bedrock, with
a crest at elevation 355. The dam location is approx-
imately on the section corner of sections 1, 2, 11 and
12, T7S, R58W, Seward Meridian Alaska.
U.S.G.S. maps and a cursory examination revealed two
possible damsites. One at the outlet of Lake Elva and
another approximately one mile downstream. Although the
site at the lake outlet would require a dam of less
height, a much longer pipeline would be required and the
geology is not favorable for a dam at this location.
Also, spillway costs would be much greater due to the
topography.
The downstream site has favorable geologic conditions,
considerably reduces the length of the pipeline, sub-
stantially increases the storage, and reduces the length
of the project road. The height of the dam at elevation 350
was chosen as it provides a near desirable storage for
regulation and an old channel of Elva Creek provides an
economical spillway section. Rock for the embankment
material could be obtained from the abundant talus deposits
along the valley sides. A concrete cutoff wall and
pressure grouting of the rock foundation to reduce founda-
tion percolation will be incorporated in the dam. A
vertical impervious seal of butt welded ~11 x7'x20' aluminum
alloy plates would extend from the concrete cutoff wall
to 2-feet above the rockfi ll crest. A 100 foot wide
uncontrolled spillway would be excavated in the saddle
approximately 1000 feet north of the dam with the crest
at elevation 350. The maximum depth of flow during a
probable maximum flood is expected to be about 5 feet,
leaving 2 feet of freeboard above the dam for wave action.
See Figures III-3 and III-4.
b. Waterway
A 48 inch diameter steel pipe, concrete encased, would
penetrate the dam with an upstream invert at elevation
295. The upstream end would be bell-mouthed to reduce
entrance losses and be provided with a trashrack and stop
log guides. The downstream end waul d terminate with
48-inch hand operated gate valve with locking provisions.
II I-10
Dillingham -Section III
APA016/A
Power flows would be conducted from the valve to a surge
pipe via a 48-inch diameter CMP, 12 gauge, with the
corrugations running he 1 i ca lly to reduce friction 1 oss.
Joints would be made with bands over 0-rings to effect a
seal. The pipe line would be approximately 4100 feet in
1 ength and roughly fo 11 ow the 300 foot contour to a
prominent ridge on the left (north) bank of Elva Creek.
A Tee in the line, with a 48 11 diameter CMP pipe running
up the ridge to elevation 400 would provide for pressure
surges and a penstock varying in diameter of 3 1 -6 11 to
3 1 -0 11 and approximately 3200 feet in length would run
down the ridge to a powerhouse located on Elva Creek
about 800 feet upstream from the mouth. Total head loss
at maximum flow (84.5 cfs) would be about 15 feet. The
penstock pipe would be spiral-welded with standard ends
grooved for victaulic couplings. The penstock and pipeline
will be placed in a trench and buried where feasible and
the remainder will be unburied. The trench sections of
the pipeline and penstock will be where it is more economical
to trench than follow the contour with additional length
of pipeline or expensive miter joints and anchors in the
penstock.
c. Powerhouse
The powerplant will be an insulated steel building on
Elva Creek with the tailwater at elevation 50. The
foundation wi 11 be reinforced concrete p 1 aced on com-
pacted gravel deposits. The powerhouse would contain two
1000 HP Francis turbines with speed increasers and two
750 kW horizontal generators. The centerline of the units
would be placed at elevation 58. The tailrace will
discharge into Elva Creek about 1,000 feet upstream from
the mouth at Lake Nerka.
A minimum of two units should be installed so that the
project could still operate with one unit out of service.
Since the system minimum load is considerably greater
than the project can produce on a continuous basis, the
turbines can be operated at all times near maximum
efficiency whether base loaded with one unit or used as
peaking units with both operating during peak hours. The
addition of more than two units would not increase the
plant reliability nor produce any more kilowatt-hours of
energy. It would increase the number of machines to
maintain and repair and increase the size of the powerhouse.
For these reasons, two 750 kW units were selected for the
Project. A review of this selection would be in order
after a season of stream flow measurements are available.
II I -11
Dillingham-Section III
APA016/A
d. Transmission Lines
The connection to the existing Nushagak Electric System
will be made in Aleknagik (the existing 7.2 kV, single
phase line would have to be upgraded to 24.9 kV, three
phase). The transmission circuit is assumed to consist
of approximately 9 miles overhead line following Pick and
Lillie Creek and approximately 20 miles submarine cable
in Lake Aleknagik; or 9 miles of submarine cable in Lake
Nerka, 2 miles overhead line to cross the valley west of
Bumyok Ridge and 18 miles submarine cable in Lake Aleknagik.
e. Access
There are no access roads north of the village of Aleknagik
at the present time and none are foreseen for the future.
The development plan does not call for an access road.
Equipment, materials and supplies will be moved in over
the ice on Lakes Aleknagik and Nerka during the winter.
Summer access will be by float plane or helicopter. A
cat trail will run from the beach of Lake Nerka near the
mouth of Elva Creek to the dam site and along the waterway
from the dam to the powerhouse.
III-12
....... ....... .......
I ......
w
ELEVATION 355 A! -1 ....
'/) tJ
1.5 /"oq,
I l/8" MAX. VIBRATORY
COM~CTED IN 2' LIFTS .
CONCRETE CUTOFF
TYPICAL
~ .. ALUMINUM
ALLOY
...,._ ... ..--,. .... .... EL. 350
ARMOR ROCK
l : . GROUT CURTAIN
II...-
, I ,,
II
DAM SECTION
ALASKA POWER AUTHORITY
LAKE ELVA PROJECT
FIGURE m-3
_.
....... .......
I ......
.j:::>.
200
400
300
200
100-
0
t ELVA CREEK
SCALE 0 ~0 100 200 300 FEET
OA"' SECTION LOOKING UPSTREAM
MAX W.S 350
PIPELINE 4'-o" 0---·-
SCALE 0 'SO 100 200 300 FEET s=---J
VERTICAL
PEN STOCK PROFILE
SURGE PIPE
4'-o·lil
114• ALUM-
INUM ALLOY
PLATE
CUTOfF WALL
SCALE 0 10 20 30 40 FEET
~ 7
INTAKE SECTION
TRASHRACK
POWERHOUSE
-L::DRAFT EL 50
SCALE 0 ..... 500 1000 2000 FEET
HORILQNTAL
ALASKA POWER AUTHORITY
LAKE ELVA PROJECT
FIGURE m-4
-I
~
(.]"!
1-
Ill
Ill
IL
~
z
0
1-~ ..,
..J ..,
AREA (ACRES X 1000)
400tt 10 9 a 1 s 5 4 3 2 1 o
35oJ I I !:/'" "'= I I I I I
300
250
200 0 10 20 30 40 50
CAPACITY (ACRE -FEET X 1000)
60 70 80 90 100
LAKE ELVA
AREA-CAPACITY CURVE
FIGURE ID-5
110
Dillingham -Section III
APA016/A
6. Project Construction
The project construction wi 11 be carried out by separate
supply and civil works construction. One general contractor
wi 11 be engaged to build the production p 1 ant portion of the
project and the transmission line will be a separate contract.
a. First Year
The contractor would commence moving his camp, equipment
and materia 1 s from the end of the road at A 1 eknagi k
across the ice to the site in March. Tractors would
prepare a level area for the camp, maintenance building,
etc. near the mouth of Elva Creek. All equipment,
materials, supplies, fuel, etc. for the first construction
season would be on site by the end of April.
The contractor would start clearing for the powerhouse,
waterway, and construct the cat trail to the damsite
during the month of May while the ground is still frozen.
Soft spots would be filled in with freeze dry gravel from
the abundant deposits in the area.
Stripping of the dam and spillway would commence in June
and simultaneously concrete aggregate would be processed
and rock fill for the dam would be quarried or stockpiled
from suitable talus areas.
In mid July the concrete cutoff wall and grouting of
bedrock would commence. Sections of the aluminum alloy
plates would be attached to flanges cast in the cutoff
wall with butt welded joints along the seams. The
aluminum plates would be brought up with the fill. A
36-inch steel pipe would be placed through the fill at
stream grade for diversion during construction. The
diversion pipe will be plugged with concrete upon
completion of the dam.
Also, starting in July, the contractor would place the
powerhouse foundation concrete, erect the metal building,
start the installation of the waterway and improve the
salmon spawning beds downstream of the powerhouse tailrace
prior to the return spawning salmon all with the guidance
of the Alaska Department of Fish and Game.
By the end of the first construction season, the dam
embankment would be in place to elevation 290, approx-
imately two-thirds of the waterway in place, the spillway
comp 1 eted, and the powerhouse ready to receive the
generating equipment. (See Figure III-6).
II I-16
Dillingham-Section III
APA016/A
b. Second Year
The contractor would remove the snow from the cat trail,
top of dam embankment and quarry area in early June and
immediately plug the diversion pipe to store the spring
runoff. The generating equipment, additional fuel,
supplies and materials to complete the project would have
been moved in over the ice during the winter.
With the dam completed to elevation 290 during the first
year, the contractor would have little trouble keeping
ahead of the rising water in the reservoir.
The dam would be topped out, the waterway completed, and
the generating equipment installed by the end of August.
The contractor would begin testing the unit in September
and making necessary adjustments and corrections to bring
the unit on line by the first of November.
Simultaneously, the contractor would be moving all equipment,
materials, etc. to the beach near the mouth of Elva Creek
for removal from the project during the coming winter.
Transmission line construction would start when ice
conditions on the lakes permitted passage of construction
equipment and continue through the winter and spring. It
is anticipated that the submarine conductor would be
placed through a trench in the ice cover. Mobilization
of materials and equipment would take place during the
summer of the first construction year.
III-17
Dillingham -SPclion Ill
APAI1/D3
7. COST ESTIMATES
LAKE ELVA
2 x 750 MW
SUMMARY
Capital Expenditures
by Year in
FERC $1,000-(1979-Base)
ACCT.
331
332
333
334
335
336
352
353
355
356
358
390
381/389
ITEM
Hydraulic Production Plant
Structures & I rnprovernen t
. 1 Powerhouse
Reservoir, Darns and Waterways
. ·1 Darn
.2 Spillway
.3 Pipeline & Surge Tank
. 4 Penstock
Water Wheels, Turbines & Generators
Accessor·y Electrical Equipment
Mise. Plant ~quiprnent
Roads
Transmission Plant
Structures and I rnprovernents
Station Equipment:
Poles and Fixtures (9 miles, 25 kV, 30)
Overhead Conductors and Devices
Underground Conductors and Devices
(20 miles, 25 KV, 4/0 Cu.)
General Plant -------· Structures & Improvements
Miscellaneous
Direct Construction Cost
Contingencies:
On Underground Work (25%)
On All Other Work ( 1 O%)
Engineering ( 15% of Direct
Construction Cost)
Total Construction
Allowance for Inflation ( 8%)
Interest during Constr·uction 9%
Total I nvestnient
Total Project Cost in 1979 -$
used in Economic Evaluation
Inflated at 8% per year to 1983
and with interest during construction
results in
III-18
1981
1,639
75
494
315
455
50
200
300
213
1 '760
582
327
840
7,350
1,223
772
9,345
12,940
1982
390
i ,499
494
721
LbO
"340
315
50
4,259
213
341
639
:11452
1, 4"i 6
1, 390
8,258
MISC09/Nl
LAKE ELVA
PRODUCTION PLANT
DETAILED COST ESTIMATE
FERC UNIT TOTAL
ACCT. ITEM QUANTITY PRI PRI
331 Structures and Improvements
.1 Powerhouse
Excavation (common) 2,000 c.y. 12.00 24,000
Concrete -Reinforced 100 c.y. 750.00 75,000
Prefabricated Building L. s. 40,000
Structural Steel 8,000 lb. 1. 50 12,000
Water & Sewerage L. s. 60,000
Clearing 2.5 Ac. 5,000.00 12,500
HVAC L. s. 50,000
Powerhouse -Mobilization Portion L. s. 116,500
Total Account 331 $ 390,000
332 Reservoirs, Dams and Waterways
.1 Dam
Rockfi ll 80,000 c.y. 12.00 960,000
Toeblock Concrete 1,000 c.y. 500.00 500,000
Grouting L. s. 200,000
Aluminum Alloy Sheeting 110,000 lbs. 4.00 440,000
Intake Structure L.S. 50,000
Dam & Reservoir Clearing 18 Ac. 5,000.00 90,000
Dam-Mobilization Portion L. s. 898,000
Subtotal Dam $3,138,000
.2 SEillwa;t
Clearing & Grubbing 1 Ac. 10,000.00 10,000
Concrete Reinforced 80 c.y. 500.00 40,000
Downstream Erosion Control L. s. 15,000
Spillway-Mobilization Portion L. s. 10,000
Subtotal Spillway $ 75,000
. 3 PiEeline and Surge Tank
Pipe 4 1 -0 11 Diameter C.M.P. 4,242 ft. 165.00 700,000
Clearing 4 Ac. 5,000.00 20,000
Excavation and Backfill 3,000 12.00 36,000
Supports 80 ea. 400.00 32,000
Pipeline -Mobilization Portion L. s. 200,000
Subtotal Pipeline $ 988,000
III-19
MISC09/N2
LAKE ELVA
PRODUCTION PLANT
DETAILED COST ESTIMATE, continued
FERC
ACCT.
333
334
335
336
ITEM
.4 Penstock
Pipe-3 1 -6 11 to 3 1 -0 11 Diameter
Clearing
Excavation and Backfill
Concrete Anchors
Penstock-Mobilization Portion
Subtotal Penstock
Total Account 332
Waterwheels, Turbines and Generators
.1 Turbine-1,000 H.P.
.2 Generator-750 kW
.3 Appurtenances
Mobilization Portion
lotal Account 333
Accessory Electrical Equipment
QUANTITY
220,000 lbs.
1. 8 Ac.
2,500 c.y.
75 c.y.
L. S.
2 ea.
2 ea.
L.S.
L. S.
Misc. Plant Equipment (Supervisory
Control, Compressed Air. Fire Protection,
10-ton Crane, etc.) L.S.
Roads, Permanent Rock Surface
Roads, Construction Access
Mobilization Portion
Total Account 336
2 mi.
1 mi.
I II -20
UNIT
PRICE
2.50
5,000.00
12.00
800.00
75,000.00
75,000.00
150,000.00
100,000.00
TOT Pit
PRICE
550,000
9,000
30,000
60,000
72,000
$ 721,000
$4,922,000
150,000
150,000
90,000
60,000
$ 450,000
$ 340,000
$ 630,000
300,000
100,000
__ 55,00Q
$ 45S,OOO
MISC09/N3
LAKE ELVA
TRANSMISSION PLANT
DETAILED COST ESTIMATE
FERC UNIT TOTAL
ACCT. ITEM QUANTITY PRICE PRICE
352 Structures and Improvements
. 1 Concrete Foundations L.S . 20,000
. 2 Substation Structure L. S . 30!000
Total Account 352 $ 50,000
353 Station Equipment
.1 Transformer 2 MVA
4.16/24.9 kV 1 ea. 30,000.00 30,000
. 2 Transformer 2 MVA
24.9/12.5 kV 1 ea. 30,000.00 30,000
. 3 Circuit Breaker, 24.9 kV 2 ea. 15,000.00 30,000
.4 Disconnects, 24.9 kV, 3 Phase 4 ea. 1,500.00 6,000
. 5 Potential Transformers, 24.9 kV 6 ea. 1,000.00 6,000
. 6 Lightning Arrestors, 24.9 kV 6 ea. 1,000.00 6,000
.7 Busbar, Insulators, Wiring, etc. L. s. 921000
Total Account 353 $ 200,000
354 Poles and Fixtures
.1 Right of Way Clearing 9 mi. 5,000.00 45,000
.2 Structures 140 ea. 1,500.00 210,000
. 3 Hardware LS. 45,000
Total Account 354 $ 300,000
356 Overhead Conductors and Devices
.1 Conductor 4/0 AWG ACSR 3 x 9 mi. 7,900.00 213,000
Total Account 356 $ 213,000
358 Underground Conductors and Devices
.1 Submarine Cable, 24.9 kV
3 Phase, 4/0 Cu. 20 mi. 87,400.00 1,748,000
.2 Terminators, 24.9 kV 6 ea. 1,000.00 6,000
.3 Lightning Arrestors, 24.9 kV 6 ea. 1,000.00 6,000
Total Account 358 $1,760,000
TOTAL TRANSMISSION PLANT $2,523,000
::.::::::...-:::::::::.=----========:::
II I-21
MISC09/N4
FERC
ACCT.
390
391/
ITEM
LAKE ELVA
GENERAL PLANT
DETAILED COST ESTIMATE
QUANTITY
Structures and Improvements
.1 Operator 1 s Cottage L. S.
Total Account 390
UNIT
PRICE
TOTAL
PRICE
---~00, 000
$ 100,000
399 Miscellaneous Equipment
.1 Office Furniture and Equipment
.2 Stores Equipment
.3 Communication Equipment
Total Accounts 391/399
TOTAL GENERAL PLANT
DIRECT CONSTRUCTION COST
L.S. 8,000
L.S. 10,000
L.S. 32,000
$ 50,000
$ 150,000
$9,860,000
III-22
....... .......
.......
I
N w
Dillingham -Section
APA11/M3
Item
Mobilization
Cat Trail
Dam
Spillway
Waterway
Powerhouse
Testing
Year
Quarter
Transmission & Substations
Demobilization & Clean-up
·-···-·-·-----·
1
J l
CONSTRUCTION SCHEDULE
First Second
2 3 4 1 2 3 4
-
I I
,.
J J J l
ALASKA POWER AUTHORITY
LAKE ELVA PROJECT
CONSTRUCTION SCHEDULE
FIGURE ill-6
Dillingham-Section III
APA016/A
8. Environmental and Institutional Concerns
a. Hydrodevelopment
No conflicts \vi th the moose, caribou and brown bear
populations are anticipated, other than some slight
disturbance of habitat during construction.
There are no known archaeological sites in the area that
would be inundated. However, to be certain that no sites
are overlooked an archaeological survey should be conducted
prior to construction.
The fishery aspects also need more investigation.
The lake supports small populations of char and grayling.
The lake is isolated from its outflow streams by a waterfall
which forms a migration barrier to anadromous fish.
Although exact figures are not available, the number is
relatively low. The stream supports spawning populations
of sockeye salmon as well as rainbow trout, char, and
grayling. The proposed development should cause only
minimal conflicts with the downstream fishery. Further
study of the effect of the project on these populations
should be undertaken during the detailed environmetnal
assessment. (See Appendix 0-1 for comments).
b. Transmission
The transmission corridor will cross several small streams.
As there is a possibility that the transmission l1ne
construction could introduce sediments into these streams,
a study should be conducted during the detailed environ-
mental assessment to determine the optimum methods of
insuring that anadromous fish streams are protected.
The underwater portion of the transmission line is not
expected to cause disturbance of the fisheries.
Use of single wire ground return transmission system,
wherever practicable would minimize visual impact.
c. Institutional Constraints
Most of the project features are located in a proposed
state park (Wood River Lakes) but has been set aside in
the park statutes as a non-objectionable development.
Land status in detail is as follows:
III-24
Dillingham-Section III
APA016/A
TOWNSHIP PROJECT FEATURE STATUS
(Ref: Seward Meridian)
T6S, R58W Lake Elva Tentative Approval of
State selected land
T7S, R58W Lake, Dam, Penstock, Power-
house, Transmission 1 i ne
T7S, R57W Transmission Line
T8S, R57W Transmission Line
T9S, R57W Transmission Line
Tentative Approval of
State selected land
Tentative Approval of
State selected land
Tentative Approval of
State selected land
BLM control pending
tentative approval of
State selected lands
T10S, R57W Transmission Line Extensive native claim
land with some BLM
controlled land
T10S, R56W Transmission Line
B. GRANT LAKE PROJECT -GENERAL DESCRIPTION
1. Introduction
Extensive native claim
land with some BLM
contra 11 ed 1 and
Grant Lake, at the head of the Wood River chain of Lakes, lies
at Elevation 467. The lake has a surface area of 3.05 square
miles and a drainage area of 37.2 square miles as measured
from the U.S.G.S. Dillingham (D-7) and (D-8) quadrangle,
scale 1:63,360. The drainage area is mostly barren country on
the divide between the Wood River and Nuyakuk River systems.
Grant River from its mouth at Kulik Lake is 6.5 river miles in
length to the mouth of Grant Lake. From river mile 6.5 (Grant
Lake) to river mile 6.0, the river flows at a fairly uniform
grade and drops 17 feet in elevation. From river mile 6.0 to
4.6, the river drops approximately 200 feet in a series of
falls and rapids through a steep narrow canyon. The highest
fall is approximately 100 feet high. From river mile 4.6 to
3.2, the river drops 75 feet at a fairly uniform rate. Below
mile 3.2, the river meanders through a flat plain westerly
into Kulik Lake. There were no signs of salmon in the stream
above mile 3.2, however, thousands of spawning salmon were
observed below mile 3.2 in the fall of 1979.
III-25
Dillingham-Section III
APA016/A
With six years of actual stream gauging (7-59 thru 7-65) and
19 years of synthetic record (based on the adjacent Nuyakuk
watershed 1954 thru 1978) the average annual runoff from Grant
Lake was found to be 69,590 acre-ft. or 96.12 cfs. With
active storage in the proposed reservoir of 52,500 acre-ft. it
is estimated that the average regulated flow would become
92 cfs. An evaluation of the runoff record suggests that it
may not be practicable to utilize all the available secondary
energy, so the prime energy rating is used in the power cost
study. Further studies of ways to utilize all the secondary
energy (such as increasing installed capacity) may be useful
when and if the project is deemed worth additional consideration.
With forecast community system load factors of 0.52 to 0.66
depending on the scenario, the installed capacity of 2,700 kW
at Grant Lake represents a plant factor of 0.54 based on the
average annual energy or 0.51 based on the prime energy rating.
II I -26
MIS08/Sl
SIGNIFICANT DATA
GRANT LAKE HYDROELECTRIC
RESERVOIR
Drainage Area
Normal Maximum Water Surface Elevation
Minimum Water Surface Elevation
Surface Area-Normal Maximum W.S.
Live Storage
DAM
Type
Height
Crest Elevation
SPILLWAY
Type
Crest Elevation
Width
DIKE
Type
Crest Elevation
Height
Volume
Impervious Membrane
CANAL
Length
Base Width
Invert Elevation
WATER CONVEYANCE
Pipe Line, 60-inch Dia., Length
Surge Tank 48 11 I.D., 60" O.D., Height
Penstock 48-inch Dia, Length
POWER PLANT
Capacity
Maximum Gross Head
Type of Turbines
TRANSMISSION LINE
Voltage
Length
Conductor Size
ANNUAL ENERGY
Prime
Average Annual
Secondary
III-27
37.2 square miles
500
477
2,500 Acres
52,500 Ac-Ft.
Thin Arch Concrete
56 ft.
504
Overflow Section in Dam
500
125 Ft.
Rockfill
506
37 Ft.
14,000 c.y.
A 1 umi num A 11 oy
4,860 Ft.
20 Ft.
468
60 Ft.
3,100 Ft.
2,700 kW (2 Units)
210 Ft.
Horizontal Francis
96 kV
65 mi.
266.8 KCM ACSR
12,130 MWh
12,672 MWh
542 MWh
N
I ,
0 >-,...
en -1-1-... ::J (,) 0::: 1-0 1'-~ 0 (,) >-~ I w I --,~<( 0 1-
::J 0 ~ s <( O:::~..o o...l() w z wi'Q<C 0::: ~ . ~
j-o... ::J
(!)
1-I ~ -z C\J <( LL en <( 0::: ,...
0:.: w ~
(.!) z cj w ....
0 (.!) ~
<(
0
Dillingham -Section III
APA016/A
2. Geology
The USGS has not yet published a geologic map for the Dillingham
quadrangle. The rock units are similar to those at Lake Elva
and may also be part of the extensive Gemuk group. The canyon
of Grant River is underlain by a sequence of northwest striking
black shales. The shales display very little fissility and
show minor local folding and contortions.
Near the proposed damsite, several more resistant cherty
layers and bands were observed forming ridges. The predominant
joint set strikes northerly with a dip of 50° to the south.
The damsite selected on the Grant River would require only a
small dam (perhaps 150 feet in length and 30 feet high) with
sheetpile extensions or the equivalent for another 150 feet on
either side. The bedrock underlying the proposed axis is
massive with only a few tight joints. Constructing a leakproof
structure in the gorge itself should not be difficult. The
gently s 1 oping benches above the gorge are covered with a
layer of organic debris and thin glacial soils. To give the
dam a few more feet in height, cutoff walls made of sheetpiles
driven to bedrock have been proposed. Developing a good seal
here may be more difficult and the depth of overburden will
need to be determined accurately.
A second ancient channel exists from Grant Lake 1 s northwestern
corner. This channel will also need to be dammed. This site
was not visited on the ground but appeared from the air to be
an equally good site and would require a dam of still lesser
extent.
It is proposed to run a penstock from this second damsite
along the old channel cut and down to a powerhouse located
near the center of Township 32. Only two sites have the
necessary room for a small powerhouse site; 1) Upper site--
directly below the lower falls, and 2) Lower site--at the
junction of Grant River with its major tributary in Township 32.
While the penstock route would be slightly longer, the greater
space available, access, and the smaller hazard from slides at
the lower site are recommended.
The shales underlying the proposed powerhouse sites are quite
similar to the damsite and should form good foundations. The
upper site would have to be situated at the toe of the talus
fan. The talus would need to be excavated and a retaining
wall constructed to keep the talus in place and for safety
from minor slides.
Rockfill for the two damsites is available nearby, although
not directly from the abutments. The shales generally fracture
into blocky cobble sized fragments. Good sources of aggregate
I II-29
Dillingham-Section III
APA016/A
for concrete structures will be harder to come by in the close
vicinity of the dam sites. The investigation has not been
complete enough to write off the possibility, however, the
lake margin and river channel directly below the outlet contain
very coarse alluvium with minimal fines. Better aggregate is
probably available below the lower powerhouse site.
Sealing the dam extensions on the Grant River, and selection
of the best site for the powerhouse are two problems which
will need further attention. Hazards to the site in general
are low, with the exception of rockslides within the main
canyon (affecting either powerhouse site or the penstock
route). Earthquake hazard in this area is relatively low. No
evidence of faulting was observed.
3. Project Arrangement (See Figure III-7)
The Grant Lake Project will consist of the following principal
elements:
a. A concrete dam across the river at mile 6. 0, founded on
bedrock with an uncontrolled ogee spillway with crest at
Elevation 500.
b. A canal excavation approximately one mile north of the
dam with an invert elevation at 468 to divert the flow to
an intake structure 0.8 miles north-northwest of the dam.
c. A rockfill dike in the canal 37 feet maximum height at
crest Elevation 506 containing an intake structure at
invert Elevation 470. A 5 1 -0" diameter steel pipe
installed under the dike from the intake structure to a
valve on the downstream toe.
d. A low pressure pipeline 6,600 feet in length from the
dike to a surge tank above the powerhouse.
e. A penstock 3,100 feet in length from the surge tank to
the powerhouse located on the right bank of Grant River
just downstream of the last waterfall on the river.
f. A powerhouse containing the turbines, generators, and
e 1 ectri cal switchgear and an adjacent step up substation
and transmission take-off structure.
g. Other facilities including a caretakers cottage, gravel
airstrip, project road connecting the cottage, powerhouse,
dike, airstrip and dam, and transmission line.
I II -30
Dillingham-Section III
APA016/A
4. Hydroelectric Power
The powerplant will have two generators each rated at 1,350 kW,
powered by horizontal reaction (Francis) turbines 2000 HP
each. The plant is expected to produce 12,130 MWh of prime
energy annually with a potential average annual energy produc-
tion of 12,672 MWh. It is assumed in the Power Cost Study
that the 542 MWh of secondary energy is not available. (See
Appendix A-6).
5. Description of the Project Facilities
a. Dam and Spillway
Previous studies by the Corp of Engineers envisioned a
dam at the upper falls (river mile 6) and a 2.5 mile long
tunnel to divert the flow to a powerhouse on the north
shore of Lake Kulik. The average net head deve 1 oped
would be 397 feet and the prime power capability of
3,120 kilowatts. The Corps scheme did not provide for
mitigating damages of the excellent salmon spawning
provided in the lower reaches of Grant River.
This study is aimed at partial development of the power
potential of Grant Lake and enhancing the natural salmon
resources.
Preliminary plans were to extend the waterway from the
mainstream dam at mile 6 to a powerhouse at the foot of
the lower falls at mile 4.6 and use the ancient channel
to the north of the existing channel for a natural spillway.
On-site investigations revea 1 ed that the canyon wa 11 s
between miles 4. 6 and 6 were too narrow, steep and
meandering to consider placing a pipeline for water
conveyance.
The proposed plan utilizes the existing topographic
features to maximum feasibility and still maintain and,
hopefully, enhance the fishery in Grant Lake. The proposed
plan reverses the spillway and pipeline from that in the
preliminary plan in that a canal will be constructed to a
dike across the ancient channel and a pipeline leading
from there to a surge tank on the bluff above the power-
house. The spillway will be incorporated in the main
stream dam at mile 6. (See Figure III-9).
The dam will be a thin arch, single curvature, reinforced
concrete dam with an uncontrolled spillway. The crest of
the spillway is at Elevation 500 and the top of the dam
at Elevation 504. The spillway section will be 125 feet
in chord width. An apron is provided to divert spillway
I II-31
Dillingham-Section III
APA016//\
flows away from the toe of the dam and onto the bedrock.
A 60-inch diameter steel pipe will be cast in the concrete
at invert Elevation 450 for temporary diversion during
construction. The upstream end will be flanged with
bolts protruding to attach a blind flange upon closure.
The pipe would then be plugged with concrete.
Hydrologic data for the Grant Lake basin is included in
Appendix A-6.
A grout curtain will be provided along the entire length
of the dam. The foundation will be stripped to sound
bedrock.
b. Canal
A canal will be excavated from the lake shore to the dike
and intake structure with an invert elevation of 468,
bottom width of 20 feet and side slopes of 1/1. Minimum
drawdown of 23 feet will be to Elevation 477.
c. Dike and Intake Works
The dike will be a rockfi ll structure with a maxi mum
height of 37 feet to Elevation 506. The crest width will
be 10 feet and upstream and downstream slopes of 1.5 horizontal
to 1.0 vertical. The structure will be sealed with a
~ inch aluminum alloy through longitudinal center of the
dam.
A 60 inch diameter pipe with a bell mouth entrance on the
upstream toe and a hand operated gate valve on the downstream
toe will penetrate the dam for power flow. The upstream
end invert will be at Elevation 470.
d. Waterways
A low pressure pipeline with extend 6,600 feet fro~ the
intake works to a surge tank 3,100 feet from the powerhouse.
The pipe will be 60 inch, 12 gage, CMP with the corrugations
running helically to reduce losses. The joints will be
sealed with 0-rings under bands. The pipe will roJghly
follow the 465 foot contour and buried in a trench where
not in rock.
I II -32
Dillingham-Section III
APA016/A
The surge tank will be a 48 inch pipe inside a 60 inch
pipe, 60 feet in height, guyed to withstand wind and
other forces. The area between the two pipes will be
filled with insulation. The top will have an insulated
cover with breather vents. The penstock, a 48 inch
diameter by !:i inch wall thickness pipe, will extend
3,100 feet from the surge tank to the powerhouse. The
penstock will be spiral weld with standard pipe ends with
grooves for victaulic couplings.
e. Powerhou3e
The powerhouse will have a reinforced concrete substructure
with a prefabricated metal structure above the generator
room floor.
The powerhouse will contain two 1,350 kW horizontal
generators driven by 2,000 HP horizontal reaction turbines
with 233 feet of effective head and 92 cfs. The p 1 ant
wi 11 normally operate as a base 1 oad p 1 ant operating
under an average net head of 215 feet and 92 cfs. The
unit would produce 12,130,000 kWh of prime energy per
year.
Two units were selected for this site so that the project
could still operate with one unit out of service and
provide peaking capability when both units were in operable
condition.
f. Transmission Line
Energy would be transported via a 35 kV overhead transmission
1 ine to Aleknagik, where the 1 ine would tie into the
existing Dillingham system at a transformer substation.
The line route mostly follows a low ridge separating the
Wood River Lakes from the Nushagak River Valley. The
distance is approximately 65 miles.
g. Project Roads
Project roads will consist of approximately 2.5 miles of
grave 1 roadway connecting the powerhouse, intake works
and dam. A section of the road between the dam and
intake works will be widened and used as a landing strip
for aircraft.
II I-33
Dillingham-Section III
APA016/A
h. Access
Access to the plant will be over a winter cat trail or by
float planes in the summer or ski planes in the winter
during the early part of construction. A portion of the
project road will be widened to serve the dual purpose of
a runway and road.
j. Reservoir
A portion of the reservoir will require the removal and
burning of stunted spruce trees.
II I -34
.......
I
w
V1
ELEVATION 506 -'-_ w i:,..
NORMAL MAX. W.S. ELEV. 500
Y4" ALUMINUM
ALLOY
o CROCK FILL .2:::> o.,
"
-----!: lr1 R £r 9 2 IIllo 4! Q Q!a$> '::J ELEV. 468
DIKE SECTION
ALASKA POWER AUTHORITY
GRANT LAKE PROJECT
FIGURE m-S
.------.....:-ELEV. 504
ELEV. 504_ ..----..-------.
ELEV. 500
--,--,-----------
1 I
I :
8 END VIEW
-------~------------
TEMPORARY DIVERSION PIPE
60" DIA. PLUGGED WITH
CONCRETE ON COMPLETION
DAM SECTION
lTT-36
.......
........ ........
I w ......
z
0
;:::. .. > ....
-' ...
NATURAL GROUND SURFliCE
'-.EARTH-...,
500[ c::(EMA~-~~ ~~~:~ 500-----------
--:-DIKE
1EL468' ~~-------PIPELINE 60" i
I
400~-·--
leO-
zoo~--
SCALEO 50 100 200FEET s=::::=· .. -·-·. J
VERTICAL
PENSTOCK PROFILE
' ' I
60"fii=O•INSULAT;jON !
PiPE r:
40"0 A i
PIPE : I
I
SECTION A-A l
'
fTOPEL5!0
SURGE TANK DETAIL
SURGE TANK
SCALE 0 500 1000 2000 3000 I'EET
HORilONTAL
£RAFT EL 240
ALASKA POWER AUTHORITY
GRANT LAKE
FIGURE lli·IO
I
w
co
1-
UJ
UJ
IL.
~
z
0
1-< >
UJ
...J
UJ
AREA (ACRES X 1000 j
5204 3 2
510 -!-----------+-~ -+--
I
500t-----1----+-----+----------+----+----
1 I
I !
I I I ,
1 I
' I
49ol I I I I I \. Y ---1
~----+---t~~+i~---+---J-----r------1
I i I I ---+-· I --+-------J
i -~ I f
I I I I I I I
I ' I
480
470
460r------+----~~------~------+-------~------+-------r------+-----~~----+----1--~ I -t---
1 i ' :
I I ' I
i
450~----~------~----~~----_.------~----~------~------~----~------~----~------~------~----~------~-----J
0 1 2 3 4 5 6 7 8 9 10 II 12 13 14 15 16
CAPACITY(ACRE -FEET X 10,000)
GRANT LAKE PROJECT
AREA-CAPACITY CURVE
FIGURE m-11
Dillingham-Section III
APA016/A
6. Project Construction
The project construction will be carried out by a separate
supply and civil works construction contracts. A single
general contractor wi 11 be engaged to bui 1 d the production
plant and a separate contract will be let for the transmission
plant construction.
a. First Year
The Contractor will mobilize his equipment, materials and
supplies in the village of Aleknagik in January using
sleds and track type vehicles. This should be completed
by the first of March and ready to proceed to Grant Lake.
Dozer ·tractors will precede the convoy, utilizing frozen
lakes where possible to minimize environmental damage.
Daily transportation for operators to and from Aleknagik
will be by snowmobile. The convoy should reach Grant
Lake by the first of April. A small crew would set up
the camp and have it in a self sufficient status by
May 1. During the month of May, the contractor would be
clearing right-of-way for the road, airstrip, and waterways
and clearing the reservoir.
In July the contractor would begin stockpiling concrete
aggregate, setting up the batchplant for concrete while
simultaneouly excavating the foundations for the dam,
dike and powerhouse structures. By the end of the
construction season, late September, the contractor will
have completed the road and airstrip, reservoir clearing,
cutoff walls for the dam and dike, installed the intake
works, completed the diversion in the main dam and placed
the first stage concrete for the powerhouse.
b. Second Year
The Contractor would move additional materials and supplies
over the cat trail from Aleknagik and use his tractors to
comp 1 ete the dike, excavate the cana 1 and prepare the
right-of-way for the penstock. Concrete operations on
the main dam would proceed and be completed. Transmission
line construction would start and continue through the
winter. The powerhouse structure would be completed and
most of the waterway installed. The diversion pipe would
be plugged at season end.
III-39
Dillingham-Section III
APA016/A
c. Third Year
The Contractor would move the generating equipment to the
site from Aleknagik over the winter trail and immediately
start installation. The remaining portion of the waterway
would be completed. The reservoir will have filled
sufficiently from spring rains and snow melt by the end
of July when testing of the unit would begin. All tests,
necessary adjustments and corrections would be complete
for the unit to go on-line the first of October.
The Contractor would be cleaning up and preparing the
camp, equipment, etc. to move out during the winter while
testing the generating equipment.
II I -40
MISC09/N9
GRANT LAKE
COST SUMMARY
2 X 1. 35 MW
Capital Expenditures
by Year in $1000 -(1979 Base) FERC
ACCT. ITEM 1982 1983 1984
331
332
333
334
335
336
352
353
354
356
HYDRAULIC PRODUCTION PLANT
Structures & Improvements
Reservoirs, Dams and Waterways
.1 Dams
.2 Pipeline and Penstock
.3 Intake Structure
.4 Surge Tank
. 5 Can a 1
Waterwheels Turbines & Generators
Accessory Electrical Equipment
Misc. Plant Equipment
Roads
TRANSMISSION PLANT
Structures and Improvements
Station Equipment
Poles & Fixtures (65 miles,
35 kV, 3 Phase}
Overhead Conductors and Devices
GENERAL PLANT
390 Structures and Improvements
381-389 Miscellaneous
Direct Construction Cost
Contingencies (15%)
Engineering (15%)
Total Construction
Allowance for Inflation (8%/yr)
Interest During Construction (9%)
Total Investment
Total Project Cost 1979 -($1000)
Inflated at 8% per year to 1985
1,000
1,200
300
400
50
600
4,130
2,070
9,750
1,463
1,682
12,895
3,349
731
$16,975
$20,123
$31,032
III-41
450
651
1,313
50
65
364
100
50
3,043
456
525
4,024
1,451
1,708
$7,183
323
1,120
300
630
50
2,423
363
418
3,204
1,504
2,166
$6,874
MISC09/N10
GRANT LAKE
PRODUCTION PLANT
DETAILED COST ESTIMATE
FERC UNIT TOTAL
ACCT. ITEM QUANTITY PRICE PRICE
331 Structures and Improvements
.1 Powerhouse
Excavation (common) 1,500 c.y. 12.00 18,000
Excavation, Rock 300 c.y. 40.00 12,000
Concrete -Reinforced 250 c.y. 750.00 187,500
Prefabricated Building L.S. 90,000
Structural Steel 12,000 lb. 1. 50 18,000
Water & Sewerage L. S. 60,000
Clearing 2.5 Ac. 5,000.00 12,500
HVAC L.S. 75,000
Mobilization Portion L.S. 300!000
Total Account 331 $ 773,000
332 Reservoirs, Dams and Waterways
.1 Dams
~Concrete Dam and Spillway
Foundation Excavation 250 c.y. 40.00 10,000
Grouting L.S. 80,000
Reinforced Concrete 380 c.y. 750.00 285,000
Diversion L. S. 30,000
Clearing 80 Ac. 3,000.00 240,000
.12 Rockfill Forebay Dam
Rockfill 14,000 c.y. 12.00 168,000
Toeblock Concrete 300 c.y. 500.00 150,000
Aluminum Sheeting 22,000 lb. 4.00 88,000
1.3 Mobilization Portion 600,000
Subtotal Dams and Spillway $1,651,000
.2 Intake Structure L. s. 50,000
.3 Pipeline
Pipe 5 1 -0 11 Diameter C.M.P. 6,600 ft. 175.00 1,155,000
Excavation and Backfill 2,000 c.y. 12.00 24,000
Supports 100 ea. 400.00 40,000
Mobilization L.S. 200,000
Subtotal Pipeline $1,419,000
.4 Penstock 316,000 lbs. 2.50 790,000
Excavation 2,000 c.y. 12.00 24,000
Concrete Anchors 100 c.y. 800.00 80,000
Mobilization L.S. 200!000
Subtotal Penstock $1,094,000
. 5 Surge Tank L.S . 65,000
III-42
MISC09/Nll
GRANT LAKE
PRODUCTION PLANT
DETAILED COST ESTIMATE, continued
FERC UNIT TOTAL
ACCT. ITEM QUANTITY PRICE PRICE
. 6 Canal
Excavation, Common 44,000 c.y. 6.00 264,000
Excavation, Rock 10,000 c.y. 20.00 200,000
Mobilization L.S. 200~000
Total Account 332 $4,943,000
333 Waterwheels, Turbines and Generators
.1 Turbine, 2,000 H.P. 2 ea. 140,000.00 280,000
.2 Generators, 1350 kW 2 ea. 140,000.00 280,000
.3 Appurtenances L. s. 160,000
Mobilization L.S. 400,000
Total Account 333 $1,120,000
334 Accessory Electrical Equipment L. s. $ 400,000
335 Miscellaneous Plant Equipment L. s. $ 630,000
336 Roads 2. 5 mi. 120,000.00 300,000
f-.1obi 1 i zat ion 100,000
Total Account 336 $ 400,000
TOTAL PRODUCTION PLANT ~8.266,00Q
III-43
MISC09/N12
GRANT LAKE
TRANSMISSION PLANT
DETAILED COST ESTIMATE
FERC UNIT TOTAL
ACCT. ITEM QUANTITY PRICE PRICE
352 Structures and Improvements
.1 Concrete Foundations L. s. 20,000
.2 Substation Structure L. s. 30!000
Total Account 352 $ 50,000
353 Station Equipment
.1 Transformer 2 MVA
4.16/69 kV 1 ea. 60,000.00 60,000
. 2 Transformer 2 MVA
69 kV/12.5 kV 1 ea. 60,000.00 60,000
. 3 Circuit Breaker, 69 kV 2 ea. 60,000.00 120,000
.4 Disconnects, 3 Phase, 69 kV 8 ea. 10,000.00 80,000
.5 Potential Transformers, 69 kV 3 ea. 3,000.00 9,000
.6 Lightning Arrestors, 69 kV 3 ea. 3,000.00 9,000
. 7 Circuit Recloser, 12.5 kV 2 ea. 15,000.00 30,000
.8 Disconnect 12.5 kV 4 ea. 1,000.00 4,000
. 9 Busbar, Insulators, Wiring, etc. L.S. 228!000
Total Account 353 $ 600,000
354 Poles and Fixtures
.1 Right of Way Clearing 65 mi. 5,000.00 325,000
.2 Structures TPS 650 ea. 5,200.00 3 380,')1)ij
3 Hardware L. s. ; ')'1': ""'"'" __ _...,. -... L ·~ .
Total Account 354 $4,130,000
356 Overhead Conductors and Devices
.1 Conductor 266.8 KCM ACSR 3 x 65 mi. 10,600.00 2,010,000
Total Account 356 $2,070,000
TOTAL TRANSMISSION PLANT $6,850.000
III-44
MISC09/Nl3
FERC
GRANT LAKE
GENERAL PLANT
DETAILED COST ESTIMATE
ACCT. ITEM QUANTITY
390 Structures and Improvements
.2 Store Facilities
Total Account 390
391/399 Miscellaneous
L. s.
.1 Office Furniture & Equipment L.S.
.2 Stores Equipment L.S.
.3 Communication Equipment L.S.
Total Accounts 391/399
TOTAL GENERAL PLANT
TOTAL DIRECT CONSTRUCTION COST
III-45
UNIT TOTAL
PRICE PRICE
50!000
$ 50,000
8,000
10,000
32!000
$ 50,000
$ 100,000
~216,000
I
+:> m
Dillingham -Section
APA11/M1
Item
Mobilization
Cat Trail
Project Road
Reservoir Clearing
Dam
Dike & Intake Works
Powerhouse
Canal
Waterway
Generator-Turbine
Year
Quarter
Transmission & Substations
Demobilization
1
•
CONSTRUCTION SCHEDULE
First Second
2 3 4 1 2 3
I
I
I T T
I I
1 I I l l l
4
Third
1 2 3 4
•
~
I I ~ •
ALASKA POWER AUTHORITY
GRANT LAKE PROJECT
CONSTRUCTION SCHEDULE
FIGURE ill-12
Dillingham -Section III
APA016/A
8. Environmental and Institutional Concerns
a. Hydro Developments
Only minor conflicts with the moose, caribou and brown
bear populations are anticipated, other than some slight
disturbance of habitat during construction.
There are no known archaeological sites in the area that
would be inundated. However, to be certain that no sites
are overlooked an archaeological survey should be conducted
prior to construction.
The fishery aspects also need more investigation.
The lake supports small populations of char and grayling.
The lake is isolated from its outflow streams by a waterfall
which forms a migration barrier to anadromous fish. The
stream supports spawning populations of sockeye salmon of
approximately 19,000 fish annually. The proposed development
is expected to cause only minimal conflicts with the
downstream fishery. Further study of the effect of the
project on these populations should be undertaken during
the detailed environmental assessment. (See Appendix 0-1
for comments).
b. Transmission Corridor
The transmission corridor will cross several small streams.
As there is a possibility that the transmission line
construction could introduce sediment into these streams,
a study should be conducted during the detailed environmental
assessment to determine the optimum methods of insuring
that anadromous fish streams are protected.
Use of single wire ground return transmission system
wherever practicable will minimize visual impact.
c. Institutional Constraints
Most of the project features are located in the proposed
Wood River Lakes State Park (See Appendix D-2), but may
be set aside in the park statutes as a non objectionable
development. This land is either still BLM controlled or
has been tentatively approved as state selected land.
II I-47
Dillingham-Section III
APA02/L
C. TAZIMINA RIVER PROJECT -GENERAL DESCRIPTION
1. Introduction
The Tazimina River has its headwaters on the western slopes of
the Alaska Range north of Lake Iliamna. The river flows
westerly through two large lakes, Upper Tazimina Lake with the
mouth at river mile 32.2 and Lower Tazimina Lake with the
mouth at river mile 18. From Lower Tazimina Lake, the river
flows through four small lakes with no significant drop until
reaching river mile 9.5 where it cascades over a 105 feet high
waterfall. The river drops another GO feet in the next 2000
feet below the falls to elevation 435 at river mile 9.15.
From river mile 9.15, the river flows at moderate grade to its
confluence with the Newhalen River near the mouth of Lake
Clark. The river from its mouth to mile 9.15 is an important
red salmon spawning stream.
A suitable forebay dam site is located at river mile 10.44
where a substantial head could be obtained due to the relief
a.t the falls downstream. f1 reservoir storage dam may be
located at mile 11.6 (Roadhouse mountain site) or at mile 18
(mouth of Lower Tazimina Lake). See map in pocket.
For the estimates in this study, a dam at the mouth of Lower
Tazimina Lake for the reservoir was used due to questionable
geo 1 ogy at the Roadhouse mountain site. Cost of storage at
either site is comparable, as the Roadhouse Mountain site
would have fewer miles of access roads and power and control
rables to the discharge valves if geoloqic conditions are
favorable.
The drainage area above the forebay dan• is 320 square miles.
There are no stream flow records for the Tazimina River;
however, similar basins in the area indicate a flow of 4.5 cfs
per square mile is a conservative estimate. Thus, the average
annual flow is taken as 1440 cfs for this study. See Appendix A-6.
Two stages for project deve 1 opment are proposed. Stage I
includes all the basic features of the complete project except
that the storage dam is 25 feet 1 ess in height. Stage I I
raises the storage dam 25 feet, adds a second penstock and
increases size of the powerhouse (adding 2-units). St~ge I
active storage capacity provides for assuring a regulated flov1
of 700 cfs.
III-48
MIS08/S2
RESERVOIR
Drainage Area
SIGNIFICANT DATA
TAZIMINA HYDRO PROJECT
STAGE I
Normal Maximum Water Surface Elevation
Minimum Water Surface Elevation
Surface Area-Normal Maximum W.S.
Live Storage
1st Stage Min. Regulated Flow
STORP,GE DAM
Type
Height
Crest Elevation
FOREBAY DAM
Type
Height
Crest Elevation
SPILLWAY
Type
Crest Elevation
Width
Design Discharge
WATER CONVEYANCE
Penstock 11 1 -0 11 Dia., Length
Wall Thickness
POWER PLANT
Capacity
Maximum Gross Head
Type of Turbines
TRANSMISSION LINE
Voltage
Length
Conductor Size
ANNUAL ENERGY
Prime
Secondary
Annual Total Energy
III-49
320 square miles
675
660
3,700 Acres
86,000 Ac-Ft.
700 cfs.
Earthfill
45 Ft.
690
Ea.rthfill
38 Ft.
650
Ungated Side Channel
675
325 Ft.
75,000 cfs.
6,800 Ft.
3/8-inch.
18,000 kW (2 Units)
195 Ft.
Vertical Francis
138 kV
181 miles
795.5 KCM ACSR
78,840 MWh
59,120 MWh
137,960 MWh
Dillingham-Section III
APA02/L
2. Geology
The hydroelectric potential of the Tazimina River has been
under discussion for many years. While the discharge of the
river, and the elevation and storage of the lake system are
substantial, section and design of a suitable damsite has been
difficult because of the width and geology of the valley.
Several sites at and below the outlet of Lower Tazimina Lake
have been suggested. All share the same problem, i.e. unknown
depths of outwash and alluvium covering either one, or both,
abutments.
There have been no pub 1 i shed geo 1 ogi c maps of the I 1 i amna
Quadrangle, although reconnaissance geologic mapping has been
done or extended from other areas to a 11 ow camp 1 et ion of
Beikman 1 s 1978 geologic map of the state of Alaska. A letter
and summary report prepared by James Callahan in 1970 addressed
the prob 1 ems of 1 ocat i ng a feas i b 1 e dams i te on the Lower
Tazimina River. They recommended the Roadhouse site but left
open the possibility of using the lower site since they did
not actually visit it.
The purpose of the geotechnical phase of this investigation
was to exp 1 ore--by shall ow seismic survey--the subsurface
bedrock profile at the so-called 11 lower damsite,11 located
about one-half mile above the main falls of the Tazimina
River. The 11 lower damsite 11 was chosen where bedrock first
begins outcropping in the banks of the river, at a small falls
about four feet in height. The left abutment of the site
rises gently in a series of terraces into the foothills north
of Roadhouse Mountain. The terraces are alluvial in nature
and are composed of sandy gravels. No seismic work was done
on the left abutment; geomorphology, however, suggests that
the terraces probably cap a gently and evenly rising bedrock
profile that varies in depth from ten to fifty feet beneath
the terraces.
It was realized from the outset that the right abutment could
be a prob 1 em area. Thus, the focus of the study was con-
cent rated there. The right abutment is formed by a 1 ong
irregular ridge that bounds the north edge of the Tazimina
River for about two miles above the site. The ridge apparently
formed as a lateral moraine during the waning stages of the
last major glacial advance. It is exposed in a cutback one
mile upstream from the site. The cutback reveals well graded
but poorly bedded outwash gravels throughout the section but
no bedrock. Traversing the ridge southwestward toward the
11 lower damsite,11 occasional exposures of well washed gravels
occur where vegetation is lacking. The ridgetop swings up and
down and a low saddle, perhaps no more than thirty or forty
feet above the river, occurs just upstream of the 11 lower
damsite.11
II I -50
Dillingham-Section III
APA02/L
As the 11 1 ower dams i te 11 is approached, bedrock begins to crop
out in both banks of the river. At the site itself, a more
competent zone of rock has formed a sma 11 fa 11 s confined
between two low ramparts that rise fifteen feet or so above
the river. The bedrock which the river encounters here is a
volcanic breccia of probable lower jurassic age. The unit is
light green to gray with an aphanitic siliceous matrix con-
taining angular volcanic fragments from 5 to 10 mm in size.
The volcanic sequence is exposed in the walls of the stream
gorge from the 11 lower site 11 on down to the main falls and
below. The volcanics display little bedding at the site but
show highly contorted beds in exposures near the main falls.
The unit seems to trend in an approximately north-south sense.
Jointing in the rocks at the site is predominantly east-west
and vertical. Though the rock is well jointed and generally
frost-shattered in outcrop, the unit appears fairly tight.
The bedrock along the river channel rises in vertical walls
approximately ten feet above river level, and forms a bench
which disappears below the glaciofluvial deposits.
Commencing on the bench of bedrock, a 500-foot seismic refrac-
tion line was run northwestward over the low ridge of moraine.
A portable single channel seismograph built by Bison Instruments
was used to measure ground velocities. A twelve pound sledge
hammer was used as an energy source for the first half of the
line and then one-third pound Kine-Stik charges were used to
finish the line.
The seismic data indicate that the right abutment is underlain
by bedrock but at a considerable depth. The overburden has a
seismic velocity of 2000-3000 ft/sec (typical of the sandy
gravels at the surface) with velocities in bedrock ranging
from 10,000-12,000 ft/sec. A surface layer of less compacted
soil from five to fifteen feet in depth has a ve 1 oci ty of
2000 ft/sec. The time-distance graph also indicates a low
velocity zone just west of the river, which could be an old
stream channel or a fractured zone in the bedrock.
Dry potholes, lack of swampy areas, and the coarse nature of
the exposed outwash, a 11 suggest the very pervious nature of
the materal in the right abutment. To avoid potential excessive
leakage and/or eventual piping and destruction of the reservoir,
a low maximum dam height of forty feet is recommended. It
would be critical that a drilling program be carried out to
delineate depth to bedrock prior to final design. Sealing the
entire right abutment is not considered an economic alternative.
Upstream, the Roadhouse site will most probably encounter a
very similar situation; however, a seismic survey should be
carried out there in order to be certain.
III-51
I
(Jl
N
....
'l>
<b .....
!::
c:::
·~ .....
() ::..
<b .....
'l>
<b ....
t::l
E:
'< () .._
<::1.
~
SEISMIC SURVEY-RIGHT ABUTMENT-LOWER DAMSITE-TAZIMINA RIVER
80
{: 60 c:::
<:>
1..>
<b
"' ., ..... :::::
~ 40
·!::
~
·.;:: 20
750-
700-
650-
550-
2.9
•
100
•
X
X
•
8.8 -
....._____ VELOCITY x 100
I
200
distance in feet
T
300
3.1
400
INTERPRETED X-SECTION
2000 ft./ sec..:....
3000 ft. /sec.
1.9
500
PERVIOUS SANDY GRAVELS
. __ /_.......... ;rrm n?l/7 TT/171
/...... ~ /,.,-r11 ~-~ 1 1 1 1 10,000 -12,000 ft. /sec $fi.l/ I/~ Tl I I
I
0
' / "-:"'/ 1' ; I I WELL JOINTED VOLCANIC BRECCIA
I
llJO
I
200
FIGURE m-13
feet
I
300
I
400
r;; ; T ,-~
I
500
Ul llingharn-Section III
APA02/L
The site at the outlet of Lower Tazimina Lake contains morainal
deposits in both abutments and would face even more difficulties
in achieving a good seal.
One last alternative is suggested. It would require a much
more extensive dam but would allow considerably more storage.
The site falls in Section 8 bet~een the third and fourth small
lakes below the outlet of Lower Tazimina Lake. The axis of a
dam at this site would be nearly one-half mile in length.
Although the size of such a project would be considerably
greater, earthfill is readily available in large quantities.
In addition, both abutments would be founded in bedrock and
the height of the dam would be unrestricted by physical condi-
tions. The depth and character of alluvial fill in the valley
would have a direct bearing on the economic feasibility of
such a project. A limited drilling program coupled with a
seismic study would be necessary to fully evaluate its potential.
If the economics of this larger seale project do not make
sense, it is suggested that a subsurface study of the Road-
house site be accomplished and compared to the 11 lower damsite.11
3. Project Arrangement -Stage I
The Tazimina River Project will consist of the following prin-
cipal elements:
a. An earthfi ll forebay dam across the river, founded on
bedrock at river mile 10.44 with an uncontrolled side
channel spillway with a crest at elevation 635.
b. An earthfill storage dam at the mouth of Lower Tazimina
Lake (mile 18) with an uncontrolled spillway with a crest
at elevation 675. The storage provided by the dam would
regulate an average winter flow of 700 cfs. There will
be four 8'-611 diameter pipes penetrating the dam with an
invert elevation of 650. Each pipe will have a Howell-
Bunger type valve on the downstream end for automatic
control of releases. (In Stage II this dam will increase
25 feet in height).
c. The forebay dam at river mile 10. 44 will have two 11'-011
diameter pi pes penetrating the dam with an upstream
invert at elevation 615. The upstream ends would have
trashracks and the downstream ends would have valves.
One pipe valve would be covered with a blind flange and
be installed for future expansion.
d. A power penstock approximately 6800 feet long and 11' -0 11
diameter constructed to convey the water to a powerhouse
located at river mile 9.15. (In Stage II a second penstock
will be added).
II I -53
Dillingham-Section Ill
APA02/L
e. A surface powerhouse containing the turbines, generators
and electrical switchgear and an adjacent switchyard to
contain the transformers, etc., and the transmission line
take-off structure. (Two more units added in Stage II).
f. Other facilities including access road and transmission
line. (In Stage II, a 2nd transmission system is added
for reliability).
4. Hydroelectric Power Production
The powerp 1 ant initially wi 11 have two generators rated at
9,000 kW each, powered by two vertical Francis type turbines
of 13,875 HP each. At full utilization (4-9 MW units) the
Project will produce 111,252 MWh of prime energy and 47,689 MWh
of secondary energy per year.
Net operating head will be 180 feet with the forebay at the
spillway crest level and two units operating.
5. Description of the Project Facilities
The Corps of Engineers in "Interim Report No. 5, Southwestern
Alaska, 1954 11 proposed two plans of development for Tazimina
Lake. The water could be diverted northward by a 17-foot
diameter tunnel 5 miles long into a powerhouse on the south
shore of Lake Clark or diverted southward by a 17-foot diameter
tunnel 11~-miles long into a powerhouse on Iliamna Lake. The
first would operate under an average head of 443 feet and
develop 27,600 kW of prime power. The alternate would operate
under an average head of 606 feet and develop about 37,900 kW
of prime power. Storage for complete regulation would be
obtained by constructing a rock-fill dam 80 feet high and
600 feet long at the Roadhouse Mountain site (river mile 11.6).
No fish facilities or water releases to maintain the excellent
fishery below river mile 9.15 were provided.
The proposed plan of development in this study is to partially
develop the hydroelectric potential of Tazimina Lake in two
stages and maintain or enhance the fishery below the falls.
Two possible storage dam sites were considered; one at the
Roadhouse Mountain site (river mile 11.6) and another at the
outlet of Lower Tazimina Lake (river mile 18). The site at
river mile 18 was selected for cost estimates in this study
because surficial geology and the volume of material required
for the dam appears to be more economically favorable.
II I-54
Dillingham-Section III
APA02/L
Either site would require an extremely long pipeline to take
advantage of the relief and ultimate feasibility provided by
the falls. An alternate to the long pipeline is to create a
fore bay dam near the falls where the water is then conveyed
through a much shorter pipeline to the powerhouse at the base
of the falls. An excellent forebay damsite of limited height
due to geologic conditions exists at river mile 10.44. (See
geologic section, Figure III-13). The forebay dam water
surface would be maintained at near constant level by automatic
releases from the storage dam. This scheme was selected as
being the least costly.
a. Forebay Dam and Spillway
The forebay dam will be an earth-fill dam with an un-
controlled side channel spillway around the right abutment.
The crest of the spillway is set at elevation 635 and the
top of the dam at elevation 650. The dam will have a
maximum height of 38 feet in the river section. The
spillway crest elevation was set at elevation 635 to
provide sufficient cover over the intake to prevent a
vortex forming -permitting air into the penstock. (See
Figure I II -15).
Hydrologic data for the Tazimina Lake basin is included
in Appendix A-6.
The spillway will be 300 feet in width and concrete lined
where suitable bedrock is not encountered in the excavation.
No storage effect is considered available at this site.
Storage will be provided in the upper dam.
b. Storage Dam
The storage dam will be an earth-fill dam with an un-
controlled spillway in a saddle approximately 1800 feet
north of the dam at the mouth of Lower Tazimina Lake. A
concrete agee type weir will be placed across the saddle
at crest elevation 675. The main dam and possibly two
small dikes south of the main dam will have a crest at
elevation 690. The spillway crest elevation was set to
provide sufficient storage to maintain 700 cfs flow to
the fore bay dam during periods of 1 ow f1 ow. (See
Figure III-15).
Erosion control in the spillway channel below the weir
will be provided by removing all organic materials from
the channel and a series of rock barrages placed laterally
across the channe 1 to trap sediments and reduce the
velocity of the water. Rock Gabions will be placed along
the downstream toe of weir.
III-55
Dillingham-Section III
APA02/L
The dam and spillway will be designed for increasing the
height 25 feet; the maximum height believed to be econom-
ically feasible at this site if geologically favorable.
The spillway will be raised accordingly and gated. The
Stage II development will provide an active storage of
247,000 acre-feet or an estimated average regulated flow
of 1,008 cfs.
c. Intake Structures
Forebay Dam-the forebay dam will be penetrated with two
11'-0 11 diameter pipes with an upstream bell mouth to
reduce entrance losses. A trashrack will be installed
over each of the entrances. The downstream ends of each
pipe will be provided with a gate valve. One pipe will
be used to connect with the power penstock to the power-
house. The second pipe will be used for the second stage
of development. It will have a blind flange connected to
the downstream end of the valve in the interim.
Storage Dam -This dam will be penetrated by four 8' -6 11
diameter pipes each with a bell mouth entrance and stop-
log guides on the upstream end. Two pipes will have a
blind flange on each at the downstream end for future
expansion and the other two pipes will have Howell-Bunger
type valves for water releases from the storage provided.
These valves will be controlled by a float switch at the
forebay dam to maintain a water surface at elevation 635.
d. Penstock
An initial partly exposed ll'-0 11 diameter penstock with a
total length of 6800 feet and 3/8'' wall thickness will
convey the water from the forebay dam to the powerhouse.
The penstock will gradually leave the streambed over to
the left abutment and follow a natural gully to a point
along the river just above the powerhouse. The penstock
will be anchored at this point and dropped down the steep
river bank to an anchor block before bifurcating and
entering the powerhouse.
The penstock will be located to allow easy install:1tion
of the other penstock required for future expans i ·)n.
e. Powerhouse
The powerhouse will have a reinforced concrete substructure
with a prefabricated metal type insulated superstructure
above the generator floor.
I II -56
Dillingham -Section III
APA02/L
The two reaction turbines will be set vertically. Each
turbine will be rated to produce at least 13,875 HP when
operating at a net head of 180 feet and 700 cfs flow.
Stage I will include 2-9,000 kW generating units. The
rationale vf this initial plant factor of about 51.5% is
described in Appendix A page 61.
The ultimate development of the Project proposes the
installation of four 9 MW units corresponding to a similar
plant factor of 51.5%. With four units installed, the
plant would still have some peaking capacity with one
unit out of service.
The first stage development proposes the installation of
two of the 9 MW units; thus maintaining like units in the
desired ultimate installation.
The generators and turbines will be connected by a vertical
drive shaft. Each generator will be rated at 11,250 kVA
at 60°C temperature rise, 0. 8 powerfactor and have a
continuous overload rating of 15 per cent.
f. Transmission Lines
A substation at the powerhouse will transform the generating
voltage of 13.8 kV to the transmission voltage of 138 kV.
An overhead line (795.5 kCM ACSR conductor) will follow
the north shore of Iliamna Lake to Igiugik and then
roughly parallel the Kvichak River to Levelock. Total
length of this section is approximately 89 miles. Near
Levelock a separate branch will supply power to a sub-
station near Naknek, where the voltage is stepped down
via a 10 MVA transformer. This section is approximately
32 miles long and crosses the Kvichak River. The other
branch continues for approximately 60 miles to a substation
near Dillingham, where the voltage is stepped down to the
local distribution voltage. Stage II would add a second
line for reliability.
g. Access Road
Approximately 7 miles of road will be required from the
existing road along the Newhalen River to the powerhouse
site. An additional 8 miles of project roads will be
required from the powerhouse to the forebay dam and the
storage dam. Construction materials for a gravel road
are abundant throughout the length of the roadways required.
III-57
Dillingham -Section III
APA02/L
Materials, equipment and supplies for the project and
construction equipment can be barged up the Kvichak River
into Iliamna Lake during early summer and off loaded at
the village of Iliamna. From Iliamna, access would be by
existing and project roads.
III -58
I
I
I
I
t r£1 ~ p., ~ H ~ H ~ 8 v ~~ ow Ro:: N:::> <!) u...
....... ....... .......
I
0\
0
45' TO
....,_. .. I HOWELL BUNG~,~
I VALVES ~ :;•,-,
.
.........
;,~~ :;_:R ROCK
I/4"ALUMI~I
.ALLOY
GoMPACfEO
SAN 0 8 GRAVEL(_
11'-0" PIPE (TWO)
INIIERT ELEV. 615
.... ..... ......... ..... ..... ..... ... .................... , .....
CUT-OFF WALL
FOREBAY DAM SECTION
COMPACTED
SAND 8 GRAVEL
........ f.l.O_V!___ 8'-6" DIA. PIPE (FOUR)
INVERT ELEV. 650
Wh~;;-;-
STORAGE DAM SECTION
(WifH PROVISION FOR RAISING 25')
ROCK
SHEEf PILE CUT-OFF
ALASKA POWER AUTHORITY
TAZIMINA LAKE
'CIGUPr '"":-15
I
0'1
I-'
....
IU
IU ....
!
z
0 ....
~
IU
..J
IU
ARE A (ACRES X 1000)
700t0 • 8 7 • !5 4 3 2 1 0
690
680
67
6
650
6400 50 100 150 200
CAPACITY(ACRE-FEET X 1000)
250 300 350 40C
TAZIMINA RIVER
AREA-CAPACITY CURVE
(ROADHOUSE MOUNTAIN SITE)
FIGURE :ni-16
Dillingham -Section III
APA02/L
6. Project Construction -Stage I
The project construction will be carried out by separate
supply and civil works construction contracts. One or more
general contractors will be engaged to build the project.
a. First Year
The terrain is suitable for the contractor to move
crawler type equipment directly to the powerhouse and
dam sites prior to completing the access road. The
contractor can begin stripping the overburden and
spillway excavation at the dam sites simultaneously
with the access road construction.
The contractor should be ready to commence bui 1 ding a
cellular sheet pile cofferdam to permit dewatering of
the left half of the stream channel at each dam site by
July. Upon completion of the cofferdams, the contractor
can excavate for the cutoff wall inside the enclosure,
start the dam fill and place the pipes, trashracks and
valves on the pipes passing through the dam. The left
half of the dam embankment should be completed to the
point where the ce 11 ul ar cofferdam can be removed in
June of the second year to divert the river flow through
the pipes.
While the dam construction is taking place, the con-
tractor can be excavating and placing first stage
concrete for the powerhouse and preparing the penstock
route to line and grade to readily receive the penstock
during the second year.
It is expected that work will be curtailed through the
winter months of November through April with the exception
of the transmission line contractor.
b. Second Year
The contractor will remove the cellular cofferdam from
the 1 eft bank to the right bank of the river at both
dam sites and divert the flow through the pipes.
By the end of the construction season of the second
year, the contractor wi 11 have comp 1 eted both dams,
spillways, intake works, penstock and erection of the
prefabricated metal superstructure.
I II -62
Dillingham-Section III
APA02/L
During the winter season he can complete the installation
of auxiliary electrical and mechanical equipment including
the overhead travelling crane.
c. Third Year
The turbines, generators and auxiliary equipment should
arrive on the site by July 1 and the contractor can
immediately commence the installation of the turbines,
generators, etc. under the supervision of manufacturer•s
representatives.
The contractor will remove most of his heavy equipment on
the outgoing barge that delivered the powerhouse equipment.
The contractor will complete the installation of the
electro-mechanical equipment in October and begin testing
the units and making necessary adjustments and corrections
to bring the first unit on line by the end of the year.
d. Fourth Year
The contractor will have camp 1 eted the testing of the
second unit by the first of February and complete clean-up
work and have all equipment and materials removed from
the site by the end of February. The remaining equipment
will be very limited and may be flown out from the Iliamna
airport.
7. Project Construction -Stage II
If geological conditions permit the construction of Stage II,
the following principal features will be constructed:
a. The reservoir storage dam will be raised 25 feet to
Elevation 715.
b. Install another power penstock approximately 6,800 feet
long and 11 1 -011 diameter between the forebay dam and the
powerhouse.
c. Expand the powerhouse and install two additional 9,000 kW
turbine generator units.
III-63
Dillingham-Section Ill
APA11/D1
7. COST ESTIMATES
TAZIMINA -STAGE I
2 x 9 MW
PRELIMINARY COST ESTIMATE
Capital Expenditures
FERC
ACCT.
by Year in $1,000 -(1979-Base)
331
332
333
ITEM
Hydraulic Production Plant
Structures and Improvements
Reservoirs, Dams & Waterways
.1 Dams
.2 Spillway
. 3 Penstock
Waterwheels, Turbines, &
Generators
334 Accessory Electrical Equipment
335
336
352
353
354
356
Misc. Plant Equipment
Roads
Transmission Plant
Structures & Improvements
Station Equipment
Poles & Fixtures (181 miles,
138 kV I 30)
Overhead Conductors & Devices
General Plant
390 Structures & Improvements
381/389 Miscellaneous
Direct Constr. Cost
Contingencies
On Underground Work (25%)
All Other Work (10%)
Engineering 15% of Direct
Constr. Cost
Total Construction
Allowance for Inflation ( 8% per
year)
Interest during Construction 9%
Total Investment
Total Project Cost in 1979 -
$( 1, 000) used in economic evaluation
Inflated at 8% per Year to 1985
and with interest during
construction results in
III-64
1982 1983 1984
1,313
1,200
440
2,953
628
44
443
4,068
1,057
461
5,586
1,000
1,312
2,500
3,500
500
50
6,000
100
14,962
328
1,365
2,244
18,899
6,813
2,775
28,487
50,820
77,659
1,000
2,500
3,500
250
1,185
6,000
5,900
50
20,385
2,039
3,058
25,482
11,959
6£145
43,586
MISC09/N5
TAZIMINA LAKE
PRODUCTION PLANT
DETAILED COST ESTIMATE
FERC UNIT TOTAL
ACCT. ITEM QUANTITY PRICE PR CE
331 Structures and Improvements
.1 Powerhouse
Excavation (common) 1,000 c.y. 12.00 12,000
Excavation, Rock 1,500 c.y. 40.00 60,000
Concrete -Reinforced 1,200 c.y. 750.00 900,000
Prefabricated Building L. s. 175,000
Structural Steel 42,000 1 b. 1. 50 63,000
Water & Sewerage L. S. 70,000
HVAC L. s. 140,000
Mobilization L. s. 580,000
Total Account 331 $2,000,000
332 Reservoirs, Dams and Waterways
.1 Dams
-:l:lForebay Dam
Foundation Excavation 5,000 c.y. 8.00 40,000
Embankment 80,000 c.y. 12.00 960,000
Intake Facilities L. S. 200,000
Cofferdams L. s. 200,000
.12 Reservoir Dam
Foundation Excavation 2,000 c.y. 8.00 16,000
Embankment 38,000 c.y. 12.00 456,000
Cofferdam 200,000
Control Works 353,000
.13 Mobilization, Dams 200,000
Subtotal Dams $2,625,000
.2 Spillway
.21 Forebay Dam
Excavation, (Common) 30,000 c.y. 8.00 240,000
Concrete 800 c.y. 600.00 480,000
Clearing & Matting L. s. 28,000
. 22 Reservoir Dam
Excavation 20,000 c.y. 8.00 160,000
Concrete 500 c.y. 600.00 3001000
Subtotal Spillways $1,200,000
II I-65
MISC09/N6
FERC
ACCT.
333
334
335
336
TAZIMINA LAKE
PRODUCTION PLANT
DETAILED COST ESTIMATE, continued
.3 Penstock
Pipe
ITEM
Concrete Anchors
Excavation
Penstock Mobilization
Subtotal Penstock
Total Account 332
Waterwheels, Turbines and Generators
.1 Turbines, 13,900 H.P
. 2 Generators, 9,000 kW
. 3 Appurtenances
. 4 Mobilization
Total Account 333
Accessory Electrical Equipment
Miscellaneous Plant Equipment
(Compressed Air, Fire Protection,
40-Ton Crane)
Roads Railroads and Bridges
. 1 Roads
Mobilization
Total Account 336
TOTAL PRODUCTION PLANT
QUANTITY
2,862,800 lbs.
200 c.y.
25,000 c.y.
L.S.
UNIT
PRICE
1. 50
600.00
8.00
2 ea .
2 ea .
L.S .
1,300,000.00
1,300,000.00
L.S.
L.S.
15 mi . 25,000.00
III-66
TOTAL
PRICE
4,294,200
120,000
200,000
385,800
$5,000,000
$8,825,000
2,600,000
2,600,000
1,000,000
800,000
$7,000,000
$ 500,000
$ 250,000
375,000
65,000
$ 440,000
lli,015,000
MISC09/N7
FERC
ACCT.
352
353
354
356
TAZIMINA LAKE
TRANSMISSION PLANT
DETAILED COST ESTIMATE
ITEM QUANTITY
Structures and Improvements
. 1 Concrete Foundations L.S .
.2 Substation Structure L. s.
Total Account 352
Station Equipment
.1 Transformer 20 MVA
13. 8 kV /138kV 1 ea.
. 2 Transformer 20 MVA
138 kV/12.5 kV 2 ea.
. 3 Circuit Breaker, 138 kV 3 ea.
. 4 Potential Transformers
138 kV 3 ea.
. 5 Disconnects, 138 kV 3 ea.
.6 Lightning Arrestors, 138 kV 9 ea.
.8 Busbar, Insulators, Wiring, etc. L.S.
Total Account 353
Poles and Fixtures
.1 Right of Way Clearing 181 mi.
.2 Structures, TX 1,000 ea .
. 3 Hardware L.S.
Total Account 354
Overhead Conductors and Devices
.1 Conductor 795.5 KCM ACSR 3 x 181 mi.
. 2 Disconnect 138 kV 3 ea.
Total Account 356
T
TOTAL TRANSMISSION PLANT
I II -67
UNIT TOTAL
PRICE PRICE
20,000
30,000
$ 50,000
2oo,ooq.oo 200,000
200,000.00 400,000
80,000.00 240,000
6,000.00 18,000
10,000.00 30,000
6,000.00 54,000
253,000
$1,185,000
5,000.00 905,000
9,000.00 9,000,000
2,095,000
$12,000,000
10,700.00 5,810,000
30,000.00 90,000
$5,900,000
$19,135,000
MISC09/N8
FERC
ACCT.
390
391/
TAZIMINA LAKE
GENERAL PLANT
DETAILED COST ESTIMATE
QUANTITY
Structures and Improvements
.1 Operator 1 s Cottage L. S.
Total Account 390
UNIT
PRICE
TOTAL
PRICE
100,000
$ 100,000
399 Miscellaneous
.1 Office Furniture and Equipment
.2 Stores Equipment
.3 Communication Equipment
Total Accounts 391/399
TOTAL GENERAL PLANT
DIRECT CONSTRUCTION COST
L.S. 8,000
L.S. 10,000
L.S. 32,000
$ 50.000
$ 150 000
$38,300,000
I II-68
Dillingham -Section I II
APA11/D2
TAZIMINA-STAGE II
2 X 9 MW
PRELIMINARY COST ESTIMATE
Capital Expenditures
FERC
ACCT.
by Year in $1,000 -(1979-Base)
ITEM
Hydraulic Production Plant
331 Structures and Improvements
332 Reservoirs, Dams & Waterways
.1 Dams
. 2 Penstock
333 Waterwheels, Turbines, &
Generators
334 Accessory Electrical Equipment
335 Misc. Plant Equipment
Transmission Plant
354 Poles & Fixtures (181 miles,
138 kV I 30)
356 Overhead Conductors & Devices
Direct Constr. Cost
Contingencies (20%)
Engineering 15% of Direct
Constr. Cost
Total Construction
Allowance for inflation
8% per year to 1984 and
4% thereafter
Interest during construction at 9%
Total Investment
Total Project Cost in 1979
($1 ,000) used in economic evaluation
Inflated to 1994 and including
interest during construction
results in
III-69
1991 1992 1993
895
2,500
3,395
679
509
4,583
4,309
800
9,692
2,500
3,500
50
6,000
---
12,050
2,410
1,807
16,267
16,493
2,948
35,684
45,774
99,588
2,000
3,500
250
6,000
-~900
17,650
3,530
__.S_647
23,827
25,909
4,476
54,212
I--<
I--<
'
-...J
0
L_
Dillingham -Section
APA11/M2
Item
Mobi I ization
Access Road
Dams
Spillways
Penstock
Powerhouse
Year
Quarter
Equipment Installation
Transmission & Substations
Demob iIi zation
-----
1
CONSTRUCTION SCHEDULE
First Second
2 3 4 1 2 3
I
~
L I
I I
-__ L_ _____ LJ
4
Third 4th
1 2 3 4 1
v /// ///1
~ -
First Unit
Second Unit
ALASKA POWER AUTHORITY
TAZIMINA RIVER PROJECT
CONSTRUCTION SCHEDULE
FIGURE m-17
Dillingham -Section III
APA02/L
8. Environmental and Institutional Concerns
a. Hydrodevelopment
No major conflicts with the moose, caribou and brown bear
populations are anticipated, other than some s 1 i ght
disturbance of habitat during construction. Some loss of
habitat would occur due to inundation of low lands behind
the dam.
There are no known archaeological sites in the area that
would be inundated. However, to be certain that no sites
are disturbed an archaeological survey should be conducted
prior to construction.
The fishery aspects have to be more closely investigated.
Lower Tazimina Lake supports populations of typical
Alaskan fish species such as trout, Dolly Varden, grayling
and char. A large waterfall separates the lake from the
Tazimina River. This waterfall prevents any anadromous
fish from entering the lake. Below the falls there is a
large population of spawning sockeye salmon. Data provided
by the Alaska Department of Fish and Game (see Appendix D-1)
show a sockeye salmon escapement in Tazimina River averaging
160,000 fish. Tazimina River also supports populations
of rainbow trout, grayling and char. While the project
does not appear to involve any major fishery problems in
the 1 ake, some potentia 1 prob 1 ems may occur be 1 ow the
power plant due to nitrogen saturation and alterations of
the flow regime. These potentia 1 downstream fishery
problems and enhancement possibilities should be studied
during the course of the detailed environmental analysis.
b. Transmission
The transmission corridor will cross and several small
streams as well as the Kvichak River near Levelock. As
there is a possibility that the transmission line construc-
tion could introduce sediments into these streams, a
study should be conducted during the detailed environmental
assessment to determine the optimum methods of insuring
that anadromous fish streams are protected. The area
presently has no road access. Transmission line construction
is therefore planned via helicopter and/or ATVs.
Use of single wire ground return transmission system,
would minimize visual impact.
III-71
Dillingham-Section III
APA02/L
c. Institutional Constraints
The Tazimina project and most of the transmission corridor
are located in a wilderness study area which has been
made subject to a federa 1 emergency wi thdrawa 1 by the
Federal Land Policy Management Act of November 16, 1978,
Section 204e.
Native land clims have been filed however, on most of the
right-of-ways required for the hydroproject development.
Most of the land claims have not been conveyed yet, but
are in various stages of processing.
Conveyance of this land extinquishes all former claims,
such as power site withdrawals or classifications, unless
they qualify as an active Federal Installation under
Section 3(e) of the Alaska Native Claims Settlement Act.
This qualification has to be filed for by an federal
agency.
The Tazimina project is located within power site
classification 463, which withdraws 11 every smallest legal
subdivision adjacent to Taz imina River and Lower and
Upper Tazimina Lakes, below 720 feet above sea level 11
•
It has not been determined in the course of this study
whether this c 1 ass ifi cation qua 1 ifi es under the above
mentioned Section 3(e). The following lists the major
facilities of the project and the land status at the time
of investigation (January 1980).
(1) Powerhouse and Penstock: Located in T3S, R32W,
Sect 1 on 24. Conveyed to the I 1 i amna Village Ltd
January 1980.
(2) Forbay Dam: Located in T3S, R31W, Section 19.
(3)
(4)
(5)
(6)
Claimed as a regional withdrawal.
Reservoir Dam: Located in T2S, R32W, Section 35.
Claimed by Nondalton Ltd.
Lower Tazimina Lake Reservoir: Overlapping claims of
Nondalton Ltd., and regional withdrawals.
Tazimina River between Lower Lake and Forebay Dam:
Overlapping claims of Iliamna Ltd., and regional
withdrawals.
Transmission Line Route: Since no firm routing has
been establ1shed 1n this study, the status along the
anticipated right-of-way is only briefly addressed
here:
II I -72
Dillingham-Section III
APA02/L
• From the powerhouse a 1 ong the Taz imina and
Newhalen River and Iliamna Lake to R35W located
on Iliamna Ltd. claimed land.
• From R36W to R38W located on proposed wildlife
refuge.
• From R39W to R41W located on Igiugig Village
claimed land.
1 From R42W to R46W located on Levelock Village
selected land.
• From Levelock to Dillingham located on Portage
Creek/Ekwok Village selected land.
• From Levelock to Naknek located on Levelock/Portage
Creek selected land.
III-73
IV. ECONOMIC FEASIBILITY ANALYSIS
Dillingham-Section IV
APA013/F
IV. ECONOMIC FEASIBILITY ANALYSIS
A. THE CHOICE OF METHODS AND ALTERNATES
The various analyses performed represent on attempt to find the
development plan resulting in the lowest cost for electric energy.
Continued use of diesel generation has been used as the base for
comparisons.
The economic evaluations have been presented in the form of busbar
power cost studies for a 20 year study period. It is realized that
the choice of this study period will penalize possible hydro-
developments which have a much longer economic life than 20 years.
However, with the uncertainties introduced in regard to 1 oad
forecasting as well as cost and technical developments, it is
anticipated that a 20 year period will allow a realistic feasibility
evaluation. Inflation rates have been assumed at 8% per year to
1984 and at 4% per year thereafter. Fuel oil costs have been
escalated at 2% above the general inflation rates. Sensitivity to
the cost of money has been investigated by establishing power costs
for interest rates of 2, 5, 7 and 9%. The low interest rates would
be most likely to materialize for REA financed projects, while the
higher rates represent the rates for bonds or institutional loans.
A detailed 1 i sting of parameters and assumptions used for this
economic analysis is provided in Appendix C.
The evaluated alternates reflect two different routes of development:
1. Independent systems in the various communities.
2. Intertied regional systems.
In case of independent system development the only available electric
power source will be in most cases diesel generation. Supplementary
use of wind generation is possible but is not deemed feasible at
this time. Utilization of wind energy to replace diesel fuel has
been calculated to be economical only if diesel fuel would at least
cost between $3.00 to $5.00 per gallon (See Section V for details).
The independent system scenarios have been evaluated for the low
load growth cases only, since it is not expected that the historical
growth rate will be maintained with the rapidly increasing costs of
electric energy under diesel generation.
Dillingham is located approximately 51 miles from the Lake Elva
hydrosite and 65 miles from Grant Lake. It is therefore conceivable
that either or both potentials can be developed by Nushagak Electric
Cooperative (NEC) -the operating utility in Dillingham. These
hydrosites have therefore been evaluated separately for the Dillingham
system.
IV-1
Dillingham-Section IV
APA013/F
The Tazimina hydrosite development is judged to be too costly and
large a project to be undertaken by any of the existing utilities
or individual communities. It has therefore been assessed only for
an interconnected system which includes 13 small communities in
addition to the population centers of Dillingham and Naknek.
B. ALTERNATE DEVELOPMENT PLANS
This part will briefy describe the various plans evaluated.
The alternate development plans provide for the equipment installa-
tions required to maintain a reliable electric power supply to the
communities involved. Criteria used are explained with the various
alternative plans.
AL HRNAH
!JlENTl£ICATION
1-A
3 A'
4-A
s-A
S-B
G-A
6-B
7-A
7-B
B-A
8-8
9-A
9-B
10-A
lO-B
SERVICE AREA METHOD OF GENERATION -!:.Q~.D GROWTH
Dillingham-Diesel -Low Load
Naknek Diesel -Low Load
10 Villages-Local Diesel -
low load
Dillingham/Naknek/10 Villages-
Central Diesel -Low Load
Dillingham Elva -Low Load
Dillingham-Elva High Load
Dillingham-Grant Low LOad
Dillingham Grant-High load
Oillinghma Elva+ Grant Low Load
Oillingnam-Elva+ Grant
High Load
Dilllngham/Naknek/10 Villages
Elva + Grant -Low Load
Oillingham/Naknek/10 Villages
Elva + Grant -High Load
lntertied System (15 Communities)
Tazimina -Low Load
lntertied System (15 Communities)
Tazimina-High Load
lntertied Svstem (15 Communities)
Elva • Taiimina -Low load
!ntertied System (15 Communities)
Elva • Tazimina -High load
• Representative for Iliamna, Newhalen, Nondalton also.
IV-2
Dillingham-Section IV
APA013/F
Figure IV-1 to IV-6 illustrate the relationship between projected
power and energy requirements and the capacity of various hydro-
electric projects. Existing diesel capacity has not been included
in these graphs, to allow a better assessment of the hydrocapacity
in relation to load requirements.
1-A. Dillingham System-Diesel -Low Load Growth
Continuous use of diesel generation with plant additions of
a 1,000 kW unit each in 1980, 1990 and 1999 has been assumed
for this case. Only low load growth has been evaluated.
2-A. Naknek System -Diesel -Low Load Growth
Conti~ous use of diesel generation with plant additions of
1,000 kW units each in 1984 and 1993 has been assumed. Low
load growth only has been evaluated.
3-A. 10 Small Communities -Diesel -Low Load Growth
Continuation or implementation of local diesel generation
for the 10 communities in the Nushagak/Kvichak area is
investigated in this case. These villages are within
economic distance from the 1 arger centra 1 systems in
Dillingham and Naknek (See Appendix A-4). The summation of
all installed units and addition of new capacity in 100 kW
increments has been used to simplify the evaluation. The
calculated power costs should not be used for individual
communities, but they are considered to represent a valid
base to be used for comparisons with other alternatives.
Again, only low load growth has been evaluated.
4-A. Dillingham/Naknek/10 Villages -Diesel -Low Load Growth
The 10 communities addressed in alternate 3-A are assumed
to be connected to the 1 arger systems in Di 11 i ngham or
Naknek by single wire ground return transmission lines.
The Dillingham and Naknek systems are not connected by a
transmission line in this case, since generating efficiencies
and fuel costs are approximately the same for both systems.
A 11 energy required is supp 1 i ed by the centra 1 di ese 1
generators, but standby generation is maintained in every
community. The cost for the transmission tie lines have
been added as a lump sum in 1981. Low load growth has been
assumed. A comparison with Alternate 3-A (local generation)
will illustrate the difference in fuel efficiency performance
between large generating units (~1000 kW) and smaller ones
(~500 W) as well as fuel cost in the population centers
compared to remote communities.
IV-3
Dillingham-Section IV
APA013/F
5-A/B Dillingham System Lake Elva-High and Low Load Growth
Lake Elva development by 1983 has been assumed. Under
low load conditions (5-A) additional diesel units at 1000 kW
each are then required in 1980 and 1990. Investments
required to maintain firm capacity have been determined by
assuming the hydroplant or its transmission line not
operational. Electric energy generation by diesel engines
drops to 2% of the tota 1 requirements in 1983 and then
slowly increases to 54% in 2000. In case of high load
growth (5-B) additional diesel units have to be installed
in 1980, 1988, 1991, and 1994. The diesel generated part
of the energy requirements grows from 29% in 1983 to 84% in
2000. Average annua 1 energy has been used for the Lake
Elva project for this evaluation.
6-A/B Dillingham System-Grant Lake -High and Low Load Growth
Grant Lake has been assumed to be operational in 1985. For
approximately 5 years this project will produce sufficient
energy to supply all the system demands in the low load
growth case. From 1990 on d i ese 1 generation has to be
supplemented. In the high load growth case some diesel
generation is required at all times.
7-A/B Dillingham System with Lake Elva and Grant Lake
With Grant Lake in addition to Lake Elva operational in
1985, diesel generation is not needed during the study
period in the low load (7-A) growth case. Additional
generating units are not required except for the 1980
addition of 1000 kW. Assuming the high load (7-B) scenario,
diesel generation has to be resumed in 1990 to supply peak
demand. Additional diesel capacity has to be installed in
1980, 1992 and 1997.
The following graphs (Figures IV-1 & IV-2) illustrate
energy and capacity available from Lake Elva and Grant Lake
in comparison to the system requirements.
IV-4
I 000 ..-------~----~---,.-----------~------------------------·---------------r----
9001-------------
a::
UJ
!l
. -----------
800 ,_____ __ ----~------+------------~-------------+-------------------------+
700
600~---------+--------------+--------------~------------~
500~---------------+----------------+----------------~------------
400 ~-----------------+---------------+---------------+-----------<
300 1-----------------+-------------+-------------------+----------------11
200~--------------+-----------.----+---------------~-----~---------~-----
!001-----
90~------------~-------------+-------------------~------------------------------
80 ~--~--------+---------------+------------+-------------i
70~----------+--------------+------------------~-----
60~-------------+--------------+----------~~-----------------------
50~-----------+----------·-+----------------+r---------------
30~--------------+-------------+-------------1+!------------... 1
20~-----------~--------------~-----------------+
~ ~~~-----------------+------------+-----------------HIGH~ANo--·--8l=========t=========t===----==~~~~==~~ 7~---------+-------------+~-~--~-------+~-------------~
6~----------4-----~----=-~~-----------~--------------
51--------------+~-~~~-----r-------------+-------------·---+
4~--------~---~~~~~~~~~~~~~~~~~~~~=L=O=W~D~E~M~A~ND~~~
~~~-------~~-~----~--------~~=-~~~~~~~~~-t~~-~-~~-=-~-~-~-~~-~~=~-
'~DIESEL
2 ~------=---F--------------+--=L::.:.A.:.:.K.:.:::E:.-=ELVA a GRANT LAKE ----------------
LAKE
ELVA i
I ---t-·---t----l----+---r--+---+--+---1-----+----+----+---+----+------+----+----+---+--~
1980 1985 1990 1995 2000
IV-5
DILLINGHAM
HYDROELECTRIC POWER POTENTIAL a CAPACITY BALANCE
1980-2000
FIGURE TIL -I
1000
900
800
700
600
500
400
300
200
100
90
80
70
60
50
40
0
0 Q 30
X
J:
!J: 20
:::E
>-(,!) a:
UJ
--
• .:~••IRE.~~
ANN ~AL ENERGY _, ~
/AVAIL 'ABLE FROM HYDRO ~ ~
I~ ~ 1 mN cu:;rnliREM.ENTS
z
UJ 10
_/ ____..,. ~
9 """""""'
_,.,....
8 ~
~ 7
6
,-_,.,..,..,-\
5
4
3
2
I
1980
-~
-~ ,_.
LAKE
ELVA
' FIRM
EN ERG~
1985
*AT DISTRIBUTION BUS
(TRANSMISSION LOSSES 3.5%)
TV-6
LAKE ELVA a GRANT L KE
FIRM EHf:R~
1990
---
1995 2000
DILLINGHAM
HYDROELECTRIC POWER POTENTIAL
8 ENERGY BALANCE
1980-2000
FIGURE TIL-2
Dillingham-Section IV
APA013/F
8-A/B Dillingham/Naknek/10 Villages with Lake Elva and Grant Lake
Here it is assumed that the Nushagak/Kvichak communities
(See Alternate 4-A) are i ntert i ed with Di 11 i ngham and
Naknek. The interconnection between the Di 11 i ngham and
Naknek systems is assumed as a 138 kV, 3 phase transmission
(92 miles), which is installed in 1984.
In either the high (8-B) or the low (8-A) load case diesel
generation is necessary to provide 35 to 54% of the required
energy in 1985. Additional units are required in 1980,
1984, 1990, 1993 and 1999 for the low load growth and in
1980, 1982, 1989, 1992, 1995 and 1998 for the high load
growth case.
The following graphs (Figures IV-3 & IV-4) show the capacity
and energy balance for the hydro projects in comparison to
the system requirements.
IV-7
900
800
700 .v ...
500
400
300
2"" ,..,..
~ -80
7..,
60
50
,,..
'"'
30
20
10 -EXISTING
i 'DIESEL...,-
6 ~
:s .......
4
3
2
I
1980
r-----------------j TAZlMIHA S' .G£ 1 & 2
I CAPACITY (W/0 ELVA 8r GRANT)
I I ! --,a
.. T~ZIMfNA STAGE I -
-_-....J HIGH""
:c~ ~
I 8r GRANT)
I ..,. ~
~
l1
I
:
r; GRANT LAKE 8r LAKE:
CAPACITY
I
I
I
I
I
I
LAKE I
ELVA I
CAPACITY I
I
1985 I He>
IV-8
LOW-~j A'•m
ELVA
I
1995 2000
DILLINGHAM/ NAKNEK /JO VILLAGES
HYDROELECTRIC POWER POTENTIAL
& CAPACITY BALANCE
1980-2000
FIGURE :CZ:-3
0
0
0
>-(!)
a::
w z w
0
00
100
900
800
7
6
5
4
0~
00
00
300
2 ~au
~
80
70
60
50
40
30
20
10
9
8
7
6
5
4
3
2
I
--~--
-----
--
--
TAZIMINA STAGE 1 8r 2
TAZ IMINA STAGE 1 FIRM ENERGY*(W/0 ELVA -/ I--FIRM ENERGY*(W/0 ELVA & GRANT)
& GRANT) [ ·-r-·-
f i ~
l ~
\ ,--:tl~c.-~
~ ~ II 'A ,c.-.r. _, ~
~\..OW ~ REOUIREI'\\ENiS
~ I
I
I
'I GRANT LAKE a-LAKE ELVA
I FIRM ENERGY*
I
I
(I
rr
rr
LAKE
ELVA I
FIRM I
ENERGY* I
I
I
II
I
I
I
I
,l
1980 1985 1990 1995 2000
* AT DISTRIBUTION BUS
(TRANSMISSION LOSSES 3.5%)
lV-Y
DILLINGHAM/NAKNE K/10 VILLAGES
HYDROELECTRIC POWER POTENTIAL
8r ENERGY BALANCE
1980-2000
FIGURE ::nz::-4
Dillingham -Section IV
APA013/F
9-A/B Intertied System (15 Communities) -Lake Tazimina
Development of Lake Tazimina only is considered in this
alternate. The communities of Iliamna, Newhalen and Nondalton
have been included in the evaluation due to their location
close to the project. It has been assumed that these three
communities are intertied on the distribution level as
proposed in the system planning study for the Iliamna/Nawhalen
Cooperative. Connection to the Dillingham/Naknek systems
is included as a 138 kV, 39 transmission line with Single
Wire Ground Return 1 i nes i ntertyi ng the 10 vi 11 ages to
Dillingham and Naknek.
Di ese 1 generation is not required throughout the study
period for the 1 ow 1 oad case (9-A) once this project is
operational. Standby capacity requirements make the
installation of additional diesel units in 1980, 1990, 1993
and 1998 necessary. The high load scenario (9-8) requires
implementation of Stage II of the Tazimina development in
1992 and installation of diesel units in 1980, 1983, 1987,
and 1990 to assure firm capacity. Diesel generators have
to be operated to supply system requirements from 1996 on.
Early excess of hydro capacity could be utilized in form of
electric heat. Appendix A-5 evaluates the possible bene-
fits of utility installed and controlled electric heat for
residential consumers.
The following graphs (Figure IV-5 & IV-6) show capacity and
energy balances for this scenario.
IV-10
100
900
800
7
0
00
0::
w
3::
0 a.
6
!5
4
OG
00
00
00
IV\
~~ 2
~
80
70
60
50
40
30
20
10
9
"' t
6
5
4
3
2
I
EXISTING
DIESEL
CAPACITY ...,..,
Ill"""
,_.
1980
---
TAZ IMINA CAPACITY t\IGI"I oE.M~~ STAGE 1 8r 2 ------~ TAZIMINA CAPACITY
~ LOW OEMAND ---
1985 1990 1995 2000
I NTERTIED SYSTEM
{ 15 COMMUNITIES l
CAPACITY BALANCE
WITH TAZIMINA HYDROELECTRIC POWER
1980-2000
TV-11 FIGURE nz:-5
0
0
100
90
80
7
0
00
6
!5
00
0
0
Q
X
I
:3:
~
>-
l9 ex:
w z
w
00
4 00
3 00
'""' ~v 2
/
1-TAZIMINA STAGE I
FIRM ENERGY*
90 I
80 I
70 \
~ _,..,-
60 ~ !50 ~ 40
30 ~ -~ ::.------
20
10
9
8
7
6
5
4
3
2
I
1980 198!5
* AT DISTRIBTION BUS
(TRANSMISSION LOSSES 3.5%)
T .....,_ -~
1990
·----
I
TAZIMINA STAGE I a 2
FIRM ENE~~~·\t,g_UIREMENTS
----
1 OW REQUIREMENTS
I
199!5
I NTERTIED SYSTEM
(15 COMMUNITIES)
ENERGY BALANCE
2000
WITH TAZIMINA HYDROELECTRIC POWER
1980-2000
LV-12 FIGURE :nz::-6
Dillingham-Section IV
APA013/F
10-A/B Intertied System with Lake Elva, and Lake Tazimina
This case has been evaluated to determine the impact of the
development of two sites on the cost of power. The development
is planned as follows:
Lake Elva operational in 1983.
Lake Tazimina operational in 1985.
Additional alternates where the Tazimina development would
be delayed in relation to the smaller projects have also
been briefly examined. Since in all conceivable cases (for
the intertied system) diesel-generation was necessary even
with the small hydro plant operational, no substantial
advantages are realized.
Basic investments are as described for the cases 9 and 5.
C. EVALUATIONS AND CONCLUSIONS
The results of the economic analyses (for details see Appendix C)
for the various alternate development plans are summarized in three
different ways:
l. The sum of the present worths at a discount rate of 7% of
(a) accumulated annual cost; (Table IV-2 and IV-3), and
(b) equivalent unit cost.
2. Cost ratios for the present worth of the unit cost of energy
and accumulated annual cost (Table IV-4 & IV-5) at four different
interest rates for the 20 year study period. A discount rate
of 7% has been used. The cost ratios have been calculated for
scenarios that can be compared directly. Scenarios with
different service areas have been compared on the per unit
cost level only.
3. Diagrams showing the unit cost of energy graphically for the
alternate development plans for high and low load growth as
well as for the four different interest rates (Figure IV-8 to
IV-15).
These graphs illustrate the possible advantages of larger
service areas.
The present worth of the unit cost of energy and the graphical
display of unit cost have been used for this evaluation because
they offer an easily understood base for comparisons.
IV-13
Dillingham -Section IV
APA013/F
All cost comparisons have been done with the assumptions stated in
Appendix C and investment cost for the hydropotentials as developed
in Section III. This means that the hydro development is planned
with conventional three phase transmission lines. If single phase,
low frequency generation and transmission were implemented, (See
Appendix A-3) the savings in the investment cost have been calculated
to be about 10% for the two smaller projects and up to 13% for the
Tazimina project which requires installation of 181 miles of
transmission lines.
The present worth analysis favors the Tazimina (9-A/B) project for
an intertied regional system for all load cases, except for a low
load growth and the highest interest rate. The graphical display
shows, however, that an extension of the evaluation period would
result in a cost ratio greater than 1. Breakeven with the diesel
generation occurs in 1992 for the low load growth assumption and in
the first operational year (1985) of the project for the expected
1 oad case. Cons ide ration of e 1 ectri c heat as described in Appen-
dix A-5, where the utility installs and controls a comfort heating
system in addition to an independent home heating system, results
in higher utilization of the available hydro energy. The unit cost
of electric energy can then be reduced by the incremental revenues
from the sales of heating energy. Figure IV-7 shows the possible
reduction in unit cost. Development of the smaller projects shows
rapidly increasing energy cost with the necessary additional supply
of electric energy by diesel generation. Installation of all three
hydro projects or Elva plus Tazimina is still more economical than
continued diesel generation, but less than the Tazimina project
alone.
For the Dillingham system alone the Lake Elva (5-A/B) project is
very attractive at the lower interest rates but results in higher
cost for energy than diesel generation at the higher interest rates
due to the relatively high initial cost. The necessary additonal
diesel generation eventually results in increasing power cost
parallel to the 11 diesel only 11 scenario.
An evaluation for Grant Lake and the Dillingham system (6-A/B) only
shows it less economical than Elva for all interest rates above 2%.
The remoteness and inaccessibility of this site does not allow
development as rapidly as Lake Elva.
From the purely economical point of view the following alternates
are clearly favored for development:
(i) Transmission Interties
from the small communities in the area to larger central
generating systems.
IV-14
Dillingham-Section IV
APA013/F
(ii) Lake Tazimina
for a reg1onal system including 15 communities in the Bristol
Bay/Lake Iliamna area.
(iii) Lake Elva
for the Dillingham system only.
The following summary table (Table IV-1) shows the unit cost of
power at the distribution bus at a medium 5% interest rate for all
alternates examined.
Additional tables and figures mentioned in the preceding text also
follow.
IV-15
MISC09/J-3
TABLE IV-1
UNIT COST OF POWER
in ¢/kWh
at 5% Interest
Alternate 1985 1990 1995 2000
1-A Di 11 i ngham -Diesel -Low Load 17.1 21.7 27.0 35.3
2-A Naknek -Diesel -Low Load 16.1 20.1 26.3 33.8
3-A* 10 Villages -Local Diesel -
Low Load 50.7 63.1 79.3 101.6
4-A Dillingham/Naknek/10 Villages -
Central Diesel -Low Load 18.2 22.2 28.2 35.8
5-A Di 11 i ngham -Elva -Low Load 18.3 20.0 22.7 28.3
5-B Dillingham -Elva -High Load 16.5 18.7 24.7 30.7
6-A Di 11 i ngham -Grant -Low Load 24.8 20.5 21.8 25.7
6-B Di 11 i ngham -Grant -High Load 18.7 19.5 23.8 30.3
7-A Dill i nghma -Elva + Grant -Low Load 37.0 30.2 25.7 22. 7
7-B Dillingham -Elva + Grant -
High Load 24.6 18.1 21. 7 27.6
8-A Dillingham/Naknek/10 Villages
Elva + Grant -Low Load 24.1 24.9 27.7 32.6
8-B Dillingham/Naknek/10 Villages
Elva + Grant -High Load 20.5 22.1 26.4 32.1
9-A Intertied System (15 Communities)
Tazimina -Low Load 21.0 18.1 16.5 15.5
9-B Intertied System (15 Communities)
Tazimina -High Load 14.4 11.4 15.1 17.8
10-A Intertied System (15 Communities)
Elva + Tazimina -Low Load 24.9 21.3 19.3 18.0
10-B Intertied System (15 Communities)
Elva + Tazimina -High Load 16.6 12.7 15.7 16.5
* Representative for Iliamna, Newhalen, Nondalton also.
IV-16
Dillingham-Section IV
APA013/F
TABLE IV-2
EQUIVALENT UNIT COST OF ELECTRICAL ENERGY (¢/KWH)
AND OF PRESENT WORTHS OF ACCUMULATED ANNUAL COST (1000-$)
FOR 1980 TO 2000
LOW LOAD GROWTH AT 7% DISCOUNT
INTEREST RATE
ALTERNATE 2% 5%
1-A Dillingham-Diesel Unit Cost 21.09 21.36
Ace. Cost 25,527 25,888
2-A Naknek -Diesel Unit Cost 19.89 20.03
Ace. Cost 40,983 41,278
3-A 10 Villages -Local Unit Cost 61.91 62.54
Diesel Ace. Cost 24,689 24,920
4-A Dillingham/Naknek/ Unit Cost 21.71 22.38
10 Villages Intertied -Ace. Cost 79,157 81,529
Central Diesel
5-A Dillingham+ Elva Unit Cost 17.56 20.28
Ace. Cost 20,594 23,870
6-A Dillingham+ Grant Unit Cost 17.59 20.86
Ace. Cost 20,148 24,388
7-A Dillingham+ Elva+ Unit Cost 20.12 25.9
Grant Ace. Cost 23,004 30,278
8-A Dillingham/Naknek/ Unit Cost 20.81 24.02
10 Villages +Grant Ace. Cost 74,656 86J36
9-A Intertied System -Unit Cost 15.35 18.41
Tazimina Ace. Cost 54,006 66,523
10-A Intertied System -Unit Cost 16.69 20.57
Elva + Tazimina Ace. Cost 59,705 75,360
Inflation assumed at 8% per year to 1984, 4% per year thereafter.
Fuel oil escalated 2% above inflation rate.
IV-17
7%
21.6
26,178
20.12
41,505
63.02
25,111
22.88
83,349
22.58
26,632
23.67
27,969
31.73
36,423
26.58
96,548
21.00
76,970
23.84
88,447
9%
21.84
26,479
20.23
41,748
63.52
25,296
23.43
85,304
24.94
29,444
26.50
31,624
35.78
42,684
29.35
106,781
23.67
87,700
27.18
101,869
5-B
6-B
7-B
8-B
9-B
10-B
Dillingham -Section IV
APA013/F
TABLE IV-3
EQUIVALENT UNIT COST OF ELECTRICAL ENERGY (¢/KWH)
AND OF PRESENT WORTHS OF ACCUMULATED ANNUAL COST (1000-$)
FOR 1980 TO 2000
HIGH LOAD GROWTH AT 7% DISCOUNT
INTEREST RATE
ALTERNATE 2% 5% 7%
Dillingham -Elva Unit Cost 18.17 19.91 21.34
Ace. Cost 42,994 46,790 49,955
Di 11 i ngham -Grant Unit Cost 18.07 20.04 21.68
Ace. Cost 42,078 46,857 50,858
Di 11 i ngham -Elva + Unit Cost 16.90 20.27 23.08
Grant Ace. Cost 38,028 45,573 51,928
Dillingham/Naknek/ Unit Cost 20.23 22.30 23.96
10 Villages Grant Ace. Cost 134,175 147,796 158,813
(w.o. Iliamna)
Intertied System -Unit Cost 13.33 15.81 17.91
Tazimina Stage I + II Ace. Cost 80,821 100,816 117,440
Intertied System -Unit Cost 13.4 16.16 18.47
Elva + Tazimina Ace. Cost 80,170 101,490 119,290
Stage I + II
Inflation assumed at 8% per year to 1984, 4% per year thereafter.
Fuel oil escalated 2% above inflation rate.
IV-18
9%
22.85
53,201
23.38
54,957
25.94
58,412
25.72
170,331
20.07
134,536
20.84
137,559
Dillingham-Section IV
APA013/F
TABLE IV-4
COST RATIOS OF ACCUMULATED PRESENT WORTHS
OF ANNUAL COSTS FOR ALTERNATE DEVELOPMENT PLANS
INTEREST RATE
ALTERNATES COMPARED 2% 5% 7%
DILLINGHAM SYSTEM
1-A Diesel -Low Load 1. 24 1. 08 .98 5-A Elva -Low Load
1-A Diesel -Low Load 1. 27 1. 06 .91 6-A Grant -Low Load
1-A Diesel -Low Load 1.11 .86 .72 7-A Elva + Grant -Low Load
REGIONAL SYSTEM -
(Dillingham/Naknek/10 Villages)
~1-A}+~2-A2+{3-A) Local Diesel -Low Load
4-A Central Diesel -Low Load 1.15 1.13 1.11
4-A Central Diesel -Low Load 1. 06 .94 . 96 8-A Elva + Grant -Low Load
4-A Central Diesel -Low Load 1. 47 1. 23 1. 08 9-A Tazimina -Low Load
4-A Central Diesel -Low Load 1. 33 1. 08 .94 10-A Elva + Tazimina -Low Load
IV-19
9%
. 90
.84
.62
1.10
. 80
. 97
. 84
Dillingham -Section IV
APA013/F
TABLE IV-5
COST RATIOS OF EQUIVALENT UNIT COSTS
FOR ALTERNATE DEVELOPMENT PLANS
INTEREST RATE
ALTERNATES COMPARED 2% 5% 7%
DILLINGHAM SYSTEM
1-A Diesel to:
4-A Dillingham/Naknek/10 Villages
Central Diesel -Low Load . 97 .95 . 94
5-A Elva -Low Load 1. 20 1. 05 .96
5-B Elva -High Load 1.16 1. 07 1. 01
6-A Grant -Low Load 1. 20 1. 02 .91
6-B Grant -High Load 1.17 1. 07 1. 00
7-A Elva + Grant -Low Load 1. 05 .82 .68
7-B Elva + Grant -High Load 1. 25 1. 05 . 94
8-A Dillingham/Naknek/10 Villages
Elva + Grant -Low Load 1. 01 .89 .81
8-B Dillingham/Naknek/10 Villages
Elva + Grant -High Load 1. 04 .96 .90
9-A Intertied System -
Tazimina -Low Load 1. 37 1.16 1. 03
9-B Intertied System -
Tazimina -High Load 1. 58 1. 35 1. 21
10-A Intertied System -
Elva + Tazimina -Low Load 1. 26 1. 04 .91
10-B Intertied System -
Elva + Tazimina -High Load 1. 57 1. 32 1.17
REGIONAL SYSTEM -
(Dillingham/Naknek/10 Villages)
4-A Central Diesel to:
8-A Elva + Grant -Low Load 1. 08 .93 .86
8-B Elva + Grant -High Load 1. 07 1. 00 .95
9-A Intertied System -
Tazimina -Low Load 1. 41 1. 22 1. 09
9-B Intertied System -
Tazimina -High Load 1. 63 1. 42 1. 28
10-A Intertied System -
Elva + Tazimina -Low load 1. 30 1. 09 .96
10-B Intertied System -
Elva + Tazimina -High Load 1. 62 1. 38 1. 24
IV-20
9%
.93
.88
.96
.83
. 94
.61
.84
.75
.85
. 92
1. 09
.80
1. 05
. 80
.91
.99
1.17
. 86
1.12
NAKNEK
Dillingham-Section IV
APA013/F
ALTERNATES COMPARED
2-A Diesel to:
TABLE IV-5
(CONTINUED)
4-A Dillingham/Naknek/10 Villages -
Central Diesel
8-A Dillingham/Naknek/10 Villages -
Elva + Grant -Low Load
8-B Dillingham/Naknek/10 Villages -
Elva + Grant -High Load
9-A Intertied System -
Tazimina -Low Load
9-B Intertied System -
Tazimina -High Load
10-A Intertied System -
Elva + Tazimina -Low Load
10-B Intertied System -
Elva + Tazimina -High Load
VILLAGES
3-A Local Diesel to:
4-A Dillingham/Naknek/10 Villages -
Central Diesel
8-A Dillingham/Naknek/10 Villages -
Elva + Grant -Low Load
8-B Dillingham/Naknek/10 Villages -
Elva + Grant -High Load
9-A Intertied System -
Tazimina -Low Load
9-B Intertied System -
Tazimina -High Load
10-A Intertied System -
Elva + Tazimina -Low Load
10-B Intertied System -
Elva + Tazimina -High Load
NOTE:
2%
.92
.96
.98
1. 30
1.49
1.19
1.48
2.85
2.98
3.06
4.03
4.64
3.71
4.62
INTEREST RATE
5% 7%
.89
.83
.90
1. 09
1. 27
.97
1. 24
2.79
2.60
2.80
3.40
3.96
3.04
3.87
.88
.76
.84
.96
1.12
.84
1. 09
2.75
2.37
2.63
3.00
3.52
2.64
3.41
9%
. 86
. 69
. 79
.85
1. 01
.74
.97
2.71
2.16
2.47
2.68
3.16
2.34
3.05
1. 11 High Load 11 cases compared to 11 Diesel 11 cases are approximations; actual
ratio would be slightly lower due to additional diesel investment required.
2. 11 Tazimina 11 cases include Iliamna/Newhalen/Nondalton.
IV-21
80 ----··--·---r-------+------+-------f------+
I
700 +
I 600 -- - - ----1----~~----t----------+------+-------+
I
500 ~"·-·---r----~--·--·------·-+--~----+------+------+-'
400 -------·------~----+-----+----+----~
I I
300 -
200 ·-
I .. --· f--· ·------------~-~-----t-----+------f
........ ........
................
I
------_l COSTS WITHOUT
ELECTRIC HEAT
'r-. COSTS UTILIZING
________ 1------·---+-'_ ...... __, ___ +------=-.....-:..---+~----_-_-_-+ELECTRIC HE AT
......... --90 ·----··--------------+------+ ...... --------+-------+
80
70
60 . -r-·· -~~--------1-------+-----+------!
+-------... -~-1----.
~r -----·-· ---------------------···-· -·-·--+------+
TAZIMINA
BUS BAR COST FOR
ELECTRIC EN&RGY
WITH AND WliHOUT
THE SALE OF ELEC-
TRIC HEAT.
20L __ _ . ___ --~---+-----+------+---------+ ASSUMPTIONS: ~2~w~o:o
I : 5% INTEREST
10 -----. _l ______ ------4----j -----'----~-
1980 1985 1990 1995 2000
FIGURE ::m:-7
IV-22
•
IOOOr----------------r----------------r----------------r----------------,
900~---------------+----------------+----------------+----------------;
800~---------------+----------------+----------------+--------------~
700~---------------+----------------+----------------+----------~--~
600~---------------+----------------+----------------+--------------~
500~---------------+----------------+----------------+--------~----~
r400~---------------+----------------+----------------+--------------~
3:
~
.......
(/)
...J
...J
i300 ~---------------+----------------+----------------+----~~~------;
9A
100~-T--~--~~---+--~--~-+--~--+-~---r--~~~-+--~--+-~--~~ 1980 1985
---4 A -DILLING HAM /NAI<NEK/10 VILLAGES
CENTRAL DIESEL -LOW LOAD
5A -DILLINGHAM -ELVA
---6A -DILLINGHAM -GRANT
---7A -DILLINGHAM-ELVA+ GRANT
---BA-DILLINGHAM/NAI<NEK/10 VILLAGES
ELVA + GRANT .
9A -INTERTIED SYSTEM (15 COMMUNITIES)
TAZIMINA
•--lOA-INTERTIED SYSTEM (15 COMMUNITIES)
LAKE ELV~ + TAZIMINA
BRISTOL BAY
BUSBAR COST Of POWER
LOW LOAD GROWTH
2 -y. INTEREST ·
FIGURE :m -8
•
IOOOr----------------r----------------~--------------~----------------,
900~---------------+----------------+----------------+----------------1
800~---------------+----------------+----------------+--------------~
700~---------------+----------------+----------------+----------------1
600~---------------+----------------+----------------+--------------~
500~---------------r----------------+----------------+--------~------;
~400~---------------r----------------r----------------+--------------~
:lo:
' (/)
_J
_J
~300~--------------f+----------~~==~~-------------+--~~~--~~~
9A
100~-T--1---~-;---r--~--r--+--4---+-~--~--~~r--+--1---~~--~~ 1980 1985
4 A -DILLINGHAM /NAKNEK/10 VILLAGES
CENTRAL DIESEL-LOW LOAD
5 A -DILLINGHAM -ELVA
---6A-DILLINGHAM-GRANT
---7 A-DILLINGHAM-ELVA+ GRANT
---8 A-DILLINGHAM/NAKNEK/10 VILLAGES
ELVA+ GRANT
--9A-INTERTIED SYSTEM (15 COMMUNITIES)
TAZIMINA
• - -lOA-INTERTIED SYSTEM (15 COMMUNITIES)
LAKE ELVA + TAZIMINA
BRISTOL BAY
BUSBAR COST OF POWER
LOW LOAD GROWTH
5 ~.INTEREST ·
FIGURE nz:: -9
•
1000~----~--------~----------------~---------------.----------------,
900~---------------+----------------+----------------+--------------__,
800~---------------+----------------+----------------+--------------~
700~--------------4---------------~---------------4--------------~
600~---------------+----------------+----------------+--------------~
500~---------------+----------------+----------------+--------~----~
z 400~--------------~------~~------+----------------+--------------~
~
:1' .......
(/)
~300r--------------fJt~~~~========f=======~~=:~:t;;~~~~=:;:~
4 A -DILLINGHAM /NAKNEK/10 VILLAGES
CENTRAL DIESEL-LOW LOAD
5 A -DILLINGHAM -ELVA
6A -DILLINGHAM -GRANT
7 A -DILLINGHAM -ELVA + GRANT
SA-DILLINGHAM/NAKNEK/10 VILLAGES
ELVA + GRANT .
--9A -INTERTJED SYSTEM (15 COMMUNITIES)
TAZIMINA
---lOA-INTERTIED SYSTEM (15 COMMUNITIES)
LAKE ELVA + TAZIMINA
BRISTOL BAY
BUSBAR COST OF POWER
LOW LOAD GROWTH
7 •t. INTEREST
FIGURE Ill:-10
•
IOOOr----------------.----------------.----------------.----------------,
900~---------------+----------------+----------------+----------------;
800~--------------~----------------+----------------+----------------1
700~---------------+----------------+----------------+----------------;
600~--------------~----------------+----------------+----------------1
~ 400~------------~~----------------+-----~~~-----+----------------;
:lie
' (/)
.J
.J
~300~------~~~~~~~~~~~==;::=;:~~~~==~~~~
YEAR
--4A -DILLINGHAM/NAKNEK/10 VILLAGES
CENTRAL DIESEL-LOW LOAD
5 A -DILLINGHAM -ELVA
---6 A-DILLINGHAM-GRANT
---7 A -DILLINGHAM-ELVA+ GRANT
---SA-DILLINGHAM/NAKNEK/10 VILLAGES
ELVA + GRANT .
-9A-INTERTIED SYSTEM (15 COMMUNITIES)
TAZIMINA
---lOA-INTERTIED SYSTEM (15 COMMUNITIES)
LAKE ELVA + TAZIMINA
BRISTOL BAY
BUSBAR COST OF POWER
LOW LOAD GROWTH
9 -y. INTEREST
FIGURE Ill -II
I
•
700r----------------.----------------~---------------.----------------,
aoor-~-------------+----------------+----------------;----------------;
500+---------~----+---------------+---------------~------------~
400+----------------+----------------;---------------~----------------~
x300+----------------+----------------;----------------;----~~~----~~
31:
~ ......
Cl)
..J
..J
::::E
IOO+----------------+--=-------~c---4-------~------~---~~~~~~--~
90+----------------+----------~----43~----~------~--------------~
70+--,~-.--,---r--+---r--r--,---r--~-,.-~--,---r--;---r--~-,.--r--4
1980 1985 1990
YEAR
2000
4A-DILLINGHAM/NAKNEK/10 VILLAGES
CENTRAL DIESEL-LOW LOAD
5 B -DILLINGHAM -ELVA
68 -DILLINGHAM-GRANT
78 -DILLINGHAM-ELVA+ GRANT
88-DILLINGHAM/NAKNEK/10 VILLAGES
ELVA + GRANT .
9 B -INTER TIED SYSTEM (15 COMMUNITIES)
TAZIMINA
lOB-INTERTIED SYSTEM (15 COMMUNITIES)
LAKE ELVA + TAZIMINA
BRISTOL BAY
BUSBAR COST OF POWER
HIGH LOAD GROWTH
2 •t. INTEREST
FIGURE nz:: -12
I
•
IOOOr----------------r----------------r----------------.--------------~
900~--------------~----------------+----------------+--------------~
800~--------------~----------------~---------------+--------------~
700~--------------~----------------+----------------+--------------~
600~--------------~----------------~---------------+--------------~
500~--------------~----------------~---------------+--------~----~
~400~--------------~----------------+---------------~--------------~
~
........
If)
....J
....J
i300~--------------.P~--------------+----------------+~~~~~~~~
4A-DILLINGHAM/NAKNEK/tO VILLAGES
CENTRAL DIESEL-LOW LOAD
-58 -DILLINGHAM-ELVA
68 -DILLINGHAM-GRANT
--
78 -DILLINGHAM-ELVA+ GRANT
88-DILLINGHAM/NAKNEK/tO VILLAGES
ELVA+ GRANT
98 -INTERTIED SYSTEM (1!5 COMMUNITIES)
TAZIMINA
lOB-INTERTIED SYSTEM (15 COMMUNITIES)
LAKE ELV~ + TAZIMINA
BRISTOL BAY
BUSBAR COST OF POWER
HIGH LOAD GROWTH
7 •t. INTEREST
FIGURE nz: -14
•
IOOOr----------------r----------------r----------------.----------------,
900~--------------~----------------~---------------+--------------~
800~---------------r----------------r----------------+--------------~
700~---------------r----------------~---------------+--------------~
600~--------------~----------------~---------------+--------------~
500~---------------+----------------+----------------+--------~----~
I40Q~--------------~----------------~--------------~--------------~ 3C
:II:
' Cll
..J
..J
i 300~-------------4~----~~--------r----------------t~~~--~~~~
100~-T--~--r-~--~--+-~~-+--~--r-~--~--~~--~--~--~-+--~~ 1980 1985
YEAR
4A -DILLINGHAM/NAKNEK/tO VILLAGES
CENTRAL DIESEL-LOW LOAD
-58 -DILLINGHAM -ELVA
6 B-DILLINGHAM-GRANT
7 8 -DILLINGHAM -ELVA+ GRANT
8 8-DILLINGHAM/NAKNEK/tO VILLAGES
ELVA + GRANT .
- -9 B -INTERTIED SYSTEM (15 COMMUNITIES)
TAZIMINA
---lOB-INTERTIED SYSTEM (15 COMMUNITIES)
LAKE ELVA + TAZIMINA
BRISTOL BAY
· BUSBAR COST OF POWER
HIGH LOAD GROWTH
9 •t. INTEREST ·
FIGURE Ill: -15
V. OTHER ELECTRIC ENERGY RESOURCES
Dillingham-Section V
APA15/G
V. OTHER ELECTRIC ENERGY RESOURCES
This section addresses alternate electrical energy resources to the
continuation of diesel generation or the development of the hydro-
potentials identified in previous sections of this report. The
recognized alternates have been evaluated to a great detail in the
11 Bristol Bay Study 11 .*
With the utilization of active solar collectors and solar voltaic
cells still in the development stages and tidal power technically
and economically not feasible at this time for the area, wind
power, transmission interties and conservation hold the greatest
promise for the near future. Biomass (wood, peat, etc.) conversions
have not been assessed due to the lack of resource information.
A. WIND POWER POTENTIAL
Existing records indicate that the wind power potential is excellent
in the King Salmon/Naknek area and good at Iliamna. The available
data from Dillingham, although not summarized, allow the assumption
that the potential here is probably as good as in King Salmon.
Historical experience with wind energy conversion systems (WECS) in
Alaska has not been too promising, mostly due to equipment failure,
high repair and maintenance cost and poor reliability of accessory
equipment. Newly developed WECS utilizing induction generators
appear to be more reliable, less costly, and easier to interface
with existing electric systems. It should, however, be noted that
these new WECS are not ••stand alone 11 systems. They require connection
to an operating power system. For the near future these new systems
appear to hold the most promise if utilized in existing systems by
individual consumers or utilities to offset fuel cost. The following
Table V-1 shows the average windspeed related to the resulting
energy output of two different WECS with induction generators and
the associated cost.
11 Bristol Bay Energy and Electric Power Potential -Phase I 11
,
Draft-October 1979 prepared for the U.S. Department of Energy,
Alaska Power Administration.
V-1
Dillingham-Section V
APA15/G
TABLE V-1
WIND GENERATOR ENERGY AND
Output
kW Range
Av. Annual Annual MWH 4
Location Wind Seeed 1
1.5 KW RATED GENERATOR
King Salmon/ 12.5 0.4-0.6
Dillingham 4.32
Iliamna 11.7 0.3-0.7
3.96
15 KW RATED GENERATOR
King Salmon/ 12.5 2. 7-4.0
Dillingham 28.91
I1 i amna 11.7 1. 7-5.7
25.4
POWER OUTPUT
Installed2
Cost $ (1979)
Annual 3
Cost $ (1979) Energy CostE,
¢/kWh (1979)
9,440 79
3,403
9,440 86
3,403
50,000 29
8,355
50,000 33
8,355
Notes: Investment cost and maintenance cost are based on manufacturer 1 s
information with very little field data from Alaska available
2
:l
4
s
to verify these assumptions.
At 60 1 mounting height.
From Appendix C. Assumes cogeneration (no energy storage).
15 year loan, 9% interest (.1221 cap. recovery factor) plus
maintenance $2250 per year for 1.5 kW and 15 kW.
Secondary (not firm) energy only.
Cost for secondary energy only, cost for primary (firm) power
has to be added.
V-2
:r:
~
Dillingham-Section V
APA15/G
With secondary energy only available from a WECS, only the fuel
saved should be used in an economic evaluation. Figure V-1 shows
how the unit cost of energy compare between the WECS and locations
listed in Table V-1 to diesel generation at the same locations.
The energy costs (¢/kWh) shown for the various WECS systems represent
costs at 80% utilization; the costs shown in Table V-1 (last column)
are valid for 100% utilization.
200~--------~---------.----------.----------r----------r---------~
150
DILLINGHAM
1.5KWWECS
80% UTILIZATION
ILIAMNA
DIESEL GENERATION
AT 8 KWH/GAL!
~ 100~----~--4----------;----------+---------~~--------~------~~
' ~
....
U'l
0
f.)
1.5 KW WECS
80% UTILIZATION
DILLINGHAM
DIESEL GEN-
ERATION AT
12 KWH/GAL.
0~--------~--------~----------~--------~----------~--------~
0 2 4 6 8 10
FUEL COST $/GAL.
FIGURE V-1
COST OF ELECTRIC ENERGY
AT DILLINGHAM AND ILIAMNA
WIND ENERGY VERSUS
V-3 DIESEL GENERATION
12
\
Dillingham-Section V
APA15/G
The average consumption of a residence at a low electrification
level is approximately 2,400 to 3,000 kWh per year and the demand
about 3-6 kW. A 11 stand alone 11 system will therefore require a WECS
of this capacity plus an inverter and storage batteries to supply
the energy requirements during low wind periods. The cost for
inverter and batteries can add $3,000 to $4,000 to the initial cost
of a wind power system. The use of WECS for water heating or
pumping purposes does appear to be the most economical application
of these systems since in this case virtually all windspeeds -up
to the mechanical limits of the system-can be fully utilized.
To allow utilization of wind energy potential when less costly and
more reliable equipment becomes available, windspeed records should
be established in the various communities where this information is
presently not available.
B. TRANSMISSION INTERTIES
l. 10 Villages in the Nushagak/Kvichak Area
Diesel generating plants in small communities produce electric
ener·gy of much higher costs than for larger systems. The
following factors contribute to these costs:
a. Fuel costs ar·e higher due to transportation.
b. Small engines are less efficient than larger ones
(6-8 kWh/gal of fuel compared to 12-14 kWh/gal.)
c. Operating and maintenance costs are higher.
A low cost transmission intertie of the small systems to a
larger utility can provide less costly electric power to the
small community.
The feasibility of such an intertie has been investigated for-
the ten communities in the Nushagak/Kvichak area (listed in
Section II).
The interties with the exisiting Dillingham/Naknek systems
have been assumed to be single phase lines utilizing the
single wire ground t·eturn scheme (see Appendix B-1). This
type of transmission system will allow relatively low cost
installation compared to three phase transmission. Most of
the connected loads are single phase loads and phase conver-
sion equipment can readily produce three phase power where
needed.
V-4
Dillingham -Section V
1\PJ\15/C.
Two demonstration projects -utilizing single wire ground
return lines -are under contract to be built in the Bethel
and Kobuk area as demonstration projects in the near future.
It is anticipated that this scheme can eventually replace
small, inefficient diesel plants and make less costly power
available to remote communities.
To assure adequate voltage levels in the communities under
consideration, the interties have been chosen at 40 kV with
conductors 7#8 Alumoweld or 226.8 ACSR respectively. The
approximate routing has been shown on Figure V-2.
The following table lists the central utilities and the com-
munities to be intertied with their expected peak loads in the
year 2000, the distance from the load center and the required
tie-lines.
To simplify the evaluation the energy use as well as the
investment cost for all communities have been added together
and it has been assumed that the Dillingham and Naknek systems
produce electric energy at approximately the same cost.
The results of economic evaluations (See Appendix C for details)
performed for a low load growth rate are shown on Figure V-3
for the alternates.
a. Local diesel generation (Alternate 3-A).
b. Central diesel generation with transmission interties
(Alternate 4-A).
c. Tazimina Hydro with transmission interties (Alternate 9-A).
V-5
I
." ·futl~RAf+l ·)
·; 2700'1<,W
.0'
~
I
I
I
.. ( .
. . /"~~~'woK}' ·~/ ' ~· . 'I' . .
I
I
I
[t~~l.
)
I
I
I
·~
,.
•
LEGEND
[ff] HYDROELECTRIC GENERATING PLANT WITH
INSTALLED CAPACITY.
TRANSMISSION LINE 1 138 KV 30
EXISTING DISTRIBUTION LINES (UP TO 24KV)
1(1 OR 31!J
SINGLE WIRE GROUND RETURN
TRANSMISSION 1 40 KV
DISTRIBUTION LINE (UP TO 24 KV)
•• • • • • • • • • TRANSMISSION LINE 1 69 KV 31!J
.. -
11
DlLL:.ING HAM I NAKNEK
US fO VILLAGES INTERTI£
SC~LE : h f 000 _a&
, FIGURE :lr-2
Dillingham -Section V
APA15/G
From
Location
Dillingham
Di 11 i ngham
Di 11 i ngham
Naknek
Naknek
TOTAL
TABLE V-2
TRANSMISSION TIE LINES
To Distance Max. Load
Location (Miles) kW
Manokotak 25 560
Ekuk} 20 1780
Clark 1 s Point}
Ekwok 49 345
New Stuyahok +10 390
Koliganek +20 345
Portage Creek +15 107
Levelock 32 290
Igiugig +40 120
Egegik 48 1400
284 5337
Intallation Cost
107 miles 266.8 ACSR@ $16,000
177 miles 7#8 Alumoweld @ $15,000
River Crossings,
15 Terminals @ $35,000
Total
Use
V-7
Operating Conductor
Voltage Size
(kV)
40 7#8
Alumoweld
40 7#8
+ Marine cable
40 266.8 ACSR
40 266.8 ACSR
40 7#8
Alumoweld
40 7#8
Alumoweld
+ river crossing
40 7#8
Alumoweld
40 7#8
Alumoweld
40 266.8 ACSR
1979-$
$1,776,200
2,655,000
16,000
525,000
($4,972,200)
$4,975,000
IOOOr
900t
eoot---
700~ -.
I
60C
500
i
200!--
roo~ -
90t
I 80~ 70~
soL :
50~
i
...
1980 1985
~. -------1----~-----~-
---...1 i
/l SMALL COMMUNITIES
-7 /" --WITH LOCAL DIESEL
; GENERATION
·+
+---._ I
·--1-·-.
: ----~ INTERTIED SYSTEM
(15 COMMUNITLES) WITH
LAKE TAZIMINA
THE COST OF ELECTRIC
ENERGY IN DILLINGHAM
AREA
------···---t--~~-----~-----j---~-------·--·--t-ASSUMPTIONS: LOW LOAD
GROWTH
1990 1995
YEAR
2000
: 5% INTEREST
35 YEAR LOA~
Fl GU RE JZ:-3
V-8
Dillingham-Section V
APA15/G
It has been assumed that the interties are operational in
1980. Diesel capacity for the village loads has been added in
the central utilities.
The investigation shows that a transmission intertie between
Dillingham/Naknek and the 10 villages should be approached on
an individual basis at the present time. Close attention has
to be paid to existing systems and operating efficiencies. If
the Tazimina project is taken into account, however, these
transmission ties will eventually lower the electric energy
cost in all communities drastically.
2. Bristol Bay -Kuskokwim
Bristol Bay and the Kuskokwim area are separated by the Ahklun
and Kilbruck Mountains with peaks up to 4500 feet high. A
transmission intertie of the two areas appears to be prohibitive
at first thought because of the country that has to be traversed
and the associated cost of construction. However, with hydro
development in both areas the possibility of an intertie
merits investigation. A technically feasible route would be
from Dillingham via Togiak to the Golden Gate Hydro site.
Such an intertie could be beneficial to both areas for the
following reasons:
a. Service reliability to either area is enhanced.
b. Surplus energy can be absorbed in a combined system and
result in lower power cost.
c. Additional hydro development can be postponed.
The following paragraphs will investigate the possible results
of an intertie in 1995 when load growth (at the historical
rate) in the Dillingham/Naknek area would require implementa-
tion of Tazimina Stage II to assure sufficient hydroelectric
capacity to supply area needs.
The possibility of this i ntert i e is considered under the
assumption of hydroelectric potential developments at the
Kisaralik River (Golden Gate) and Lake Tazimina.
2.1 Loads and Energy Sources
For the year 1995 the area loads (high growth scenario) are
assumed as follows:
V-9
~ .
I
\'
\) '( .
\ .
\ .
\
i . . ·!GRANT LAKEI
l!p:z .Tlllf;'
I
I
l
I
I
I
I
J
-t.,
I<! I
I
rl'
I
1615 r.tj.
I ~
1 LEGEND
l ;r"._;;~~ HYDROELECTRI C GENtERAT i rtG ~l~~~
·;;_,' ' WI TH INSTALLED CAPACITY '''· (. 1 ~'--. viLLAGE._ SIT E -/:;.Q j
-·-TRANSMISSI ON L I NE~+~3flf
---------,:-~~~~STpN· L INE ,69 KV 3§6 .
.,___..;.o"'oe-. EXI~ING' DISTRIBUTION,Q:i.N E-".W~~~'KV) '.:f~ QR 31111 . I ~-·./ •-~;'-' _,
.....-.,...._ '. -.. Keto~
'
•
B RtSTOt _:_BAY._-'KlJS KOKWIM
TRANSMISSION INTEATIE'
-:~ :~:Se'ALE= 1: 1 ooo aoc
FIGURE JZ'i,..
0,~. 79
.,'(·
Dillingham-Section V
APA15/G
Power Requirements 1995
Annual MWh Peak kW
Bristol Bay
Togiak
Kuskokwim
Total
100,747
6,381
83,866
190,994
19,790
1,582
17,699
39,071*
Hydro Capacity
Annual MWh** Peak kW
Kisaralik
Tazimina
Total
* Noncoincident.
126,801
76,080
202,881
30,000
18,000
48,000
** Adjusted for Transmission losses (3.5%).
2.2 Transmission -Line Data
Although the direct distance from Lake Elva to the Kisaralik
hydro site is only approximately 80 miles, a transmission line
would have to be routed along a much longer route. The route
is shown on Figure V-4 11 Bristol Bay -Kuskokwim, Transmission
Intertie 11 • The total length is approximately 198 miles. If
an exchange of 15 MW maximum is assumed, a 138 kV, 30 trans-
mission line with 556.6 KCM ACSR conductor will provide adequate
service. Costs for the intertie are then assumed as follows:
198 miles transmission@ $135,000
1 substation at Togiak
2 substation additions (Dillingham and
Kisaralik) @ $150,000
Total
2.3 Economic Evaluation
1979 -$(1,000)
$26,730
300
300
$27,330
The 1995 energy requirements listed under 2.1 show that the
Dillingham/Naknek area can use 24,667 MWh from the Kisaralik
project. Busbar costs for this year are as follows (without
intertie), but assuming utilization of 24,667 MWh from Kisaralik:
V-11
Dillingham-Section V
APA15/G
Kisaralik
Tazimina
1995
15.1¢/kWh
16.6¢/kWh
The annual cost for the Tazimina Stage II development at 5%
interest are:
1995 $ 5,990
(from Appendix C)
The unit cost paid for the required 24,667 MWh are then (5,990
+ 24,667) 24.3 ¢/kWh
The cost for an intertie are:
Construction in 1994 (to be operational in 1995)
Inflation at 8% to 1984
at 4% to 1994 1994 -$(1,000)
Annual cost at 5% interest
and 35 years life (.06107)
+ O&M at 1% of line
Total Annual Cost
$59,442
3,630
594
$ 4,224
The unit cost paid for the required 24,667 MWh are then
(4224 + 24,667) ~ 17.1 ¢/kWh
Plus Kisaralik cost
from Appendix C,
(Bethel Study*)
Total
15.1 ¢/kWh
32.2 ¢/kWh
* 11 Reconnaissance Study of the Kisaralik River Hydroelectric
Power Potential and Alternate Electric Energy Resources in
the Bethel Area 11 for the Alaska Power Authority by R. W.
Retherford Associates, March 1980.
Comparing:
Unit cost in 1995 for Tazimina -Stage II
Unit cost in 1995 for Intertie to Kisaralik
Difference
V-12
24. 3 ¢/kWh
32.2 ¢/kWh
~
Dillingham-Section V
APA15/G
The negative result does not necessarily preclude the installa-
tion of the intertie.
This analysis, by only using one particular performance year,
and not evaluating the added reliability and reduced standby
requirements has to be considered rather superficial.
If it is assumed that the intertie is a low frequency, SWGR
line with converter stations at Togiak and Dillingham (Kisaralik
built at low frequency, single phase), it is anticipated that
the investment could be reduced by approximately 40%. This
would prove feasibility easily.
It is therefore recommended, that the possibility of this
intertie is investigated in more detail if the hydro develop-
ments take place as anticipated.
C. CONSERVATION
The transmission intertie described in part B of this section
represent one form of conservation by utilizing highly efficient
generating equipment rather than smaller, less efficient engines in
small communities. This investigation can be extended one step
further to the 11 individual /community 11 level. Where private
generators (at fuel rates of 4-5 kWh/gal.) are being used,
centralized power at fuel rates of 6-8 kWh/gal. will not only
conserve fue 1 but a 1 so produce more re 1 i ab 1 e and 1 ess costly
electric energy. Other forms of conservation in the Bristol Bay
area, where the electrical hook-up saturation is extremely low, can
be achieved by the following measures:
1. Variable Speed Engines
This unorthodox method of improving the efficiency and life
expectancy of di ese 1 engines has been described in various
studies 1 '2 and basically employs a gearbox between the prime
mover (diesel engine) and generator to allow speed reduction
for the prime mover at times of low load and still maintain
constant speed at the generator. The diesel engine will then
perform at an apparent high load efficiency rate and require
less maintenance due to reduced wear.
1 11 Bristol Bay Energy and Electric Power Potential 11
, Alaska Power
Administration.
2 11 Waste Heat Capture Study 11
, Division of Energy and Power
Development.
V-13
Dillingham-Section V
APA15/G
2. Wasteheat Recovery and Utilization
Engine jacket water heat is utilized in the Dillingham and
Naknek plant for space heating purposes. Exhaust heat is not
used in any installations in the study area. Since approx-
imately 70% of the energy input into a diesel engine generator
is lost as wasteheat, the rapidly increasing costs of fuel oil
are expected to make installation of exhaust heat recovery
equipment economically feasible even for older existing plants.
An evaluation on a case by case basis is however advisable to
assure the most economical installation.
V-14
VI. RECOMMENDATIONS
Dillingham -Section VI
APA018/I
VI. RECOMMENDATIONS
The economic evaluation of the Lake Elva hydroelectric potential
development and possible alternates indicates clearly that implemen-
tation of some possible plans will require regional consent and
cannot be undertaken by Dillingham or any single community in the
area alone.
The recommendations are therefore made for two different basic load
areas, Dillingham and a regional intertied system (12-15 Communities).
For Dillingham alone Lake Elva possibly followed by development of
Grant Lake proves more econom1cal than continued exclusive use of
d1esel generation, assuming the low interest rate of 2 and 5%. For
the higher interest rates of 7 and 9%, diesel generation is preferred
in the low load growth case. Load growth as expected (high) favors
development of Lake Elva and Grant Lake.
Development of the Tazimina potential will result in the lowest
power cost for all commun1ties in an intertied, combined system -
even for the highest interest rate (9%) used if the load grows as
expected.
A. DILLINGHAM
If a regional intertied system is ruled out, Nushagak Electric
Cooperative (NEC) in Dillingham should develop Lake Elva. A permit
to study this potential has already been issued by FERC 1 to NEC and
preliminary investigations have been performed in the frame of this
study. Further feasibility studies are not considered necessary,
if REA financing at an interest rate of 2 or 5% can be obtained.
In this case the project should be prepared for FERC 1 i cense
application. With the planned development as a 11 minor 11 (under
1,500 kW installed) project, it is anticipated that this application
can be prepared in a few months. Issuance of a license can then be
expected within less than a year. The design and construction
period is estimated to be a minimum of 2 years. The foregoing
assumptions lead to the earliest operational year of 1983 for the
project.
If FERC license application is pursued, right-of-way and construction
permits will have to be obtained from the State of Alaska, Department
of Natural Resources, Division of Parks, since Lake Elva as well as
the required transmission corridors are located in the Wood River
1 Federal Energy Regulatory Commission.
VI-1
Dillingham -Section VI
APA018/I
Lakes Park. Cooperation of the Department of Fish and Game should
be solicited in environmental matters especially in regard to
possible impact during construction.
The additional development of Grant Lake should be reinvestigated
after Lake Elva is operational and when it can be assessed whether
the high or low load growth pattern is prevailing.
B. REGIONAL DEVELOPMENT (12-15 COMMUNITIES)
Economic feasibility of the development of the Tazimina Lakes
Hydroelectric power potential depends on an interconnected system
between Dillingham/Naknek and the King Salmon Airforce Base as a
m1n1mum. Additional benefits are realized, if small communities
are included and intertied via Single Wire Ground Return lines as
described in Section V of this study.
Implementation of this project is judged the most beneficial for
the entire area. Supply of cost stable energy for 15 communities
for more than 20 years can be assured by this potential.
FERC license application and exemption of the dam and power plant
sites as well as the transmission corridor from the intended wilder-
ness designation of the area should be undertaken immediately.
Since the Iliamna Village Ltd. and Nondalton Ltd. native organizations
have filed for the ownership of the majority of the land necessary
for the power plant and reservoir their 11 non-objection 11 should be
solicited.
The necessary steps to initiate development are seen as follows:
1. Organization Framework
A regional entity is needed to pursue the
t Filing of an application for a 11 Preliminary Permit 11 with FERC,
if FERC jurisdiction has been determined.
t Filing of a 11 Declaration of Intention 11 with FERC if private
ownership of the land has been determined.
• Preparation of the FERC license application where necessary.
t Investigation of financing methods.
1 Removal of the Tazimina plant, damsite and the transmission
corridor from the wilderness designation, if necessary.
VI-2
Dillingham-Section VI
APA018/I
• Construction and eventual operation of the facilities and
necessary transmission interties.
Various ways are open to the area communities and utilities to
establish and finance such an organization:
• An informal regional commission which would work closely with
local utilities and the AKPA 1 . In this commission the
communities and utilities could be represented by an elected
member.
• A regional Generation and Transmission (G&T) cooperative based
on the exist1ng REA f1nanced ut1lities.
2. Financing
Depending on the type of regional entity formed the methods of
project financing will vary.
• Regional Commission: Funds can be appropriated by the State of
Alaska legislature, or bonds can be issued. In the latter
case it is most likely that AKPA would be the issuing agency.
• G & T: This agency, formed by REA financed Cooperative members,
would have the advantage of being able to obtain low interest
REA -funds (at least for part of the project). Supplementary
funds would then be raised by legislative funds or bonds.
3. Activities to Prepare for License
In order to assure an efficient and smooth preparation process the
following steps should be taken simultaneously after it has been
decided to proceed.
•
•
1
Determine the land status of the facilities site, reservoir
site and transmission corridor.
If the 1 and status research determines private ownership
(native land claims conveyance) file a 11 Declaration of Intention 11
with FERC, asking for a waiver of the licensing process.
Alaska Power Authority.
VI-3
Dillingham-Section VI
APA018/I
• If the land status research determines federal jurisdication,
file for a 11 Preliminary Permit to Study 11 with FERC. If this
permit is granted, exemption of the land from wilderness
status (204e withdrawal) appears to be certain.
• Contact the Alaska Department of Fish and Game, the U.S.
Department of Fish and Wildlife, the U.S. Forest Service and
BLM to assure their input and cooperation in regard to environ-
menta 1 study requirements, and right-of-way and permits.
• Initiate preparation of a Definite Project Report.
• Initiate environmental studies.
• P 1 an and ins ta 11 SWGR transmission i ntert i es to the sma 11
communities.
If the shortest possible times are allocated to the various
prerequisites listed above, the following time frame is considered
a minimum to implement the project:
Form G&T
Obtain license to study
Submit FERC license application
License granted
Design
Construction
Earliest Date on Line
C. FURTHER INVESTIGATIONS
March 1980
May 1980
December 1980
December 1981
Mid 1981 to Mid 1982
1982 to End 1984
1985
The only briefly addressed possibility of utilizing single phase,
low frequency generation and transmission should be pursued, since
substantial savings in the initial cost of the hydrodevelopments
are conceivable. Manufacturers have shown interest in supplying
this type of equipment, but a detailed evaluation including detailed
equipment data avai 1 ability and cost has yet to be performed.
The concept of utility installed and controlled electric heating
devices in connection with hydrodevelopments appears to be viable
and beneficial for relatively large projects to meet the existing
load. Figure IV-6 (Section IV) shows the beneficial effects of
VI-4
Dillingham -Section VI
APA018/I
this concept on the unit cost of power for the early years of the
project•s operation. There a more detailed study could address
technical details and other parameters.
To properly assess the wind power potential for various small
communities, installation of anemometers and establishment of at
least one year•s records is strongly recommended for the communities
of:
Clarks Point
Egegik
Ekuk
Igiugig
Koliganek
Levelock
Manokotak
New Stuyahok
Portage Creek
Newhalen
Nondalton
VI-5
APPENDIX A
TECHNICAL DATA
Dillingham-Appendix A
APAOll/K
A-1 SINGLE WIRE GROUND RETURN
TRANSMISSION
A-1
Dillingham -Appendix A
APAOll/K
GENERAL CONCEPT
MINIMUM COST TRANSMISSION SYSTEM
Single Wire Ground Return Transmission of Electricity
The Single Wire Ground Return (SWGR) transmission concept described
in this propos a 1 has evo 1 ved from a recognition of certain basic
facts-of-1 i fe concerning e 1 ectri c energy in remote western and
interior Alaska, which facts are:
1. Small electric loads and the geographic distribution of villages
presently limit electric energy supply to small, inefficient
fossil-fueled generating plants.
2. Fuel prices in the western and interior regions, already
uniquely high, face the probability of continued escalation.
3. Conventional three-phase electric transmission/distribution
systems to intertie the outlying communities to more efficient
generating plants are mostly impractical because high initial
costs penalize the transmitted energy rates.
4. A transmission system using a Single Wire Ground Return (SWGR)
line promises good electrical performance [1] [4] [7] {8]
[10]* and a substantially lower initial capital cost and
therefore a lower transmitted energy cost than conventional
transmission.
5. The SWGR line can be constructed using a high percentage of
local labor and local resources in areas that need gainful
employment as well as lower cost electricity.
6. The incentive to develop new, alternative energy sources (such
as appropriate scale hydroelectric power in the area) is
dependent on an economically viable electric transmission
scheme that can feasibly deliver such energy to the villages.
The SWGR transmission concept is one which proposes to deal with
these realities.
While the use of a single energized wire and earth return circuit
is unconventional in the sense that applications are not common, it
is an accepted system of proven use in several areas of the world
[7] [8] [9] [10[ [11]. Three phase equipment can also be successfully
operated from this system by using phase converters [6].
* References at end of Appendix A-1.
A-3
Dillingham-Appendix A
APAOll/K
The fifth edition of the National Electrical Safety Code (NESC)
allowed the use of the ground as a conductor for a power circuit in
rural areas; however, the most recent edition does not. It is the
opinion of this writer that the SWGR system proposed here would in
no way create an operating system with a lesser safety than the
11 convent i ona 111 system now in use throughout~JU aska. R()bert W.
Retherford Associates has applied to the eState of Alaskaj.for an
exception to the NESC to allow constructl'OrY"o'T a SWGR system.
Verbal approval has been received, with final approval to be on a
case by case basis, to construct demonstration projects using this
principle.
A project to supply central station electricity to isolated villages
using the SWGR system is proposed. Such a project would provide a
demonstration of the technical and cost ~easibility of the system.
The following pages provide a listing of objectives and a description
of three alternate projects of increasing size and cost that will
contribute valuable data for use in considering further extensions
of such systems.
A-4
Dillingham -Appendix A
APAOll/K
PHYSICAL DESIGN AND CONSTRUCTION CONSIDERATIONS
Lack of a road system, permafrost, and limited or no accomodations
for constructon crews throughout most of the region being studied
establish some limitations that must be dealt with to find appropi'iate
solutions. Conventional construction techniques and line designs
might be used -but at premium costs.
A design believed most adaptable to these limitations is based 011
the use of an A-frame structure shown in the following sketch
labeled Figure 1. The arrangement is well suited to the SWGR
design.
It is be 1 i eved that the design has certain features that wi 11
provide unique opportunities for its use over the terrain of this
region, as follows:
1. The structure can be built using maximum local products and
manpower. The legs of the A-frame can be made from 1 oca l
spruce that grows along the major river systems of the region
and can be transported by these rivers. With this being done,
75% of the total line construction dollars could stay within
the region.
2. The structure has transverse stability from gravity and need
not penetrate the earth (permafrost in this region). Longi
tudinal stability is obtained through the strength and normal
tension of the line conductor. This allows for use of the
shortest lengths for legs to provide the ground clearances
needed for safety. Additional longitudinal stability would be
provided before and after guying at suitable intervals.
3. The Single Wire configuration can be designed for minimum cost
by utilizing high-strength conductors that require a minimum
number of structures and still retain the standards for high
reliability. For example:
A single wire line constructed using 7#8
Alumoweld High Strength (approx. 16,000
lb. breaking strength) wire, electrically
equi va 1 ent to a #4 ACSR conductor wi 11
require one ha 1f as many structures per
mile as the #4 ACSR under the same Heavy
Loading Design Conditions. (The 1 i ne
could also be converted to 30 at a future
date by adding another structure in each
span, and adding the new conductors. )
A-5
PRELIMINARY DESIGN DATA
"A11 -FRAME, SPRUCE POLE, GRAVITY STRUCTURE
Figure A-1.1
A-6
Dillingham-Appendix A
APAOll/K
4. The A-frame, gravity stabilized design form allows the use of
a unique, engineering/construction technique that will
substantially reduce both engineering and construction effort
as follows:
The high strength conductor is laid out on
the ground between anchor points (at
typi ca 1 i nterva 1 s of 1 to 2 miles) and
tensioned while on the ground to the
approximate stringing tension.
An engineer and assistant locate structure
points by using the tensioned conductor as
a template (lifting it above the ground to
observe clearances from the natural contour).
This could be done in winter time by using
snow machines rigged with a small 11 jig'' to
underrun the conductor and 1 i ft it to
predetermined heights for observation.
At points selected by the engineer, a crew
assembles a structure completely and
fastens it permanently to the conductor
(all lying on the ground). The crew lifts
the structure at the point of attachement
while the stress in the conductor is being
maintained at the appropriate stringing
tension. (A typical structure with conductors
in an 800 foot span might weigh 900 lbs.
complete.)
5. Long river crossings (typically 2000 feet or less in length)
can be accomplished using the same high strength conductor.
Severa 1 such crossings have been in successful operation in
Alaska using this same 7#8 Alumoweld wire as follows:
Naknek River (S. Naknek to Naknek)
Talkeetna River (near Sunshine)
Along Kachemak Bay,
Tutka Bay
Sadie Cove
Halibut Cove
2000 ft.
1894 ft.
1835 ft.
4135 ft.
2070 ft.
6. Costs for an SWGR line constructed using the A-frame design
and high strength conductor is estimated to be about one-third
(1/3) the cost of an equivalent 30, 4 wire line of similar
capacity.
A-7
Dillingham -Appendix A
APAOll/K
The gravity stabilized A-frame line design using long span
construction will provide excellent flexibility to adapt to
the freezing -thawing cycles of the tundra and shallow lakes
of the region. Experience in this kind of terrain has clearly
demonstrated the need to 11 live with 11 these seasonal cycles and
avoid designs that cannot tolerate movement of the structure
footings. Gravel backfill around and under poles that are set
in the earth using more conventional line designs has proven
seccessful but usually expensive and in many areas of this
region highly impractical because of lack of gravel.
Hinged structures supporting large transmission line conductors
(Drake, 795 MCM, ACSR, 31,700 lb. strength, 1.094 lbs. weight/ft.)
across shallow and deep muskeg swamps and permafrost have been
performing excellent service on the lines from Beluga across
the Susitna River and its adjacent flat lands. Some of this
route has severe freeze -thaw action that has dramatically
demonstrated the need for flexibility. These flexible systems
have performed as intended during severe differentia 1 frost
action. The basic structura 1 phi 1 osophy and performance of
this transmission line is reflected in the proposed A-frame
arrangement described here.
The experience with such existing lines provides the strong
basis for confidence in the structural performance of this new
design.
A-8
Dillingham -Appendix A
APAOll/K
ELECTRICAL CHARACTERISTICS
Series impedances and shunt capacitive reactance for selected
conductor sizes have been calculated using the following formulas
r 121:
Series Impedance
e
2160 j f
Zg = rc + 0.00158 f + j0.004657f log 10 GMR
r = resistance of conductor per mile c
f = frequence in Hz
p = earth resistivity in ohm meters
GMR = geometric mean radius of conductor
Shunt Capacitive Reactance
X c
XI
a
XI
e
h
r
= X 1 + 1/3 X 1 in Megohms per mile a e
__ . 0683 60 1 I (Capacitive Reactance at 1 ft. spacing) r og1o r:
= 1 ~ · 3 log 10 2h (Zero Sequence Shunt Capacitive
Reactance Factor)
= height above ground in ft.
= frequency in Hz
= conductor radius in ft.
The line data have been calculated with the following assumptions:
Frequency:
Height above ground:
Earth Resistivity:
60 Hz, 25 Hz
30 ft.
100 Ohm-m (swamp),
1000 Ohm-m (dry earth)
Ground Electrode Resistance: R Ohms of each end
A-9
Dillingham-Appendix A
APAOll/K
60 Hz IMPEDANCES AND SHUNT CAPACITIVE REACTANCES
R GMR(Ft) z (ohm per mile) X
(Ohm Diam. p = 100 p = 1000 c (Meg ohm
Conductor Size Per Mile) (inch) Ohm-m Ohm-m Per Mile)
7#8 Alumoweld 2.354 .0116 2.449 + 2.449 + .244
.385 1 .504 1 .643
266.8 MCM .35 .0217 .445 + .445 + .229
ACSR .642 1. 428 1. 567
397.5 MCM .235 .0278 .33 + .33 + .222
ACSR .806 1.397 1. 537
556.5 MCM . 168 .0313 .263 + .263 + .218
ACSR .927 1.383 1. 523
795 MCM . 117 .0375 .212 + .212 + .213
1~ 1. 361 1. 501
25 Hz IMPEDANCES AND SHUNT CAPACITIVE REACTANCES
R GMR(Ft) z (ohm per mile) X
(Ohm Diam. 100 p -1000 c p = (Meg ohm
Conductor Size Per Mile) (inch) Ohm-m Ohm-m Per Mile)
7#8 Alumoweld 2.354 .0116 2.394 + 2.394 + .586
.385 j .649 j .707
266.8 MCM .35 .0217 .390 + .390 + .549
ACSR .642 .617 .675
397.5 MCM .235 .0278 .275 + .275 + .533
ACSR .806 .604 .663
556.5 MCM . 168 .0313 .207 + .207 + .523
ACSR .927 .598 .657
795 MCM . 117 .0375 .157 + .157 .511
1~ .589 .647
A-10
Dillingham-Appendix A
APAOll/K
LIST OF
fll 11 A Regional Electric Power System for the Lower Kuskokwim
Vicinity, A Preliminary Feasibility Assessment 11 prepared for
the United States Department of the Interior -Alaska Power
Administration, by Robert W. Retherford Associates, Anchorage,
Alaska, July 1975.
12] Alaska Electric Power Statistics 1960-1975, published by the
United States Department of the Interior - A 1 aska Power
Administration, Fourth Edition, July 1976.
[3] 11 Grounding Electric Circuits in Permafrost 11
, a paper by J. R.
Eaton, P.E., West Lafayette, Indiana (formerly Professor of
Electrical Engineering, Purdue University and visiting Professor
of E·lectrical Engineering, University of Alaska) consultant to
Alyeska Pipeline Service Co.; P.O. Klueber, P.E., Senior
Operations Engineer, Alyeska Pipeline Service Co., Anchorage,
Alaska and Robert W. Retherford, P.E. of Robert W. Retherford
Associates, Anchorage, Alaska. January 1976.
f4l 11 Single-Wire Ground -Return Transmission Line Electrica·i
Performance 11
, a paper prepared for Robert W. Retherford Associates
by J. R. Eaton, visiting Professor of Electrical Engineering,
University of Alaska, Fairbanks, Alaska, Apdl 1974.
f 51 11 Ground Electrode Systems 11
, by J. R. Eaton, Professor of
Electrical Engineering, Purdue University, Lafayette, Indiana,
sponsored by Commonwealth Edison Company, Chicago, Illinois,
June 1969.
[6] 11 Performance Characteristics of Motors Operating from Rotary-
Phase Converters", prepared by Leon Charity, Professor'
Agricultural Engineering, Iowa State University, Ames, Iowa,
and Leo Soderholm, Agricultural Engineer, Farm Electrification
Res. Br. AERO, ARS, USDA, Ames, Iowa. This paper was presented
at the IEEE Rural Electrification Conference held at Cedar
Rapids, Iowa May 1-2, 1967. Paper No. 34CP, 67-268.
l7J 11 Rural Electrification by Means of High Voltage Earth Return
Power Lines", by My E. Robertson, Paper No. 1933 presented
before a General Meeting of the Electrical and Communication
Engineering Branch of the Sydney Division on 27 August 1964.
The author is the Design Engineer for the Electricity Authority
of New South Wales, Australia.
A-ll
Dillingham-Appendix A
APAOll/K
[8J "Wire Shielding 230 kV Line Carries Power to Isolated Area" -
an article which appeared in the July 15, 1960 issue of
Electric Light and Power, written by D. L. Andrews, Distribution
Studies Engineer and P.A. Oakes, System Analysis Engineer,
Idaho Power Company. This article describes a 40 kV single-phase
transmission line using earth return.
[91 "Single-Phase, Single-Wire Transmission for Rural Electrification",
Conference Paper No. CP 60-883, presented at the AlEE Summer
General Meeting, Atlantic City, New Jersey, June 19-24, 1960
by R. W. Atkinson, Fellow AlEE and R.K. Garg, Associate Member
AIEE, both of Bihar Institute of Technology, P.O. Sindri
Institute, Dhanbad (Bihar) -India.
flO] "Single Wire Earth Return High Voltage Distribution for
Victorian Rural Areas 11
, by J.L.W. Harvey, B.C.E., B.E.E.,
H.K. Richardson, B.E.E., B. Com., and LB. Montgomery, B.E.,
B. E. E., Messrs. Harvey and Richardson are with the Electricity
Supply Department, State Electricity Commission of Victoria,
Australia and Mr. Montgomery is Director and General Manager,
Warburton Franki (Melbourne) Ltd. This paper No. 1373 was
presented at the Engineering Conference in Hobart, Australia,
6 to 21 March, 1959. The paper recalls that 11 •••••• the system
was first developed by Lloyd Mandeno of Aukland, New Zealand,
who introduced it in the Bay of Islands area in the North
Island of New Zealand in 1941. Since that time ....... thousands
of consumers are connected to hundreds of miles of single-wire
lines ...... In September 1951, the State Electricity Commission
of Victoria erected a small experimental system at Stanley ..
following the success of the experimental installations the
single-wire earth-return system has been very extensively used
in Victoria . "
1111 11 Using Ground Return for Power Lines 11
, by R.K. Garg (see [9]
above) of the Bihar Institute of Technology -an article
published in the Indian Construction News, June 1957.
[12] Electrical Transmission Distribution Reference Book, 4th
Edition, 1950, copyrighted and published by the Westinghouse
Electric Corporation, East Pittsburg, Pa.
A-12
Dillingham-Appendix A
APAOll/I
A-2 DISTRIBUTION AND TRANSMISSION LINE
LOAD LIMITATIONS
A-13
Dillingham-Appendix A
APAOll/I
DISTRIBUTION AND TRANSMISSION LINE LOAD LIMITATIONS
The amount of power that can be transmitted over a distribution or
transmission line is limited by:
• current carrying capacity of the conductor
• tolerable voltage drop
• electrical system stability.
System stability considerations have to be determined for individual
cases and current carrying capacity depends strictly on conductor
material and size.
Voltage drop, however, is a limiting factor dictated by line length,
operating voltage, 1 oad, and conductor size and configuration.
Voltage Drop (%) = Voltage sent -Voltage received
Voltage received X 100
Maximum tolerable voltage drops are for:
Distribution Lines (up to 24.9 kV)1
Transmission Lines (from 34.5 kV up to 138 kV)2
6.67%
5-7%
The following tables show load limitations in form of Megawatt
Miles for various distribution and transmission lines. For
distribution lines calculations where performed in accordance with
REA Bulletin 45-1 where:
Megawatt -Miles ::: (VD) (kV 2 ) (cos 8) P
(R cos 8 + X sin 0) 100
Where VD = Allowable voltage drop in %
2
kV ::: Line to ground voltage
8 Phase angle between voltage and CUI'rent
p = # of phases
R = Resistance in ohms per phase per mile of line
X = Reactance in ohms per phase per mile of line
REA Bulletin 169-27, January 1973
Standard Handbook for Electrical Engineers.
lOth Edition.
A-15
Fink & Carroll.
Dillingham-Appendix A
APAOll!I
For transmission lines tables published in REA Bulletin 65-2 have
been utilized and for Single Wire Ground Return Lines the following
formula 1 is considered to render adequate results for preliminary
investigations:
Receiving End Voltage =
Where =
=
=
=
X I V1 I 2 -CQ12) (R 2+X 2 )
V1 [ X cos o + R sin o ]
Sending end voltage in kV
Resistance in ohms per phase per mile
Reactance in ohms per phase per mile
Phase Angle between the two bus voltages
( R2 + X2
X ) ]
Where P12 = total real power (MW)
The reactive power Q12 ~ Q2 + Q Loss -Yc V12
Where Q2
Q loss
Yc
=
=
=
Receiving end reactive power (MVAr)
Line loss reactive power (MVAr)
Shunt capacitive admittance in Meg
mhos per mile
It should be understood that this formula can only be used for
11 Short 11 line models (up to 50 miles) and that the following
assumptions have been made:
1. R <; 1/5 X
2. o and V2 are calculated by solving for each alternatively,
assuming o ;:; 10°
3. vl and v2 differ less than 10%
4. Line length 1 mile
The load limitation given in Table B-2 can be used for preliminary
feasibility investigations. For actual line design more accurate
calculations are mandatory.
From: Electric Energy Systems Theory by Olle I. Elgerd. Published
by McGraw-Hill, Inc.
A-16
App<!ndi• A-2 • lllllingham
AI'A012/Hl
TABLE A-2. 1
LINE LOADING LIMITS IN MEGAWATT MILES
IN REGARD TO ALLOWABLE VOLTAGE DROP
FOR SELECTED CONDUCTOR SIZES
l4.4k.V·30
UISTRIBU'flON I.INES (6.67\ Voltage Drop)
COnductor-----=-~i!Y:!! __ --· __
Size -AWG P.F. P.F. P.F. n·. 1. 2kV-3~
P.F.
--~--1_4 ~kV-.!!,__ ___
P.F. P.F. P.r. P.F. p:y-:----P:-r:-----.~r:
(ACSR/AAC) .9 .95 1.0 .\I .95 1.0 .9
~--------· ____ , _____________________ _
14
l/0
4/0
397.5
1.1 1.2
1.9 2. 2
2.8 3.3
l '4 3.9
3.1 8.3
5.4 13.3
19
Baaed oo linea ot Standard REA Deoign
Tranamiasion Lin~• (5'1. Voltage Drop)
Conductor--=:69·-liv ~~~qui v -~.i!!.&2
Size-AWG P.F. P.F. P.L
(ACSII) .9 .95 1.0
4.1 4.6 4.3
8.9 11. 1 4
15.5 23.3 11
23 44
liS kV (13.48'~~1'.!0!'82_
P.F. P.f. P.F.
.9 .95 1.0
.95 1.0 .9 .95
4. 1 5.6 15.5 16. 7
8.4 12 33.3 36.7
13 21 Sl 60
74 91
_11!_!<!' .. .\ 19 ,~~~~UIV_:__~~ i~g)
P.F. P.F. P.F
. 9 '95 1.0
--------~-----~-·-----------·---------
Partridge
266.8 307 362 573
IBIS
397.5 370 450 788
Uove
556.5 423 526 997
Drake
795 416 603 1228
~·flal~_\o!ire Ground .!l,.:.:e:.:tc:uc::.r:.:.n...:L::.:i:.;;n:.oe.::.• (5\ Voltage Drop)
Conductor
S1ze • AWG
(ACSI< unle""
otherwise noted}
JIB Alumoweld
IBIS 397.5
Dove 556.5
Urake 195
40 kV
P.F.
.9
25
70
75
80
85
819
980
1112
1243
973 1571
11\17 2142 1359 1668 3030
1389 2685 1535 1924 :Jl70
1581 3271 1706 2178 455&
66 kV 80 kV
I'. F. P.F.
.9 . 9 ------·
bS 95
180 265 ]20
200 290 800
2!5 315 860
225 335 9!0
Ground rrai&Livity = 100 oh.m-11 (characterizes swampy wetland•). Voltage drop ot the ground electrod••• ha. not been l.1ken tulo
an.:ount.
Calculated using A,B,C,Il conHont..
A-17
l.O
18.9
46.7
91
173
Dillingham-Appendix A
APAOll/J
A-3 PHASE AND FREQUENCY CONVERSION
IN POWER TRANSMISSION
A-19
Dillingham-Appendix A
APAOll/J
PHASE AND FREQUENCY CONVERSION IN POWER TRANSMISSION
Power transmission lines are limited in their capacity to transport
energy by conductor sizes and voltage 1 eve 1 s. Higher operating
voltages and larger conductors will allow transmission of larger
loads over greater distances. Load and distance of transmission
will cause the voltage to drop. If this drop exceeds 5-7% of the
nominal voltage either load or distance should be decreased or a
higher voltage level and/or larger conductor should be chosen.
In Alaska, where small communities with low energy demands are
separated by great distances, conventional transmission lines are
in most cases too high cost to allow feasible installation. The
Single Wire Ground Return transmission scheme is a lower cost
transmission system that may be feasible where conventional 3-phase
lines would be too expensive to be built (see Appendix B-1). If
such a system is utilized at a lower operating frequency the load
or transmission distance could ~creased bY an amount that is
inversely proportional to the new value for the frequency and a
further potential saving in costs might result.
Railroad electrification in the U.S. as well as in Europe has
utilized reduced frequencies (25 and 16 2/3 Hz respectively) to
maintain adequate voltage levels over great distances. Generating
plants, transmission lines and substations have been built exclusively
to supply the railroad distribution network with single phase, low
frequency power.
Interconnections between three phase, 50 or 60 Hz systems and
single phase, 16 2/3 or 25 Hz systems have been made via rotating
converter sets up to 45 MVA 100 . Static frequency/phase conversion
equipment is available, but presently not an "off the shelf" item
for small (1-2 MW) applications. It is conceivable that this type
of power transmission and conversion can be economically feasible
where conventional transmission lines would be too expensive.
In case of a remote hydroelectric plant, for example, the power can
be generated single phase at low frequency, the voltage stepped up
to transmission level and transported to the point of utilization
where, after voltage step down, phase and frequency can be converted
to the required system parameters.
Since accurate cost estimates for conversion equipment could not be
obtained in time to be used for this study, the potential benefits
are shown for a hypothetical case.
A-21
Dillingham-Appendix A
APAOll/J
Transmission line capacity is shown here in terms of Megawatt miles
at 5% voltage drop, .9 power factor for:
CONDUCTOR
SIZE
(AWG)
266.8 ACSR
397.5 ACSR
556.5 ACSR
266.8 ACSR
397.5 ACSR
556.5 ACSR
THREE PHASE TRANSMISSION, 60 Hz
AND
SINGLE WIRE GROUND RETURN, 60 Hz and 25 Hz
THREE PHASE
60 Hz
:34.5 kV 69 kV
78 295
94 353
108 401
SWGR
60 Hz
40 kv 66 kV 80 kV
70 180 265
75 200 290
80 215 315
SWGR
25 Hz
13~ kV
1359
1535
1:33 kV
720
800
860
40 kV 66 kV 80 kV 1:3:3 kV
266.8 ACSR 110 300 440
397.5 ACSR 135 360 540
556.5 ACSR 150 410 600
See Appendix B-1 and B-2 for method of calculation.
The construction cost of SWGR transmission is estimated at
approximately 30-40% of a three phase transmission line. For a
rough comparison the following costs can be used:
1200
1440
1640
34.5 kV 30
69 kV 30
138 kV 30
$ 80,000/mile (conductor up to 556.5 ACSR)
$100,000/mile (conductor up to 556.5 ACSR)
$125,000/mile (conductor up to 556.5 ACSR)
A-22
Dillingham-Appendix A
APAOll/J
Transmission line cost for the following assumptions are then:
Power to be transmitted 6 MW
Distance 50 Miles
(Refer to previous table for equivalent capabilities)
30-69 kV, 397.5 ACSR
SWGR (60Hz) -80 kV, 266.8 ACSR
SWGR (25Hz) -66 kV, 266.8 ACSR
$5,000,000
$2,500,000
$2,000,000
The achievable cost savings if SWGR transmission is employed are:
$2,500,00 to $3,000,000
which would allow an expenditure of
$416 to $500 per kW
for phase and frequency conversion equipment.
A rotating converter set of this size (6 MW) with controls is
estimated to cost approximately $300/kW. Preliminary cost estimates
for static converters received from a manufacturer indicate $200/kW
per terminal. Conversion losses are estimated at 6% at each terminal.
Generating equipment for single phase, reduced frequency operation
is approximately 10% and 20% more expensive for an equivalent power
output than for three phase equipment.
To demonstrate the benefits of reduced frequency operation for
power transmission systems more clearly, investigations in regard
to the availability of conversion equipment as well as the capacity
and cost are necessary. The evaluation of a particular project
installed with conventional and low frequency, single phase equipment
could then show the potential savings.
It seems clear that the potential applications such as described
herein deserve a more in-depth evaluation since the potential
benefits appear substantial.
A-23
Dillingham -Appendix A
APAOll/J
BIBLIOGRAPHY
100 11 The Largest Rotating Converters for Interconnecting the
Railway Power Supply with the Public Electricity System in
Kerzers and Seebach, Switzerland11 Brown Boveri Review, November
1978.
101 11 Electrical Transmission and Distribution Reference Book 11
,
Westinghouse, 1964.
102 11 Standard Handbook for Electrical Engineers 11 , Fink and Carroll,
lOth Edition.
103 11 Electrical Engineers• Handbook 11 , Pender, Delmar, 4th Edition
Electric Power.
A-24
Dillingham -Appendix A
APA14/B
A-4 DETERMINATION OF II ECONOMIC 11 DISTANCE TO SUPPLy
CENTER FOR SWGR INTERTIES
A-25
Dillingham -Appendix A
APA14/B
A-4 DETERMINATION OF 11 ECONOMIC 11 DISTANCE TO SUPPLY
CENTER FOR SWGR INTERTIES
In the following, the distance between a supply center and a community
that can be economically bridged with a tie-line is investigated.
1. Basic Assumptions
a. Load:
b. Power Supply:
c. Fuel Cost:
d. Power Cost:
The average small community load as
established in the energy requirements
section is:
95 kW at .4 L.F. with 320,000 kWh per year
Existing diesel generation at 8 kWh/gal.
efficiency.
$.8/gal. in supply center, 25% higher in
small community.
To identify potential savings the following
tabulated cost elements are compared.
--~S~m~a~ll~C~o~mm~u~n~i~t~y ____ ¢/kWh Supply Center ¢/kWh
Fue 1 at $1. 00
Lube etc. at 10%
Maintenance
Operating personnel
(1 at $25,000
per year plus 30%
benefits and tax)
12.5
1.2
1.0
10.2
24.9
Bulk prime rate
for purchase of
electricity
(Bethel 5/79) 8.0
+ Fuel surcharge
(60.4¢/gal. base
& 12 kWh/gal.) at
at $.8 1.63
9.63
e. Transmission/Distribution Line Cost
From Appendix 8 -
for SWGR lines up to 40 kV
constructed with local labor
Conductor 7#8 Alumoweld
Conductor 4/0 ACSR
Terminal (2 required)
A-27
$19,000
$28,500
$35,000
Dillingham-Appendix A
APA14/B
*
2.
Annual Fixed Cost (Capital Recovery)
7#8
35 Year Loans Alumoweld 4/0 ACSR Terminal
Interest at $/mile $/mile $/each
2% 760 1,140 1,400
5% 1,160 1,740 2,137
7% 1,467 2,201 2,703
9% 1,798 2,697 3,312
f. Performance Limitations for SWGR Lines
From Appendix A-2: (without
7#8 4/0
Voltage Alumoweld ACSR
kVL-G MW miles*
7.2 . 8
12.5 2.5
14.4 3.3
24.9 9.8
40.0 25.0
5% Voltage drop .
. 9 Power factor.
MW miles*
2.1
6.3
8.3
24.9
80.0
100 Ohm-m earth resistivity.
Economic Distance
voltage drop at terminal)
miles
Load 7#8 miles
MW Alumw . 4/0 ACSR
.1 8 21
.1 25 63
.1 33 83
.1 98 249
.1 250 800
a. Allowable annual payment for tie-line cost for local
b.
Mi 1 es
generation
320,000 kWh x $.249 $79,680
minus
Cost for wholesale power
(320,000 kWh+ 5% losses) x $(0.963)
Distance from supply center:
32,356
$47,323
=Allowable Annual Payment Annual -Cost for Terminals(2)
Annual Cost for Tie-Line Per Mile
A-28
Dillingham-Appendix A
APA14/B
Interest Alumoweld
Rate Miles
2% 58
5% 37
7% 29
9% 23
3. Conclusions
4/0 ACSR
Miles Remarks
39 24.9 kV min for 7#8
12.5 kV min for 4/0
25 24.9 kV min for 7#8
12.5 kV min for 4/0
19 14.4 kV min for 7#8
15 12.5 kV min for 7#8
With the assumptions and cost estimates stated above the
maximum economic distance is 58 miles for the Alumoweld Conductor
for an interest rate of 2%. At a rate of 9%, 23 miles can be
bui 1 t. If the comparison parameters are assumed to be a
worst-case (local power cost low, central supply high), it is
conceivable that a distance of 50 miles can prove to be
"economi ca 1''.
Figure A-4.1, "Line Mile Multiplier'', may be used to determine
a correction factor by which to multiply the economic distances
listed for 7#8 alumoweld for other than the annual base cost
listed. Graph A-4.1 is used in the following manner. Determine
the local utility and central utility annual costs. Divide
these costs by the corresponding local utility and central
utility base cost. Use the utility base cost multiplier to
enter the graph and read the line mile multiplier from the
vertical axis.
Example: Local Utility Annual Cost= 87,650
Central Utility Annual Cost= 29,120
Interest Rate = 5%
Base Economic Distance 37 miles
Local Utility Base Cost Multiplier= 87,660 =
79,680 1.10
Central Utility Base Cost Multiplier= ~~:jg~ = 0.90
Enter the graph and determine where the 1.10 local utility multiplier
intersects the 0.90 central utility cost curve. Read "line mile
multiplier of 1.25 from the vertical axis.
Economic distance= 37 miles x 1.25 ~ 46 miles
A-29
.:;rapl. ;..-:,.1
1.5 T , 0.80
FIGURE A-4,1
LINE MILE MULTIPLIER
FOR 7 • 8 ALUMOWELD I / -0.90
1.4
LOCAL UTILITY ANNUAL a:
BASE COST •• 79,680 w I / / .o
...J
CENTRAL UTILITY ANNUAL a..
BASE COST •• 32,360 ~ 1.3
:;:) I / / .(~../ • 1.10 :::1!
w
...J
:::1! I / / .v / -1.20 1.2
> w z I :1 w
0
0.80 1.20
BASE COST MULTIPLIER
0.1'0
0.60
0.50
Dillingham-Appendix A
APA14/B
A-5 EVALUATION OF ELECTRIC HEAT AND
HYDROELECTRIC POWER
A-31
Dillingham-Appendix A
APA14/B
A-5 EVALUATION OF ELECTRIC HEAT IN RELATION
TO HYDROELECTRIC POWER
A. THE CONCEPT
The output of a hydroproject is often relatively large when first
connected compared to the demand of the supplied area. The costs
per kWh are then high since the large investment has to be paid
whether its output is used or not. Utilization of this surplus
power in electric home heating (at a rate comparable to cost for
heating with other systems) could lower the overall unit cost of
electric energy from the project. A problem arises when -at a
later point in time -the area demand (minus the electric heat)
approaches the capacity of the hydroplant. At that time the electric
heating load and its demand would require installation of additional
capacity. If additional hydropotential cannot be found, the added
capacity would be diesel or other fossil fuel burning plants, or
ask a 11 consumers with e 1 ectri c heat to convert to some other
heating system!
The following scheme appears to provide benefits and yet avoid most
of the problems electric home heating can have for a utility and
the homeowner:
1. The homes are built with a conventional heating system~
electric heat.
2. The utility pays for the installation of the electric heat and
controls.
3. The utility sells the energy for the electric heat at a rate
equal or lower than the other heat supply fuel cost.
4. The utility is allowed to control utilization of the electric
heat -e.g. turn it off during times of peak demand. During
these times the "normal 11 heating system supplies comfort
heating for the home. In this way the existing alternate home
heating system actually provides peaking capacity to the
utility.
A-33
Dillingham-Appendix A
APA14/B
B. ECONOMIC EVALUATION
Where are the benefits and to whom do they occur?
1. Investment Cost
Installation of heating system
20 kW @ $100/kW
Control equipment
Central station control equipment
(assumed Sangamo System 5)
1979 -$/Consumer
2,000
100
2,100
50,000
NOTE: Potential need for larger distribution transformers, service
drops and service entrance equipment has not been taken into
account. It is believed that more detailed analysis would
show that since control is provided, it is likely that few
increases in capacity of transformers and lines would be
required.
2. Benefits
Essentially all revenue from electric heating (kWh sales minus
the equipment installation cost) are benefits which can be
used to lower the rates for electric energy from the hydroplant
until full utilization is achieved.
Tables A-5.1 and A-5.2 illustrate this type of electric heat
utilization for the Dillingham/Naknek area with the Tazimina
hydroelectric project.
C. SENSITIVITY TO CHANGES IN PARAMETERS
1. Load Growth
Accelerated growth will lead to an earlier exhaustion of
11 surplus 11 energy and render the electric heating system useless
after a few years. Table A-5.1 shows though that even as
little as 5 to 6 years of full utilization will make it
economically feasible.
A-34
Dillingham-Appendix A
APA14/B
2. The Basic Heating System
Calculations are based on a fuel oil heating system (as they
are almost exclusively used in the Bristol Bay and Lower
Kuskokwim area) and inflation of fuel cost to >$3/gallon in
the year 2000. A heating system other than fuel oil (wood -
or coal fired for example) could change the results. Such
systems may have the following differences:
a. not as easy to control;
b. 1 ess expensive to operate and therefore produces 1 ower
11 receipts 11 for heating kWhs.
NOTE: Analysis has to be done more in depth to evaluate sensitivity
to the following parameters:
a. Annual cost for heating system including O&M and replacement
cost.
b. Lower use of heating energy due to improved insulation
etc.
c. Various heating systems, other than fuel oil.
d. Impact on other system facilities such as transformers
and lines.
A-35
::>
I
'""" 0"
Dillingham-Appendix A
APA015/Hl
TABLE A-5.1
Evaluation of Electric Heat for Dillingham/Naknek with
Lake Tazimina Hydro
High Load Growth
11 Normal 1
' Possible
Marketable Surplus Marketable Number of Receipts 4
Hydro MWh 5 Hydro Heating Residential For Heating
Year MWh 1 (High) MWh MWh 2 Consumers ($1,000) ----
1985 76,080 47,675 28,405 31,268 1,198 1,405
86 76,080 51,615 24,465 32,416 1,242 1,283
87 76,080 55,555 20,525 33,564 1,286 1,141
88 76,080 59,495 16,585 34,713 1,330 977
89 76,080 63,435 12,645 35,861 1,374 790
1990 76,080 67,375 8,705 36,983 1,417 576
91 76,080 74,049 2,031 37,897 1,452 142
92 107,360 80 '723 26,637 38,810 1,487 1,976
93 107,360 87,397 19,963 39 '724 1, 1,573
94 107,360 94,071 13,289 40,637 1,557 1,108
1995 107,360 100,747 6,613 41,603 1,594 584
96 107,360 107,422 -,543 1,630 -
97 107,360 114,097 -43,482 1,666 -
98 107,360 120 '772 -44,422 1,702 -
99 107,360 127,447 -45,361 1,738 -
2000 107,360 134,121 -46,249 1, 772 -
8,552
~ Present Worth 1985 at 7% discount
7,992
1 Net-transmission losses 3.5%.
2 (# residential consumers x 29,000 kWh) -10% to account for fuel use during peaks.
3 Investment only-no O&M, inflated 8% to 1984, 4% thereafter.
Cost of Possible
Heating Benefits
Installation 3 To Normal
& Controls Busbar Cost
($1,000) ($1,000)
3,970 (2,565)
149 1,134
155 986
161 816
167 623
170 406
144 (2)
150 1,826
156 1,417
162 946
178 406
180 (180)
187 (187)
195 (195)
202 (202)
199 (199)
5,483 (Cash Flow at
beginning of year)
5,125 (Cash Flow at year
end)
4 Fuel replacement equivalent: $/g~j 8 ~0 66 1 ! ~7 kWh; fuel cost escalated 2% above inflation rate (1979 base= 81.9¢/gal)
5 Incl. 10% system losses.
> I w .....,
Dillingham -Appendix A
APA015/H2
TABLE A-5.2
Evaluation of Electric Heat for Dillingham/Naknek with
Lake Tazimina Hydro
Low Load Growth
11 Normal 11 Possible
Marketable Surplus Marketable Number of Receipts 4
Hydro MWh 5 Hydro Heating Residential For Heating
Year MWh 1 (High) MWh MWh 2 Consumers ($11000)
1985 76,080 31,300 44,780 31,268 1,198 1,544
86 76,080 32,748 43,332 32,416 1,242 1,697
87 76,080 34,196 41,884 33,564 1,286 1,863
88 76,080 35,644 40,436 34,713 1,330 2,042
89 76,080 37,092 38,988 35,861 1,374 2,236
1990 76,080 2,445 38,541 37,539 36,983 1,417
91 76,080 39,829 36,251 37,897 1,452 2,536
92 76,080 41,117 34,963 38,810 1,487 2,593
93 76,080 42,405 33,675 39,724 1,522 2,647
94 76,080 43,694 32,386 40,637 1,557 2,698
1995 76,080 44,982 31,098 41,603 1,594 2,746
96 76,080 46,270 29,810 42,543 1,630 2,791
97 76,080 47,559 28,521 43,482 1,666 2,830
98 76,080 48,847 27,233 44,422 1,702 2,864
99 76,080 50,135 25,945 45,361 1,738 2,893
2000 76,080 51,424 24,656 46,249 1,772 2,914
23,531
L Present Worth 1985 at 7% discount
21,991
1 Net-transmission losses 3.5%.
2 (# residential consumers x 29,000 kWh) -10% to account for fuel use during peaks.
3 Investment only -no O&M, inflated 8% to 1984, 4% thereafter.
Cost of Possible
Heating Benefits
Installation3 To Normal
& Controls Busbar Cost
($12000) ($1,000)
3,970 (2,426)
149 1,548
155 1,708
161 1,881
167 2,069
170 2,275
144 2,392
150 2,443
156 2,491
162 2,536
178 2,568
180 2,611
187 2,643
195 2,669
202 2,691
199 2, 715
5,483 (Cash Flow at
beginning of year)
5,125 (Cash Flow at year
end)
4 Fuel replacement equivalent: $/gal x 3413 x kWh · · 1
138 ,000 x .7 ; fuel cost escalated 2% above 1nflat1on rate (1979 base= 81.9¢ ga
5 Incl. 10% system losses.
APPENDIX A-6
HYDROLOGICAL ANALYSIS
A-39
Dillingham -Appendix A
APA15/B
LAKE ELVA HYDROELECTRIC PROJECT
A. SUMMARY AND CONCLUSIONS
There is no direct streamgaging data available for Lake Elva,
although a gage was installed in late 1979. The average annual
runoff of 39,440 acre-ft. was derived synthetically for the project.
A dam constructed to spillway Elevation 350 feet would provide
29,000 acre-ft. of active storage capacity which would be filled
from a 10.5 square-mile drainage basin. The power and energy which
can be developed from the Lake Elva project are summarized as
follows:
Installed Capacity
Prime Capacity
Average Prime Energy
Average Annual Energy
1,500 kW
910 kW
7,972 MWh
8,370 MWh
The peak inflow rate for the probable maximum flow was calculated
to be 15,750 cfs. A spillway 7 feet high by 100 feet long would be
required to pass the inflow design flood.
B. METHOD OF ANALYSIS
A U.S.G.S gage was installed at Lake Elva in late 1979. However,
no flow data is available. Two methods of analysis were used to
determine the streamflows for the lake Elva Hydroelectric Project.
1. Method 1
As the drainage area for Lake Elva is 10.5 square miles,
correlation with the Nuyakuk, the Chicknuminuk and the Upnuk
rivers, all of which have gages, provided a typical discharge
per square mile data for streams in the area. The runoff for
these three rivers is as follows:
Drainage
River Runoff Basin Area Discharge
Nuyakuk 4,300,000 a.f. 1,490 mi 2 3.88 ft 3 /sec/mi 2
Chiknuminuk 800,000 a.f. 286 mi 2 3.86 ft 3 /sec/mi 2
Upnuk 280,000 a.f. 100 mi 2 3.80 ft 3 /sec/mi 2
Rounded 4.00 ft 3 /sec/mi 2
A-41
Dillingham-Appendix A
APA15/B
The area tributary to the three gages is generally at lower
elevations north and east of the Lake Elva basin and further
from Bristol Bay (the direction of prevailing precipitation).
Also, the NOAA Technical Memorandum NWS AR-10, Mean Monthly
and Annual Precipitation, Alaska, (1974), indicates the Lake
Elva drainage is in a higher precipitation 11 pocket 11 than the
surrounding area.
Accordingly, by judgment, the 4 cfs/mi 2 average of the three
gages was increased to 5 cfs/mi 2 .
2. Method 2
An alternate method of analysis, used in determining the
streamflows, required the development of a probable set of
precipitation and total volume of precipitation values on a
month-by-month basis, using 20 years of recorded precipitation
data for Di 11 i ngham and the above described NOAA Techni ca 1
Memorandum.
Mean temperature data for Dillingham was subsequently correlated
to the Lake Elva area to estimate the probable monthly distribu-
tion of precipitation runoff in order to develop a synthetic
runoff record for Lake Elva (Table A-6.1).
It was assumed that 10% of the precipitation would be lost due
to evaporation and other losses.
From the synthetic monthly streamflow data deve 1 oped in
Table A-6.1, a programmed step-by-step calculation of runoff
and draw using a 29,000 acre-ft. reservoir was used to determine
the prime power and energy available from the Lake Elva Hydro-
e 1 ectri c Project. The average annual secondary energy was
then computed using the average annual streamflow over the
20-year synthetic record.
C. CLIMATE
There are no weather stations in the immediate vicinity of the Lake
E 1 va dams ite. Weather records have, however, been recorded at
Dillingham since 1881. Temperature extremes and total precipitation
can be expected to be greater at Lake Elva than at Di 11 i ngham
because of its higher elevation and the distance from the damsite
to the warming influence of Bristol Bay. Average temperatures for
Dillingham are as follows:
A-42
Dillingham-Appendix A
APA15/B
DILLINGHAM AVERAGE TEMPERATURE (°F)
Period
January
July
Annual
Min.
8.5
45.6
25.7
Mean
15.6
55.1
34.1
Max.
22.9
64. 7
42.5
The average precipitation in Dillingham is 25.8 inches with the
prevailing wind direction being northerly. Results of the precipi-
tation correlation on a month-by-month basis indicate that Lake
Elva receives approximate three times as much precipitation as
Dillingham.
D. SOILS AND VEGETATION
Soils in the hilly to steep portions of the drainage basin were
formed in a thick mantle of silty volcanic ash over gravelly and
stone materia 1. They occur on the foot s 1 opes of high ridges,
under vegetation that is mainly alder and grasses.
Rough mountainous land consists of areas of bare rock and stony
rubble on high ridges and mountains. It supports little vegetation
other than lichens and a few scattered alpine plants.
The very gravelly, hilly to steep areas of the drainage basin
consist of poorly drained soils, with permafrost occuring on directly
north-facing slopes and in swales on high ridges. The vegetation
is dominantly sedges, mosses, and low shrubs. Beneath a thin peaty
surface mat, the soils consist of mottled dark gray silt loam over
dark gray very gravelly and stony loam. The permafrost is usually
less than 24 inches below the surface.
These very gravelly, hilly to steep areas also have shallow well
-drained soils on high alpine slopes and ridges. The vegetation
consists generally of low shrubs, grasses, and forbs. Typically,
beneath a surface mat of partially decomposed organic material, the
soils have a very dark brown upper horizon formed in very gravelly
silt loam or sandy loam that is less than 20 inches thick over
bedrock.
E. POWER POTENTIAL
The mean runoff rate, developed as described in Para B.1, was 5 cfs
per square mi 1 e of drainage basin, or 52. 5 cfs. The equation,
kWh= 0.07(Q)(MEH)(8760), was used to determine the annual energy
output (kWh) of the project, given the flowrate (Q = 52.5 cfs) and
the mean effective head (MEH = 260 feet).
A-43
Dillingham -Appendix A
APA15/B
The average annual energy output from the project was computed to
be 8,370 MWh. The prime energy is estimated below using Method 2.
Using Method 2, the mean runoff at the damsite over the 20-year
period of synthesized record was found to be 39,440 acre-feet per
year or 54.5 cfs. This would produce average annual energy of
8,689 MWh. Prime annual energy based on the synthetic runoff
record and the 29,000 acre-ft. reservoir would be 7,972 MWh. This
results from a maximum regulated runoff of 50 cfs.
The more conservative amount of average annual energy, calculated
using Method 1 was adopted for use in the power cost studies. The
power and energy that would be provided by the project are summarized
as follows:
Installed Capacity
Prime Capacity
Annual Prime Energy
Average Annual Energy
F. PROBABLE MAXIMUM FLOOD
1. Probable Maximum Precipitation
1,500 kW
910 kW
7,972 MWh
8,370 MWh
The probable maximum precipitation values for the Lake Elva
damsite were determined from references to the U.S. Weather
Bureau Technical Paper #47. This reference cites 24-hour and
6-hour probable maximum precipitation amounts of 14.0 inches
and 9.0 inches respectively. As the drainage area for Lake
Elva is relatively small, no adjustments were made to these
amounts. The 24 and 6-hour precipitation amounts were broken
down into hourly increments and 3 inches of snowmelt were
added proportional to the hourly rainfall increments. The
hourly distribution of rainfall plus snowmelt was then arranged
into the most critical sequence to develop the greatest possible
infow design flood.
2. Inflow Design Flood
According to methods outlined in the U.S. Bureau of Reclamation 1 s,
Design of Small Dams, the hourly probable maximum precipitation
amounts were used to deve 1 op a series of unit hydrographs.
The ordinates of the unit hydrographs were then added to
determine the hourly inflow into the reservoir. The instanta-
neous peak was found to be 15,750 cfs, which was used as a
basis for determining a preliminary spillway size.
A-44
Dillingham-Appendix A
APA15/B
3. Spillway Size
Severa 1 spi 11 way rating curves were deve 1 oped for various
heights and lengths of spillway. The time of concentration
for the Lake Elva drainage basin will significantly attenuate
the peak inflow of 15,750 cfs (Qp).
For a spillway height (h) of 7 feet, an attenuation factor
(AF) of 0.6 and a downstream hazard factor (OHF) of 0.6, it
was determined that the following length (b) spillway would be
required to pass the inflow design flood:
b = (AF) OHF) (Qp)
3.33 (h 1 •5 )
b = (0.50) (0.60) (15,750) = 77 feet
3. 33 (71. 5 )
A 100 foot-long spillway would be adequate to pass the inflow
design flood.
A-45
APA014i J4
TABLE A-6.
LAKE ELVA HYDROELECTRIC PROJECT
MONTHLY DISCHARGE (IN 1000 ACRE-FEET) AT THE DAMSITE
YEAR JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC TOTALS ---
930 0.9 1. 4 1. 7 3.4 5.2 6.9 7.4 7.2 6. 1 4.0 2.3 0.8 47.3
1931 0.5 0.8 1. 0 2.1 3.2 4.2 4.5 4.4 3.8 2.5 1. 4 0.5 28.9
1932 0.7 1.0 1. 2 2.5 3.9 5.1 5.5 5.4 4.6 3.0 1.7 0.6 35.2
1933 0.5 0.8 1. 0 2.0 3. 1 4.1 4.4 4.3 3.6 2.4 1.3 0.4 27.9
1940 0.7 1. 0 1. 3 2.6 4.0 5.2 5.7 5.5 4.7 3.1 1. 7 0.6 36.2
1957 0.7 1.1 1. 4 2.7 4.1 5.4 5.8 5.7 4.8 3.2 1. 8 0.6 37. 1
::» 1958 0.8 1.3 1 .5 3.2 4.9 6.4 6.9 6.8 5.7 3.8 2. 1 0.7 44.2
l 1959 0.6 1. 0 1. 2 2.5 3.8 5.0 5.4 3.2 4.4 2.9 1. 6 0.5 34.2 ~
Q'\ 1960 1. 0 1.5 1.8 3.8 5.8 7.6 8.2 8.0 5.8 4.4 2.5 0.8 52.3
1961 0.8 1. 2 1.4 2.9 4.5 5.9 6.4 6.3 6.3 3.5 2.0 0.7 40.9
1962 0.6 0.9 1.0 2.1 3.3 4.3 4.7 9.5 3.9 2.5 1. 4 0.5 29.7
1963 0.8 1.2 1. 5 3.1 4.7 6. 1 6.7 6.5 5.5 3.6 2.0 0.7 42.4
1964 0.8 1. 2 1. 4 2.9 4.5 5.9 6.3 6.2 5.3 3.4 1. 9 0.5 40.4
1965 0.9 1. 4 1. 7 3.4 5.3 6.9 7.5 7.3 6.2 4.1 2.3 0.8 47.7
1966 0.9 1. 4 1. 7 3.5 5.4 7.1 7.7 7.5 6.3 4.1 2.3 0.8 48.8
1967 0.8 1.2 1.5 3.1 4.8 6.2 6.7 6.6 5.6 3.7 2. 1 0.7 43.1
1973 0.7 1 . 1 1. 3 2.8 4.3 5.6 6.0 5.9 5.0 3.3 1. 8 0.6 38.5
1975 0.7 1. 0 1. 2 2.6 3.9 5.1 5.6 5.4 4.6 3.0 1.7 0.6 35.4
1976 0.9 1.3 1. 6 3.2 5.0 6.5 7. 1 6.9 5.8 3.8 2.2 0.7 45.0
1977 0.6 1. 0 1 . 1 2.4 3.6 4.7 5. 1 5.0 4.3 2.8 1. 6 0.5 .8
Average 0.7 1 . 1 1. 4 2.8 4.4 5.7 6.2 6.0 5.2 3.3 1. 9 0.6 39.4
% of Average
Annual 1. 9 2.9 3.5 I. 2 11 . 1 14.5 15.6 15.3 13.0 8.5 4.8 1.6 100.0
Dillingham -Appendix A
APA15/B
G. REFERENCES
Miller, John F. 1963. Probable Maximum Precipitation -Rainfall
Frequency Data for Alaska, Technical Publication No. 47, U.S.
Weather Bureau, 1963.
Riggs, H. C. December 1969. 11 Mean Streamflow from Discharge
Measurements, 11 Bulletin of the International Association of
Scientific Hydrology Vol. XIV, No. 4.
U.S. Bureau of Reclamation. 1973. Design of Small Dams.
U.S. Department of Commerce, National Weather Service. 1978.
Local Climatological Data-Bethel, Alaska.
U.S. Department of Commerce, National Weather Service. 1974.
Mean Monthly and Annual Precipitation -Alaska, NOAA Technical
Memorandum NWS AR-10.
U.S. Department of Energy, Alaska Power Administration. May 1978.
Draft Appraisal of the Lake Elva Project near Dillingham,
Alaska.
U.S. Weather Bureau. 1966. Probable Maximum Precipitation -
Northwest States, Hydrometeorological Report No. 43.
A-47
Dillingham -Appendix A
APA15/B
GRANT LAKE HYDROELECTRIC PROJECT
A. SUMMARY AND CONCLUSIONS
Stream flow records are available for Grant Lake starting in July
1959 and extending through July 1965. The nearby Nuyakuk River has
stream flow records for water years 1954 through 1978 from which a
longer record for Grant Lake can be synthesized. Based on the six
years of actual records and 19 years of synthetic records, the
average annual flow out of the 37.2 square mile drainage basin of
Grant Lake was determined to be 96.12 cfs. Active storage capacity
of the reservoir is 52,500 acre-ft. The regulated flow is estimated
at 92 cfs.
The capacity and energy that could be provided by the project are
as follows:
Installed Capacity
Prime Capacity
Annual Prime Energy
Average Annual Secondary Energy
Average Annual Energy
2,700 kW
1,385 kW
12,130 MWh
542 MWh
12,672 MWh
The peak inflow rate for the probable maximum flood was calculated
to be 51,000 cfs. A spillway 125 feet wide by 10 feet high will
pass the probable maximum flood.
B. METHOD OF ANALYSIS
The years of record for Grant Lake were tabulated by month and the
average per month was determined. The same calculations were done
for the same period on the Nuyakuk River. The average of each
month for Grant Lake was divided by the average of the same month
for the Nuyakuk River to obtain monthly factors to develop a synthetic
record. Example:
Record Average Grant Lake
Record Average Nuyakuk River
Factor
Oct.
6.40
423.0
. 01513
Nov.
3.70
252.6
.01465
Dec.
2.72
173.5
.01568
In October 1954 the discharge was 363,400 Ac-Ft. at the Nuyakuk
gage. This multiplied by 0.01513 gave a synthetic discharge at
Grant Lake of 5,498 acre-feet for October 1954. Each month of
discharge at the Nuyakuk gage was multiplied by the corresponding
factor to derive the discharge for Grant Lake shown in Table A-6.3.
A-49
Dillingham-Appendix A
APA15/B
The average annua 1 flow from the six years recorded period was
determined to be 94.89 cfs and the average annua 1 flow from
Table A-6.3 is 96.12 cfs.
C. CLIMATE
While there are no weather records available for the Grant Lake
watershed, records are available for Dillingham. The Grant Lake
watershed is in a relatively dry area when compared with nearby
streams that have some or all of their watershed origninating in
the mountains to the west. Grant Lake basin receives a little more
precipitation than does Dillingham; the runoff precipitation being
29.15 inches compared with total precipitation of 25.8 inches at
Dillingham.
Temperature extremes can be expected to be greater at Grant Lake
over those experienced in Dillingham because of the higher elevation
and the distance from the moderating effects of Bristol Bay.
Average temperatures for Dillingham are as follows:
Dillingham Average Temperature (Fo)
Period Min. Mean Max.
January 8.5 15.6 22.9
July 45.6 55.1 64.7
Annual 25.7 34.1 42.5
D. SOILS AND VEGETATION
Soils in the hilly to steep portions of the drainage basin were
formed in a thick mantle of silty volcanic ash over gravelly and
stone material. They occur on the foot slopes of high ridges under
vegetation that is mainly alder and grasses.
Rough mountainous land in the drainage basin consists of areas of
bare rock and stony rubble on high ridges and mountains. It supports
little vegetation other than lichens and a few scattered alpine
plants.
The very gravelly, hilly to steep areas consist of poorly drained
soils with permafrost that occur on directly north-facing slopes
and in swales on high ridges. The vegetation is dominantly sedges,
mosses, and 1 ow shrubs. Beneath a thin peaty surface mat, the
soils consist of mottled dark gray silt loam over dark gray very
gravelly and stony loam.
A-50
Dillingham-Appendix A
APA15/B
These very gravelly, hilly to steep areas also have shallow well
drained soils on high alpine slopes and ridges. The vegetation is
mainly low shrubs, grasses, and forbs. Typically, beneath a surface
mat of partially decomposed organic material, the soils have a very
dark brown upper horizon formed in very gravelly silt loam or sandy
loam that is less than 20 inches thick over bedrock.
E. POWER POTENTIAL
Using the average annual flow of 96.12 cfs as shown on Table A-6.3
and a mean effective head of 215 feet, the average annual energy
was determined to be 12,672,268 kWh. The reservoir capacity of
52,200 acre-ft. represents 75.4% of the average annual runoff. The
regulation provided by this reservoir is estimated to assure a
regulated flow of 92 cfs or 95.7% of the average annual runoff.
This compares to 95.2% estimated at Lake Elva where the reservoir
is 73.5% of the average annual runoff. Under the various scenarios
of the Power Cost Study the load factors of the delivered energy
range from 0.52 to 0.66. Adjusting for some added peaking contrib-
uted by Transmission losses a plant factor 0.51 is conservative.
This plant factor applied to the prime rating of the project provides
a basis for installed capacity. A regulated flow of 92 cfs and a
mean effective head of 215 feet would then produce the following:
Installed Capacity
Prime Capacity
Prime Annual Energy
Average Annual Energy
Secondary Energy
F. PROBABLE MAXIMUM FLOOD
1. Probable Maximum Precipitation
2,700 kW
1,385 kW
12,130 MWh
12,672 MWh
542 MWh
The probable maximum precipitation values for the Grant Lake
damsite were determined from references to the U.S. Weather
Bureau Technical Paper #47. This reference cites 24-hour and
6-hour probable maximum precipitation amounts of 14.0 inches
and 9.0 inches respectively. slight adjustments were made to
these amounts because of the size of the drainage basin. The
24 and 6-hour precipitation amounts were broken down into
hourly increments and 3 inches of snowmelt were added proportional
to the hourly rainfall increments. The hourly distribution of
rainfall plus snowmelt was then arranged into the most critical
sequence to develop the greatest infow design flood.
A-51
Dillingham -Appendix A
APA15/B
2. Inflow Design Flood
According to methods outlined in the U.S. Bureau of Reclamation 1 s,
Design of Small Dams, the hourly probable maximum precipitation
amounts were used to develop a series of unit hydrographs.
The ordinates of the unit hydrographs were then added to
determine the hourly inflow into the reservoir. The instanta-
neous peak was found to be 51,000 cfs, which was used as a
basis for determining a preliminary spillway size.
3. Spillway Size
Several spillwcy rating curves were developed for various
heights and lengths of spillway. The time of concentration
for the Grant Lake drainage basin will significantly attenuate
the peak inflow of 51,000 cfs (Qp).
For a spillway height (h) of 10 feet, an attenuation factor
(AF) of 0.4 and a downstream hazard factor (DHF) of 0.6, it
was determined that the following length {b) spillway would be
required to pass the inflow design flood:
b = (AF) (DHF) (Qp)
3.33 {h 1 •5 )
b = (0.40) (0.60) (51,000) = 116 feet
3. 33 (10 1 • 5 )
A 125 foot-long spillway would be adequate to pass the inflow
design flood.
A-52
APA014/J6
TABLE A-6.2
NUYAKUK RIVER
MONTHLY DISCHARGE (IN 1000 ACRE-FEET) AT THE GAGING STATION
WATER
YEAR OCT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG SEP TOTAL ---
1954 363.4 223.1 166.0 129.1 94.4 86.1 77.4 241.0 616.5 417.7 319.2 332.5 3,066
1955 ' 311.0 363.6 247.7 184.5 133.3 129.1 119.0 206.5 701.6 1256.1 782.5 445.1 4,880
1956 405.3 226.1 147.6 110.7 80.5 79.9 83.3 202.8 992.6 730.3 430.8 552.0 4,042
1957 331.7 198.3 168.0 110.7 77.8 86.1 101.2 295.5 778.3 444.7 237.0 686.9 3,516
1958 461.2 528.7 300.5 190.4 130.7 129.1 122.0 237.0 1184.0 1344.0 704.9 422.4 5,755
1959 384.6 205.3 159.9 141.4 94.4 79.9 83.3 210.0 814.0 670.7 358.8 313.7 3,516
1960 556.4 303.0 196.2 156.5 106.7 89.1 47.6 312.6 990.9 776.4 589.0 420.6 4,545
1961 401.6 332.4 252. 1 195.3 150.0 123.6 101.2 362.2 947.9 766.2 603.8 524.4 4,761
1962 393.6 238.6 134.5 116.6 100.0 98.4 95.2 255.8 930.6 945.1 412.4 318.4 4,039
1963 321.4 208.3 178.3 190.6 177.7 187.0 113.1 218.3 846.5 706.1 387.7 641.1 4,176
1964 412.1 181.9 113.7 85.9 72.0 67.4 65.5 105.7 973.9 844.7 474.7 453.4 3,851
1965 452.8 251.4 166.0 123.0 88.9 104.5 136.9 199.7 1125.0 918.7 569.1 855.3 4 f 991
> 1966 708.7 315.4 190.6 123.0 94.4 98.4 89.3 123.6 648.6 791.6 559.7 516.7 4,260
I 1967 643.6 351.1 240.8 180.7 131.7 123.2 109.1 142.8 671.0 591.8 393.3 391.1 3,970 \JI
\.IJ 1968 369.9 177.1 119.2 96.8 84.1 86.1 83.3 242.4 656.1 448.7 497.9 364.6 3,226
1969 234.7 152.9 134.5 116.0 88.9 92.2 89.3 251.5 1386.0 968.8 403.6 335.2 4,254
1970 705.2 716.6 686.5 465.3 199.1 137.9 119.0 270.3 900.5 805.5 582.3 501.8 6,090
1971 705.2 509.8 234.1 140.4 103.9 104.5 95.2 268.1 900.5 805.5 582.3 500.3 4,950
1972 399.0 272.1 186.1 140.8 104.3 92.0 85.3 153.5 727.3 988.0 490.7 427.7 4,067 1973 415.3 360.9 229.2 161.7 113.9 105.3 91.2 219.3 853.8 991.8 474.6 488.0 4,505
1974 424.3 219.0 146.2 112.7 86.3 92.2 89.9 255.9 704.9 599.4 351.8 386.6 3,469 1975 422.0 272.1 167.4 127.1 100.2 102.3 98.4 232.1 824.7 889.6 432.5 388.3 4,057
1976 475.5 286.0 166.0 109.9 77.6 60.9 53.9 157.7 653.9 667.5 508.0 586.2 3,804
1977 700.8 371.9 244.9 197.8 147.4 124.6 96.6 177.9 1108.0 1612.0 1487.0 586.8 6,856
1978 364.2 223.0 155.1 143.4 115.2 116.8 113.6 696.2 886.2 952.7 542.9 511.3 4,821
Total 11363.5 7488.6 5131.7 3850.3 2753.4 2596.6 2359.8 6038.4 21823.3 20933.6 13176.5 11950.4 109,466
Average 454.5 299.5 205.3 154.0 110. 1 103.9 94.4 241.5 872.9 837.3 527. '1 478.0 4,378.5
25 Year Average = 6,048 cfs.
Drainage Basin = 1,490 square miles
Discharge/sq. mi = 4.06 cfs.
.''\ -, •. ~ ~ Mt-M i-+
TABLE A-6.3
G R A f'< " •. A K E H Y DR 0 E L E C T R I C P R 0 J E C'
MO~·JTHL '1· D:SCHtlf-i...:J (1~-J 1000 ACRE-FEET) AT THE DAMSITP
WATER
YEAR OCT NOV DEC JAN FEB MAR APR MAY J lJ N J lJ L AUG SEP TOTAL ----------
1954 5.50 3.27 2.60 2.25 1 . 1.35 1. 36 10.15 10.89 3.70 4.15 5.03 52.04
1955 4.71 5. 3.88 3.21 2.53 2.02 2.09 8.70 12.40 11 . 12 10.18 6.73 72.90
1956 6.13 3.31 2.31 1. 93 1 . 1. 25 1. 46 8.54 17.54 6.46 5.60 8.35 64.41
1957 5.02 2.91 2.63 1. 93 1. 48 1.35 1. 78 12.45 13.75 3.94 3.08 10.39 60.71
1958 6.98 7.75 4.71 3.32 2.48 2.02 2.14 9.98 20.92 11.89 9.17 6.39 87.75
1959 5.82 3.01 2.51 2.46 1. 79 1. 25 1. 46 8.84 14.38 5.94 4.67 4.74 56.87
1960 5.96 2.46 1. 22 0. 77 0.55 0.49 1. 01 14.59 14.19 9.38 12. 15 6.22 68.98
1961 6.16 5.86 3. 77 2.39 1. 56 1.29 1.13 15.97 12.27 4.17 6.45 7. 68.75
1962 7.99 4.46 2.60 2.40 2.05 1.78 1 . 8.63 21.75 7.17 2.71 3. 67.27
1963 5.01 3.34 3.26 4.87 5.39 3.59 2.23 9.29 11.74 5.83 6.00 12.14 72.69
1964 7.15 2.03 2.37 1. 96 1.58 1.32 1. 07 1. 24 12.30 6.81 4.77 5.61 48.21
1965 6. 11 4.05 3.07 2.71 2.05 2.03 2.63 11.52 30.44 9.53 7. 40 12.93 94.47
;J.> 1966 10.72 4.62 2.99 2.14 1. 79 1. 54 1.57 5. 21 11.46 7.01 7.28 7.81 64.14
0, 1967 9.74 5.14 3.78 3.15 2.50 1. 93 1. 92 6. 01 11.86 5.24 5.12 5.91 62.30
~ 1968 5.60 2.59 1.87 1. 69 1. 60 1.35 1.46 10.21 11.59 3.97 6.48 5.51 53.92
1969 3.55 2.24 2.11 2.02 1. 69 1.44 1.57 10.59 24.49 8.57 5.25 5.07 68.59
1970 10.67 10.50 10.76 8.11 3.78 2.16 2.09 11.39 15.91 7.13 7.58 7. 97.67
1971 10.67 7.47 3.67 2.45 1. 97 1.64 1. 11.29 15.91 7.13 7.58 7.56 79.01
1972 6.04 3.99 2.92 2.45 1. 98 1 .44 1. 50 6.47 12. 8.74 6.38 6.47 62.23
1973 6.28 5.29 3.59 2.82 2.16 1.65 1.60 9.24 15.09 8.78 6.17 7.38 70.05
1974 6.42 3.21 2.29 1. 96 1. 64 1 .44 1.58 10.78 12.46 5.30 4.58 5.85 57.51
1975 6.38 3.99 2.62 2.21 1. 90 1. 60 1.73 9.78 14.57 7.87 5.63 5.87 64.15
1976 7.19 4.19 2.61 1. 91 1.47 0.95 0.95 6.64 11.55 5. 91 6.61 8.86 58.84
1977 10.60 5.45 3.84 3.45 2.80 1. 95 1.70 7.49 19.58 14.27 19.35 8.87 99.35
1978 5.51 3. 2.43 2.50 2.19 1.83 2.00 29.32 15.66 8.43 7.06 7.73 87.93
Total 171.91 109.73 80.41 67.06 52.25 40.66 41. 254.32 385. 184.29 171.4 180.68 1, 739.75
Average 6.88 4.39 3.22 2.68 2.09 1 .63 1.66 10.17 15.41 7.37 6.86 7. 69.59
*Actual U.S.G.S. Records: July 1959 through July 1965 69,590 Ac-Ft 96.12 ds
Recor·d Ave. 6.40 3.70 2. 72 2.52 2.20 1. 75 1. 64 10.21 17. 12 7 15 6.42 7.13 68.96
Nuyakuk Ave. 423.0 .6 173.5 144.7 1 15.9 111 . 7 93.3 242.4 969.1 S07.7 493.5 471.6 4299
Factor .01513 .01568 iJ -42 Oli398 .01567 .01758 .04212 . 01 7 00885 . 01301 . 015'12
Dillingham-Appendix A
APA15/B
G. REFERENCES
Miller, John F. 1963. Probable Maximum Precipitation -Rainfall
Frequency Data for Alaska, Technical Publication No. 47, U.S.
Weather Bureau, 1963.
Riggs, H. C. December 1969. 11 Mean Streamflow from Discharge
Measurements. 11 Bulletin of the International Association of
Scientific Hydrology Vol. XIV, No. 4.
U.S. Bureau of Reclamation. 1973. Design of Small Dams.
U.S. Department of Commerce, National Weather Service. 1978.
Local Climatological Data-Bethel, Alaska.
U.S. Department of Commerce, National Weather Service. 1974.
Mean Monthly and Annual Precipitation -Alaska, NOAA Technical
Memorandum NWS AR-10.
U.S. Weather Bureau. 1966. Probable Maximum Precipitation -
Northwest States, Hydrometeorological Report No. 43.
A-55
Dillingham -Appendix A
APA15/B
TAZIMINA HYDROELECTRIC PROJECT
A. SUMMARY AND CONCLUSIONS
Tazimina damsite currently has no gaging data. Based on flow data
from other streams in the area, a 4.5 cfs per square mile mean
discharge is used for the Tazimina drainage basin. A storage dam
constructed for a maximum water surface elevation of 675 feet would
provide active storage of 86,000 acre-ft. The 320 sq. mi. drainage
basin would deliver an annual average runoff of 1,031,000 acre-ft.
The relatively small reservoir can provide regulation to assure a
flow of 700 cfs. for the first stage operating conditions. The
capacity and energy that could be provided from the project are as
fo 11 ows:
Stage I Stage II
Installed Capacity 18,000 kW 36,000 kW
Prime Capacity 9,000 kW 12,700 kW
Annual Prime Energy 78,840 MWh 111,252 MWh
Annual Secondary Energy 59,120 MWh 47,689 MWh
Annual Total Energy 137,960 MWh 158,941 MWh
The peak inflow rate for the probable maximum flood was calculated
to be 250,000 cfs. A spillway 325 feet long by 15 feet high would
be required to pass the inflow design flood.
B. METHOD OF ANALYSIS
There is no stream gaging information available for Tazimina River.
Two methods were used to determine the probable amount of water
available for power generation at the Tazimina damsite.
1. Method 1
A conservative runoff figure of 4.5 cfs per square mile was
found to be representative of discharges from similar gaged
streams in the area. For the 320 square mile drainage basin,
this would be a mean flow of 1440 cfs.
2. Method 2
Weather records for Iliamna have been maintained for over
20 years. Using this weather data a 20 year synthetic month-
by-month record was established for the Tazimina River damsite.
A-57
Dillingham-Appendix A
APA15/B
Reference was made to the NOAA Technical Memoradum NWS-AR 10
to determine, from the isohyets, a set of probable monthly
correlation coefficient from Iliamna to the Tazimina River.
Recorded temperature data at Iliamna was used as a basis for
distributing the monthly precipitation into monthly runoff at
the dams ite. A 20-year synthetic discharge record was made
for the Tazimina damsite (Table A-6.4). The discharges were
reduced by 10 percent to account for evaporation and other
1 osses. The resulting mean annua 1 runoff was computed to be
1425 cfs, corresponding quite cose ly to the mean discharge
obtained using Method 1.
Using the monthly flow data, a mass hydrograph was constructed
for the 20-year synthetic record. The mass hydrograph was
used in conjunction with the 86,000 acre-ft. of active storage
to compute the flow which could be sustained throughout the
record period. A regulated minimum flow of 750 cfs was found
by this method for the 1st stage. A conservative figure of
700 cfs. is established for use in this 1st stage analysis.
By providing an active storage of 247,000 acre-ft. in the
Stage II development an average regulated flow of 1,008 cfs.
is estimated.
C. CLIMATE
There are no weather recording stations at the Tazimina River
damsite. However, it can be anticipated that climatic conditons at
the damsite are more severe, with greater temperature extremes and
larger amounts of precipitation than at Iliamna. Because of the
proximity of large bodies of water, the climate of this community
is variable between continental and marine in nature. Temperature
extremes reflect both climates, with a summer high of 91° and a
winter low of minus 47°. Neither values would normally fit with
the monthly means which show considerable moderation from the
maritime influence. Therefore, Iliamna is usually placed in the
Transition Climatic Zone. The seasonal freeze free period averages
124 days each year, generally extending from late May to late
September.
D. SOILS AND VEGETATION
The dominant soi 1 s on foot s 1 opes and moraines formed in very
gravelly glacial till capped with a shallow mantle of silty volcanic
ash. They support a forest of white spruce and paper birch or, on
more gentle slopes, a dense forest of black spruce. On high ridge-
tops and slopes above tree line most of the soils are shallow over
bedrock and support vegetation dominated by dwarf birch, other low
A-58
Dillingham-Appendix A
APA15/B
shrubs, willow, alder, grasses, and mosses. In muskegs, which
commonly occur in depressions and on valley bottoms (between the
hills), the soils consist of very poorly drained fibrous peat with
a shallow permafrost table. The vegetation in these areas is
predominantly sedges and mosses.
Higher elevations are barren or have a sparse cover of low alpine
plants. Most lower slopes support a more dense, (dominantly)
shrubby vegetation. Black spruce forests occur in some valley
bottoms.
Rough mountainous land consists of barren rocky peaks and ridges,
stony and bouldery slopes with little or no vegetation, and very
shallow and stony soils with sparse alpine vegetation. Many of the
peaks formerly were ice covered and exhibit features characteristic
of glaciated areas.
E. POWER POTENTIAL
Using Method 1, as described in Para. 8.1 the 320 square mile
drainage basin with a mean discharge 4.5 cfs per square mile would
yield a mean annual flow of 1440 cfs. Using the equation
kWh = 0.07(Q)(MEH) with 700 cfs (Q) minimum regulated flow (Method 2)
at a mean effective head (MEH) of 184 feet, the project would
deve 1 op 9, 000 kW or 78,840 MWh of prime energy in the Stage I
development. Stage II development would utilize the total amount of
water available and produce 111,252 MWh of prime energy and
47,689 MWh of average secondary energy annually.
For the purpose of the preliminary analysis of the hydroelectric
potential of the Tazimina project the capacity and energy figures
are computed using Method 1, for average annual energy and Method 2
for the estimate of minimum regulated flow.
Under the various scenarios of the power requirements study the
load factors of the delivered energy range from .52 to .66. Adjusted
for some peaking contribution by transmission losses a plant factor
of .5 is conservative. This plant factor applied to the prime
rating of the project provides the basis for installed capacity for
Stage I. Annual total available energy has been used for Stage II
to determine the total installed capacity.
The capacity and energy which can be provided by the Tazimina
project are summarized as follows:
A-59
Dillingham-Appendix A
APA15/B
Installed Capacity
Prime Capacity
Annual Prime Energy
Annual Secondary Energy
Annual Total Energy
F. PROBABLE MAXIMUM FLOOD
1. Probable Maximum Precipitation
Stage I
18,000 kW
9,000 kW
78,840 MWh
59,120 MWh
137,960 MWh
Stage II
36,000 kW
12,700 kW
111,252 MWh
47,689 MWh
158,941 MWh
Probable maximum precipitation amounts for the Tazimina damsite
were determined from references to the U.S. Weather Bureau
Technical Paper #47. This source cites 24 hour and 6 hour
Probable Maximum Precipitation amounts of 16.0 and 9.5 inches,
respectively. In accordance with methods outlined in this
source, these precipitation values were adjusted to reflect
the size of the Tazimina drainage basin. These values were
then broken down into hourly increments, assuming a total of
3 inches of snowmelt would occur in addition to the probable
maximum precipitation. This hourly distribution was then
arranged into the most critical sequence to determine the
greatest possible inflow design flood.
2. Inflow Design Flood
According to methods outlined in the U.S. Bureau of Reclamation's,
Design of Small Dams, the probable maximum precipitation was
used to develop a series of unit hydrographs. The sum of the
ordinates of the unit hydrographs provided the probable maximum
inflow of water into the reservoir. The instantaneous peak
inflow was calculated to be 250,000 cfs.
3. Spillway Size
For the purpose of preliminay s1z1ng of an adequate spillway
to pass the inflow design flood, a spillway rating curve was
constructed for several spillway sizes. Because of the length
of the drainage basin (large time of concentration) the peak
of the inflow design flood will be significantly attenuated.
For a spillway height (h) of 15 feet, using an attenuation
factor (AF) of 40% and a downstream hazard factor (DHF) of
60%, it was determined that the following width (b) would be
required to pass the inflow design flood:
A-60
Dillingham-Appendix A
APA15/B
b = (AF) (DHF) (Peak Inflow Rate)
3.33 (H 1 •5 )
b = (0.40) (0.60) (250,000) = 310 feet
3.33 (15 1 •5 )
A 325 foot-wide spillway would be adequate to pass the inflow
design flood.
A-61
AP;..01~ J2
YE R JAN FEB --
1949 15.0 21.6
1950 14.3 20.6
1951 15.8 22.9
1952 17.1 24.8
1953 17.3 25.0
1954 17.5 .3
1955 19. 1 27.6
1956 14.2 20.5
1957 13.5 19.5 :r 1958 16.2 23.4
~ 1959 14.3 20.6
1960 20.0 28.9
1961 26.3 38.0
1962 12.4 18.0
1963 16.6 24.0
1964 18.1 26.2
1965 19.0 27.5
1966 15.9 23.0
1967 25.4 36.7
1968 10.3 14.9
Average 16.9 24.5
% of Average
Annual 1. 6 2.4
TABLE A-6.4
TAZIMINA RIVER HYDROELECTRIC PROJECT
MONTHLY DISCHARGE (IN 1000 ACRE-FEET) AT THE DAMSITE
MAR APR MAY JUN JUL AUG SEP OCT --
29.6 66.9 102.4 131.2 144.9 142.0 120.3 80.1
28.2 63.7 97.6 125.0 138.0 1 .3 114.6 76.3
31.3 70.7 108.3 138.7 153.2 150.2 127.2 84.6
.9 76.6 1'17.3 150.2 165.9 162.7 137.8 91.7
34.2 77.4 118.5 151.8 167.7 164.4 139.2 92.7
34.5 78.1 119.6 153.2 169.2 165.9 140.5 93.5
37.7 85.3 130.5 167.2 184.7 181.0 153.4 102.0
28.0 63.3 96.9 124.1 137.1 134.4 113.8 75.7
26.6 60.2 92.1 118.0 130.3 127.7 108.2 72.0
32.0 72.3 110.7 141.7 156.5 153.5 130.0 86.5
28.2 63.8 97.7 125.1 138.2 135.5 114.7 76.4
39.5 89.3 136.7 1 . 1 193.3 189.6 160.6 106.8
51.9 117.5 179.9 230.3 254.4 249.4 211.3 140.6
24.6 55.6 85.1 109.0 120.3 118.0 99.9 66.5
32.8 74.1 113.4 145.3 160.4 157.3 133.2 88.7
35.8 81.0 123.9 158.7 1 .3 171.9 145.6 96.9
37.6 85.0 130.2 166.7 184.1 180.5 152.9 101.7
31.4 71.1 108.9 139.5 154.0 151.0 127.9 85.1
50.1 113.4 173.6 222.3 245.5 240.7 203.9 135.7
20.4 46.1 70.6 90.4 99.9 97.9 82.9 55.2
33.4 .6 115.7 148.2 163.6 160.4 135.9 90.4
3.2 7.3 11.2 14.4 16.9 15.6 13.2 8.8
NOV DEC TOTALS
46.8 12.0 912.8
44.6 11 . 5 869.7
49.5 12.7 965.1
53.6 13.8 1,045.4
54.2 13.9 1,056.6
64.7 14.1 1, 066.1
59.7 15.4 11163.6
44.3 11.4 863.7
42.1 10.8 821.0
50.5 13.0 986.4
44.7 11.5 870.7
62.5 16. 1 1,218. 4
82.2 21.2 1,603.0
38.9 10.0 758.3
51.9 13.3 1, 011.0
56.7 14.6 1,104.7
59.5 15.3 1,160.0
49.8 12.8 970.4
79.4 20.4 1, 547. 1
32.3 8.3 629.2
52.9 13.6 1,031.0
5.1 1. 3 100.0
Dillingham -Appendix A
APA15/B
G. REFERENCES
Miller, John F. 1963. Probable Maximum Precipitation -Rainfall
Frequency Data for Alaska, Technical Publication No. 47, U.S.
Weather Bureau, 1963.
Riggs, H. C. December 1969. "Mean Streamflow from Discharge
Measurements, "Bulletin of the International Association of
Scientific Hydrology Vol. XIV, No. 4.
U.S. Department of Commerce, National Weather Service. 1978.
Local Climatological Data-Bethel, Alaska.
U.S. Department of Commerce, National Weather Service. 1974.
Mean Monthly and Annual Precipitation -Alaska, NOAA Technical
Memorandum NWS AR-10.
U.S. Bureau of Reclamation. 1973. Design of Small Dams.
U.S. Weather Bureau. 1966. Probable Maximum Precipitation -
Northwest States, Hydrometeorological Report No. 43.
A-63
APPENDIX B
COST ESTIMATES
... . .
Dillingham -Appendix B
APAOll/G
l. Transmission Systems
APPENDIX B
COST ESTIMATES
a. 138 kV Three Phase Overhead Line
REA Standard design, average span 1000 1
Structures, 5 @ $5000
Conductor 556 MCM ACSR, 17000 1 @ $500/1000 1
Line Hardware & Anchors $1000/Structure
Survey
Clearing 30% @ $1500/1000 1
Freight
Labor 900 manhours @ $50
Engineering 12%
Use
NOTE: Right-of-Way is not included.
b. Transmission/Distribution Substation
Transformer 12/16/20 MVA
Switchgear
Bus Structure & Hardware
Freight
Labor 1500 manhours @ $50
Engineering 10%
Real Estate
For 40 MVA Transformer Add
B-1
Use
1979 le
$25,000.00
8,500.00
5,000.00
8,000.00
2,376.00
5,000.00
45,000.00
$98,876.00
12,000.00
($110,876.00)
1979 -$
$180,000.00
60,000.00
40,000.00
15,000.00
75,000.00
$370,000.00
37,000.00
$407,000.00
25,000.00
($432,000.00)
$450.000.00
$150,000.00
Dillingham-Appendix B
APAOll/G
c. Single Wire Ground Return Up To 40 kV
d.
2 Pole Structures, 800' Spans
Structures, 7@ $180 (local timber)
Conductor 7#8 Alumoweld 5300', $500/1000'
Line Hardware
Survey
Clearing 20%/mile@ $700/1000'
Freight
Local Labor 250 manhours @ $20
Engineering
For Conductor 4/0 ACSR add:
7 Structures and Hardware
Conductor $250/1000'
Labor
For river crossings, bog shoes and
additional Use
labor in difficult terrain add
Use
NOTE: Right-of-Way is not included.
Terminal for Single Wire Ground Return
Transmission Up To 40 kV
Ground Grid
20, 20 1 deep rods interconnected with
about 1000 1 of wire
Labor 50 manhours @ $20
Transformer, 10, up to 1 MVA including
shipping and installation
Switchgear and Protection
Engineering
Use
B-2
Per Mile
1979 $
$1,260.00
2,650.00
1,600.00
2,000.00
739.00
600.00
5,000.00
$13,849.00
1,000.00
($14,849.00)
~_15, OQ.Q_:_QQ
$2,860.00
1,320.00
5,000.00
$9,180.00
9,500.00
i~_QQO.QQ
1979
$1,500.00
1,000.00
22,000.00
5,000.00
$29,500.00
5,000.00
($34,500.00)
$35,000.00
Dillingham -Appendix B
APAOll/G
e. 24.9 or 12.5 kV Three Phase Overhead Line
REA Standard design, average span 300'
Poles 40' high, 17 @ $500
Conductor 4/0 ACSR, 24000' @ $120/1000'
Line hardware $250/pole
Survey
Clearing 30%/mile, $700/1000 ft.
Freight
Contract Labor 550 man hours @ $50
Supervision & Inspection 5 days @ $500
Engineering 10%
Use
1979 $/mile
$8,500.00
2,880.00
4,250.00
2,500.00
1,102.00
2,500.00
27,500.00
2,500.00
$51,732.00
5,200.00
($56,932.00)
~9"-~Q_QQ,.,QQ
If local labor can be used at an estimated rate of $25/manhoUl'
the cost/mile can be reduced as follows:
+ 550 hours@ $25.00
+ additional supervision
Engineering
Use
f. 25 kV Cable
4/0 Cu, 10, armored @ $5,000/1000'
(including terminators,
Labor 110 man hours @ $50
Freight 26000 lbs. @ $.14/lb.
Engineering
B-3
Use
etc.)
$51,732.00
(27,500.00)
13,750.00
1,250.00
$39,232.00
5,200.00
($44,432.00)
~fE~Q 9.~:9:9
1979 $/mile
$79,200.00
5,500.00
3,640.00
$88,340.00
1,000.00
$89,340.00
liQ~CLQJt2JJ
Dillingham -Appendix B
APAOll/G
2. Wind Generating Equipment
a. 1.5 kW windplant with induction generator
and control (Enertech 1500)
Tower including 60-3 pole, pole top adaptor
guy wires and anchors (4)
Control anemometer wire, 400'
Freight 4000 lbs. @ $17/100 lbs.
Installation 100 manhours@ $50
b. 15 kW windplant with induction-generator
(Grumiman WS-33)
Tower 40', steel
Control Anemometer wire 400'
Freight 8,000 lbs at $17/100 lbs
Installatin 200 man hours @ $50.00
Use
3. Frequency and Phase Conversion
1979 $
$ 2,900.00
800.00
60.00
680.00
5!000.00
$ 9,440.00
$ 29,000.00
2,000.00
60.00
1,360.00
10,000.00
$(42,420.00)
(50,000.00)
a. Single Wire Ground Return Low Frequency Transmission Up To 80 kV
2 Pole Structures, 500' Spans
Structures, 11 @ $300 (imported timber)
Conductor 266.8 ACSR, 5,300' @ $750/1000'
Line Hardware
Survey
Clearing 20%/mile $700/1000'
Freight
Labor 250 manhours @ $50(contract labor)
Engineering 10%
to account for river crossings,
bog shoes etc.
Use
B-4
Per Mile
1979
$ 3,300.00
3,975.00
5,500.00
2,000.00
739.00
1,500.00
12,500.00
$29,514.00
2,951.00
($32,465.00)
$40,000.00
Dillingham-Appendix B
APAOll/G
b. Phase and Frequency Conversion Equipment
( i) Low frequency (25 Hz) to high frequency
(60 Hz) and 10 to 30 for 1 to 2 MW
per terminal (manufacturer's data:
ASEA, Sweden)
Plus freight & engineering, contingencies
( i i) Phase conversion equipment 10 to 30
estimate
B-5
$
$
$
1979 $
Per kW
200.00
100.00
300.00
150.00
APPENDIX C
ECONOMIC EVALUATION
DETAIL SHEETS
Dillingham-Appendix C
APA018/H
LIST OF ALTERNATES
APPENDIX C
ECONOMIC EVALUATION
DETAIL SHEETS
Dillingham System-Diesel Only
Naknek System -Diesel Only
Small Communities -Diesel Only
Dillingham/Naknek/10 Villages -
Central Diesel Only
Dillingham System-W. Lake Elva
Dillingham System-W. Grant Lake
Dillingham System -W. Lake Elva &
Grant Lake
Dillingham/Naknek/10 Villages -
Lake Elva + Grant Lake
Intertied System -(15 Communities)
Lake Tazimina
Intertied System -(15 Communities)
Lake Elva + Lake Tazimina
C-1
Low Load High Load
Growth Growth
Alternate Alternate
1-A
2-A
3-A
4-A
5-A 5-B
6-A 6-B
7-A 7-B
8-A 8-B
9-A 9-B
10-A 10-B
Dillingham -Appendix C
APA018/H
PARAMETERS USED FOR THE ECONOMIC EVALUATION
POWER DEMAND AND ENERGY REQUIREMENTS
The data listed in Section II have been utilized. A system loss
rate of 10% has been added to the energy sold. The listed demands
have been used as coincident, although it is expected that in an
intertied system a coincident factor of .98 or .99 is likely to
occur. Since energy and power requirements had to be interpolated,
small round off errors may exist between alternates involving
different groupings of communities.
ENERGY SOURCES AND SUPPLY
Firm capacity is assured by assuming the largest unit in the system
is non-operational. For alternates including intertied systems,
full diesel capacity has been maintained in the small communities.
Energy supp.ly in intertied systems has been assumed by the central
utilities exclusively. In alternates including hydropower, the
prime energy available has been applied to the annual requirements.
Load duration curves have not been utilized since it is assumed
that the system will be summer peaking, when the available hydro
energy is highest also and can be fully utilized. Supplemental
diesel generation has been used to supply peak demand where necessary.
Transmission losses for the hydropower have been assumed at 3.5%.
SWGR transmission losses have not been taken into account since
they are calculated at less than 1% of the total system load.
Firm capacity has been established according to the following
parameters:
• Local diesel generation: Total installed capacity minus the
largest installed unit.
• Central diesel generation with SWGR interties: Total installed
capacity minus the largest installed unit in the central
utility minus the tie-line.
• Hydroelectric Power Potential: Total installed capacity minus
the hydro p 1 ant (if only connected to the system by one
transmission line), minus small communities connected by SWGR
1 i nes.
BASE YEAR
All cost data as outlined below is for the base year of 1979.
C-2
Dillingham-Appendix C
APA018/H
EXISTING PLANT VALUES
Dillingham and Naknek-taken from the respective REA Form 7a as of
December 1978.
Village Plants -Estimated at $870 per installed kW.
INFLATION
Fuel Costs
An inflation rate of ten percent per year is used thru 1984. The
inflation rate is then decreased to six percent per year for the
remainder of the study.
All Other Costs
An inflation rate of eight percent per year is used thru 1984 for
all other costs (i.e. labor, construction, maintenance, etc.). The
rate is then decreased to four percent per year for the remainder
of the study.
INSURANCE
A single insurance rate of $3.00/$1,000 invested is applied to all
investments. This rate is inflated as stated above.
LABOR
The present production plant labor costs were determined from
utility records for the communities of Dillingham and Naknek; and
were estimated at $20,000 per year for each of the small communities
included in the study. Taxes, insurance and all fringe benefits
were included. For each 4,000 kW diesel plant addition an additional
plant operator salaried at $40,000/year (include benefits, etc.) is
assumed. Plant operations are not required for Lake Elva/Lake
Grant projects. A single plant operation is assumed for the Lake
Tazimina project. Labor costs have been inflated as stated above.
Labor costs for the intertied systems (Cases 4A, 7A, 78, 8A, 88,
9A, and 98) are for the first two years the sum of the labor costs
for the separate Di 11 i ngham system, the Naknek system and the
villages. Within two years after these electric systems are
intertied, the village operator positions become superfluous. At
this point labor costs for the system drop.
C-3
Dillingham-Appendix C
APA018/H
FUEL COST
The fuel costs as of November 1979 were:
(1) Dillingham-$0.819/gallon
(2) Naknek -$0.810/gallon
(3) Villages -$1.60/gallon (average)
These prices are inflated as previously mentioned.
GENERATION FUEL EFFICIENCIES
The following assumptions are made in regard to fuel cost cal-
culation and usage.
(1) Heat content of 138,000 BTU/gallon of diesel fuel.
(2) A generating efficiency of 8.0 kWh/gal in the villages.
(3) A generating e'fficiency of 13.0 kWh/gal i~ Dillingham and
Naknek.
LUBE_OIL, GREASE AND OPERATING SUPPLIES
Calculated as 10% of fuel cost.
DI~~-:~_':.11JliJHENANCE MATERIALS (REPAIR MATERIALS)
Estimated at $6.77/M'.-Ih generated in Dillingham and Naknek and
$10.16/MWh in the villages. These estimates are based on utility
records. Inflation rates have been applied as listed.
HYDRO MAINTENANCE MATERIALS
Estimated at $0.60/MWh generated. Estimates are based on Alaskan
ut i1 i ty records.
DIESEL PLANT COST
Cost of installing diesel generation is estimated at $870 per
installed kW. These unit costs represent installed cost as
experienced lately in the state. An inflation rate has been applied
for future installations.
C-4
Dillingham -Appendix C
APA018/H
HYDRO PLANT COST
See Section III.
DEBT SERVICE
Debt Services on new investments have been calculated using 2, 5, 7
and 9 percent costs of money. An amortization period of 35 years
is used in all case.
DISCOUNT RATE
A discount rate of 7% has been used in all cases for present worth
calculations.
C-5
FUEL COST Tables
APA012/N2
Year
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
inflated
FUEL COST
for DILLINGHAM AREA
in dollars/gallon
Dillingham Naknek Villages
.819 . 81 1.60
.90 .89 1.76
.99 .98 1.94
1.09 1. 08 2.13
1.20 1.19 2.34
1. 32 1.30 2.58
1.40 1.38 2.73
1.48 1.47 2.90
1. 57 1.55 3.07
1. 67 1.65 3.25
1. 77 1. 75 3.45
1.87 1.85 3.66
1. 98 1. 96 3.87
2.10 2.08 4.11
2.23 2.20 4.35
2.36 2.34 4.61
2.50 2.48 4.89
2.65 2.62 5.19
2.81 2.78 5.50
2.98 2.95 5.82
3.16 3.13 6.18
3.35 3.31 6.55
10% through 1984
6% thereafter
C-6
Dillingham-Appendix C
APA018/H
EXPLANATION OF COMPUTER PRINTOUTS
The following is a line by line explanation of the enclosed computer
printouts.
DESCRIPTION
1. Load Demand
Demand -kW
Energy -MWh
2. Sources -kW
A. Existing Diesel
Location or Unit 1-12
B. Additional Diesel
Unit 1-6
C. Existing Hydro
Unit 1-6
D. Additional Hydro
Unit 1-3
Total Capacity -kW
Largest Unit
Firm Capacity
Surplus or (Deficit) -kW
Net Hydro Capacity -MWh
Diesel Generation -MWh
3. Investment Cost ($1000)
1979 Do 11 a rs
A. Existing Diesel
C-7
EXPLANATION
Projected peak load in kW
Projected Energy Requirement in MWh
Existing diesel units in kW
Diesel Additions in kW and year added
Existing Hydro units in kW
Hydro additions in kW and year added
Sum of lines A, B, C, D above
Largest installed unit
Total capacity less largest unit
Surplus or deficit in existing generation
capacity
Net annual MWh available from hydro
generation
Diesel Generation in MWh required to
supply load enegy. Calculated as
Load energy (MWh) less net hydro
capacity (MWh), unless diesel
generation is required to supply
system peak demands.
Cost of existing diesel units in 1979
dollars
Dillingham-Appendix C
APA018/H
DESCRIPTION EXPLANATION
B. Additional Diesel Cost of additional diesel units in 1979
Units 1-6 dollars
C. Existing Hydro Cost of existing hydro units in 1979
dollars
D. Additional Hydro Cost of additional hydro units in 1979
Units 1-B dollars
E. Transmission Plant Cost of transmission plant additions in
Unit 1-2 1979 dollars
F. Miscellaneous Addition Cost of miscellaneous additions in 1979
Unit 1-2 dollars
Total ($1000) 1979 Dollars
Inflated values
4. Fixed cost ($1,000)
Inflated values
A.
8.
Debt Service
1. Existing
2. Additions
Subtotal 2%-9%
Insurance
Total Fixed Cost ($1000)
2% -9%
5. Production Cost ($1000)
Inflated value
A. Operation and Maint.
1. Di ese 1
2. Hydro
C-8
Sum of lines A through F above
Sum of Lines A through F above
adjusted for inflation
Existing debt service on investments
Debt service calculated on inflated new
additions using 2, 5, 7, and 9% cost
of money.
Calculated as $3/$1000 invested
(inflated values)
Sum of Debt Service Existing, Debt
Service Additions Insurance and
Taxes Production Plant
Sum of yearly labor cost related to
diesel generation and diesel main-
tenance cost. Sum of yearly labor
or cost related to hydro generation
and hydro maintenance cost
Dillingham -Appendix C
APA018/H
"" B.
DESCRIPTION
Fuel Oil and Lube
Total Production Cost
($1000)
Total Annual Cost ($1000)
2% -9%
Energy Requirements -
MWH
Mills/kWh
2%-9%
c. Present Worth
Annual Cost ($1000)
2%-9%
D. Accumulated Annual
Cost ($1000) 2%-9%
E. Accumulated Present
Worth Annual Cost
($1000) 2%-9%
F. Accumulated Present
Worth of Energy
Mi 11 s/kWh 2%-9%
C-9
EXPLANATION
Sum of fuel oil and lube oil cost.
Lube oil cost is assumed as 10% of
fuel oil cost. Fuel oil cost is
calculated by dividing Diesel Genera-
tion (kWh) by generation. Fuel
efficiency in kWh/gal. and multiplying
result by the fuel oil cost in $/gal.
Sum of Diesel and Hydro Operation and
Maint., and Fuel and Lube Oil cost
Sum of total fixed cost and total
production cost
Project energy requirements in MWh
same as line 1, load energy-MWh
Obtained by dividing total annual
cost by energy requirements in
MWh and multiplying by 1000
Present worth of total annual cost
2%-9%
Accumulated total of annual cost
2%-9%
Accumulated total of the present worth
of annual costs. 2%-9%
Accumulated total of the present
worth of annual energy cost in
mills/kWh. 2%-9%
POWER COST STUDY
ALTERNATE 1-A
DILLINGHAM -DIESEL -Ll~ LOAD
1979 1960 1961 1962 1963 1964 1965 1966 1987 1988 1989
I • LOAD DEMAND
DEI'IAND -KW 1.400 1.~oo 1.608 1' 716 1.624 1.932 2.040 2.148 2.256 2.36:5 2.472
ENERGY -MWH 5,9:58 6.523 7.088 7.654 8.219 8.764 9.350 9.915 !0.480 1!.046 II, 612
2, SOURCES -KW
A. EXISTING DIESEL
LOCATION OR UNIT 1 2.600 2.600 2.600 2.600 2.600 2.600 2.600 2.600 2.600 2.600 2.600
2
3
4
:5
6
7
a
9
10
11
12
13
B. ADDITIONAL DIESEL
UNIT! -1.ooo t.ooo t.ooo t.ooo 1.ooo 1.ooo 1.000 t.ooo 1.ooo t.ooo
2
3
4
:5
C. EXISTING HYDRO
UNIT 1
2
D. ADDITIONAL HYDRO
UNIT! --- -
------------------
TOTAL CAPACITY -KW 2.600 3.600 3.600 3.600 3.600 3.600 3.600 3.600 3.600 3.600 3.600
LARGEST UNIT 1.ooo 1. 000 t.ooo 1.000 t.ooo t.OOO 1.ooo t.ooo 1.ooo t.ooo t.ooo
FIRM CAPACITY 1o600 2.600 2.600 2.600 2.600 2.600 2.600 2.600 2.600 2.600 2.600
SURPLUS OR I DEFICIT! -KW 200 1.100 992 684 776 666 560 452 344 23:5 128
NET HYDRO CAPACITY -MWH
DIESEL GENERATION -MWH :5.956 6.:523 7.oa8 7.654 6.219 8,784 9,350 9,915 !0.460 11.046 11.612
1-A
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000
1 • LOAD DEI'tAND
DEl'IAND -KW 2.~ 2.687 2.794 2.901 3.008 3,115 3.220 3.327 3.434 3.541 3.650
ENERGY-..... 12.177 12.716 13.25:5 13.794 14.334 14.873 15.412 15.951 16.490 17.030 17.569
2. SOURCES -KW
A. EXISTING DIESEL
LOCATION OR UNIT I 2.600 2.600 2.600 2.600 2.600 2.600 2.600 2.600 2.600 2.600 2.600
2
3
4
:5
6
7
8
9
10
11
12
13
B. ADDITIONAL DIESEL
UNIT I 1,000 1.000 1.ooo 1.000 I ,000 1.ooo 1.000 1,000 1.ooo 1.000 1.000
2 1.000 loOOO 1.000 loOOO 1.000 1.000 I .000 1.000 1.000 1.ooo 1.ooo
3 ---- -
- ---1.000 1.000
4
:5
C. EXISTINO HYDRO
UNIT 1
2
D. ADDITIONAL HYDRO
UNIT1
TOTAL CAPACITY -KW 4o600 4.600 4.600 4o600 4o600 4.600 4.600 4.600 4.600 5.600 5o600
LAROEST UNIT 1o000 1.000 1,000 loOOO 1,000 1.000 I .000 1.000 1.000 1.000 1.000
Fl~ CAPACITY 3.600 3.600 3.600 3.600 3.600 3.600 3.600 3.600 3.600 4.600 4.600
SURPLUS OR CDEFICIT> -KW lo020 913 806 699 :592 485 380 273 166 1.059 950
NET HYDRO CAPACITY -11WH
DIESEL GENERATION -MWH 12. 177 12.716 13.2:5:5 13.794 14.334 14.873 15.412 15.951 16.490 17.030 17.569
!-A
1979 1980 1981 1982 1983 1984 1985 1986 1987 198S 1999
3. INVESTMENT COSTS ($!000)
1979 DOLLARS
A. EXISTING DIESEL 1 ~ ~~0 1,~~0 1.550 1.550 1.550 1.550 1.550 1.550 1.550 !. 550 1.550
B. ADDITIONAL DIESEL
UNIT I -870 870. 870 870 870 870 870 970 870 870
2
3
4
5
6
C. EXISTING HYDRO
D. ADDITIONAL HYDRO
UNIT I
2
3
E. TRANSMISSION PLANT ADDITIONS
UNIT I
2
F. MISCELLANEOUS ADDITIONS
UNIT I
2
TOTAL !tlOOO)
1979 DOLLARS 1.550 2.420 2.420 2.420 2.420 2.420 2.420 2.420 2.420 2.420 2.420
INFLATED VALUES 1.550 2.490 2.490 2.490 2.490 2.490 2.490 2.490 2.490 :2.490 2.490
4. FIXED COST !tiOOOl
INFLATED VALUES
A. DEBT SERVICE
1. EXISTING 66 66 66 66 66 66 66 66 66 66 66
2. ADDITIONS
SUBTOTAL 27. -38 39 38 38 39 38 38 38 38 38
57. -57 57 57 57 57 57 57 57 57 57
77. -73 73 73 73 73 73 73 73 73 73
97. -89 89 89 89 89 89 89 89 89 89
B. INSURANCE 5 8 9 9 10 II 11 12 12 13 13
1-A
1979 1980 1981 1982 1983 1984 19~ 1986 1987 1988 1989
TOTAL FIXED COST (•10001
2X 71 112 113 113 114 11:5 11:5 116 116 117 117 sx 7l 131 132 132 133 134 134 I :::IS I :::IS 136 136 7'1. 71 147 148 148 149 ISO ISO 1S1 1:51 IS2 IS2
9X 71 163 164 164 16S 166 166 167 167 168 168
S. PRODUCTION COST <•10001
INFLATED VALUES
A. OPERATION AND KAINT
1. DIESEL 169 233 2S6 282 310 339 3S9 380 401 424 448
2. HYDRO
B. FUEL AND LUBE OIL 412 497 :59:5 706 834 980 ,, 106 1.244 1.393 loSS7 1.73S
TOTAL PRODUCTION COST <•10001 SS1 730 8:51 988 1.144 1.319 lo46:5 lo624 1. 794 1.981 2.183
TOTAL ANNUAL COST <•1000)
2X 6:52 842 964 1. 101 1.2S8 lo434 t.sso 1.740 1.910 2.098 2.300
SX 652 8b1 983 1.120 1.277 1.4:53 1o599 .1.759 1.929 2.117 2.319
7'X 6:52 877 999 1.136 1.293 lo469 1o61S 1. 775 1.945 2.133 2.33S
9% 652 893 loOts lo1S2 1.309 1.48:5 1.631 t. 791 I. 961 2.149 2.351
ENERGY REQUIREMENTS -1'1WH s.9Sa 6.:523 7,()88 7.6:54 a. 219 8.784 9.3SO 9.91:5 10.480 11' 046 11.612
MILLS/KWH
2X 109 129 136 144 1:53 163 169 175 182 190 198 sx 109 132 139 146 1.:5:5 16:5 171 177 184 192 200
7X 109 134 141 148 157 167 173 179 186 193 201
9% 109 137 143 lSI 159 169 174 181 187 195 202
C. PRESENT WORTH
ANNUAl. COST C$10001
2% 652 787 842 899 960 1.022 1.053 1.084 1' 112 I, 141 ,, 169
SX 6:52 805 ~9 914 974 lo036 1.06:5 1.09:5 1.123 I· 152 1.179
7Y. 652 820 873 927 986 1.047 1.076 1.105 1.132 1.160 1.187
9Y. 652 835 887 940 999 1.059 1.087 lollS 1o141 1.169 lol95
D. ACCUI'!UL. ANN. COST 111000)
21(. 652 1.494 2.458 3.:5:59 4.817 6.2:51 7.831 9,:571 11' 481 13.:579 15.879
5Y. 652 1.513 2.496 3·616 4.893 6.346 7,94:5 9.704 llo633 13.7:50 16.069
7Y. 652 1' 525' 2.:528 3.664 4.957 6.426 8.041 9.816 11.761 13.894 16.229
9X 6:52 1.545 2.:560 3.712 :5.021 6.506 8.137 9,928 11.889 14.038 16,389
E. ACCUMULATED PRESENT WORTH
ANNUAL COST <•10001
27. 6:52 1.439 2.281 3.180 4. 140 5.162 6.21:5 7.299 8.411 9.:552 10.721
5'1. 6:52 1.457 2.316 3.230 4,204 5.240 6.305 7.400 8.523 9.675 10,854
7'1. 652 1.472 2.345 3.272 4.2:58 5.305 6.381 7.486 8.618 9.778 10.965
9'1. 652 1.487 2.374 3.314 4.313 :5.372 ~" 459 7.574 8.715 9,884 11.079
1-A
1979 1980 1961 1962 1983 1984 1965 1986 1967 1966 1969
F. A(CUl"! f-·R£5 WORTH OF ENERvY
11lLLS/!'I-lH
21 109 230 349 467 584 700 613 922 !.026 1.!31 1, 232
5Y. 109 232 353 472 590 708 622 932 1.039 1. 143 1.245
7% 109 234 357 476 598 717 832 943 1.051 1.156 1.258
9"1. 109 237 362 485 606 726 842 955 1.064 t. 170 1.273
1-A
1990 1991 1992 1993 1994 199'!5 1996 1997 1998 1999 2000
3. INVEST~T COSTS 1110001
1979 DOt..LARS
A. EXISTING DIESEL 1.:5!50 1 .sso 1· 5!50 1. 5!50 1.sso 1 '5!50 1' :5!50 1· 5!50 1.550 1.s:so t.SSO
B. ADDITIONAL DIESEL
I.»>IT 1 870 870 870 870 870 870 870 870 870 870 870
2 870 870 870 870 870 870 870 870 870 870 870
3 ------- --870 870
4
s
b
C. ElCISTINO HYDRO
D. ADDITIONAL HYDRO
UNIT 1
2
3
E. TRANSI'IISSION PLANT ADDITIONS
UNIT 1
2
F. "ISCELLANEOUS ADDITIONS
I.»>IT 1
2
TOTAL CtiOOOl
1 <J79 DOLLARS 3.290 3.290 3.290 3.290 3.290 3.290 3.290 3.290 3.290 4.160 4.160
INFLATED VALUES 4.107 4.107 4.107 4.107 4.107 4.107 4.107 4.107 4.107 t-.409 t-.409
4. FIXED COST lltOOOl
11\FLATED VALUES
A. DEBT SERVICE
1. ElCISTING 6.6 66 bb bb bb 66 66 66 bb 66 6.6
2. ADDITIONS
SUBTOTAL 2X 103 103 103 103 103 103 103 103 103 1~ 195
sx 1:56 1:56 1!56 1!56 1:56 1:56 !So 1St> 156 297 297
7X 198 198 198 198 198 198 198 198 198 376 376
9X 242 242 242 242 242 242 242 242 242 460 460
B. INSURANCE 23 24 25 26 27 28 29 30 31 51 53
1-A
1990 1991 1992 1993 1994 19~ 1996 1997 19'98 19'99 2000
TOTAL FIXED COST 1$1000)
2~ 192 !93 194 I~ 196 197 198 199 200 312 314
57,. 245 246 247 248 249 250 251 252 2:53 414 416
74 287 288 289 290 291 292 293 294 295 493 495
97. 331 332 333 334 335 336 337 338 339 577 :579
5. PRODUCTION COST 1$1000)
INFLATED VALUES
A. OPERATION AND MAINT
1. DIESEL 472 498 526 554 585 617 M9 685 722 759 800
2. HYDRO
B. FUEL AND LUBE OIL 1, 927 2.!34 2.3:58 2.601 2.865 3.1!51 3.461 3.798 4.162 4.5:56 4.982
TOTAL PRODUCTION COST (S1000) 2.399 2.6'32 2.884 3.155 3.450 3.768 4. 110 4.483 4.884 5.315 5.782
TOTAL ANNUAL COST (SIOOO)
27. 2,591 2,825 3.078 3.3:50 3.646 3.965 4.308 4.682 5.084 :5.627 6.~6
51. 2.644 2.878 3. 131 3,403 3.699 4.018 4.361 4.73:5 :5.137 5.729 6,198
77. 2.686 2.920 3,173 3.445 3.741 4.060 4.403 4.777 5.179 5.8o8 6.277
9'Y. 2.730 z. 9b4 3.217 3.489 3.785 4, 104 4.447 4.821 5.223 5.892 6.361
ENERGY REQUIREMENTS -MWH 12. 177 12.716 13.255 13.794 14.334 14.E!73 15.412 15.951 16.490 17.030 17.569
MILLS/KWH
27. 213 222 232 243 254 267 280 294 308 330 347
51. 217 226 236 247 258 270 283 297 312 336 353
71. 221 230 239 250 261 273 286 299 314 341 357
91. 224 233 243 253 264 276 289 302 317 346 362
C. PRESENT WORTH
ANNUAL COST ($1000)
27. 1 '231 I, 254 I, 277 I, 299 1, 321 1.343 1, 364 1.385 1.406 1. 454 1.472
5:1. 1. 256 1.278 1.299 1' 320 1' 341 1.361 1. 381 1.401 I. 420 1.480 1.497 n 1.276 I, 297 1. 317 1.336 1.356 1.375 1. 394 1o413 1.432 1. 501 1.516
9% 1 ,297 1, 316 1.335 1. 353 1. 372 1. 390 1.408 1. 426 1. 444, 1.523 1.536
D. ACCUMUL. ANN. COST (fl000)
27. 18.470 21.295 24.373 27.723 31.369 35.334 39.642 44.324 49.408 55.035 61. 131
5% 18.713 21. :591 24.722 28.125 31.824 35.842 40.203 44.938 50,075 55,804 62,002
7'1. 18.915 21.835 25.008 28.453 32. 194 36.254 40.657 45.434 50.613 56.421 62.698
9'Y. 19.119 22.083 25.300 28.789 32.574 36.678 41.125 45.946 51.169 57.061 63.422
E. ACCUMULATED PRESENT WORTH
ANNUAL COST ( $1(100)
2'1. 11.952 13.206 14.483 15.782 17. 103 18.446 19.810 21.195 22.601 24.055 25.527
57.. 12. 110 13.388 14.687 16.007 17.346 18.709 20.090 2!.491 :!2. 911 24.391 25.888
71. 12.241 13.:538 14.855 16. 191 17.347 18.922 20.316 21.729 23. 161 24.662 26.178
91. 12.376 13.692 15.027 16.380 17.752 19.142 20.550 21.976 23.420 24.943 26.479
1-A
1990 1991 1992 1993 1994 1~ 1996. 1997 1998 1999 2000
F. ACCUI"' PRES WORTH OF ENERGY
I'IILLS/I<WH
2'% 1.333 1.432 1· :528 1.6.22 1.714 1.804 1.893 1.980 2.06.:5 2. 1:50 2.234
SX 1.348 1' 448 1· :546. 1.6.42 1.73b 1.827 1. 917 2.00:5 2.091 2.178 2.26.3 n. 1.363 I, 46.:5 1.:5b4 1.6.6.1 1. 7:5b 1.848 1.939 2.027 2.114 2.202 2.288
91. 1.379 I, 482 1.:583 1.681 1. 777 1.870 1.961 2.0:50 2.138 2.227 2.314
USED 14.12 UNITS
READY
POWER COST STUDY
ALTERNATE 2-A
NAICNEX -DHSE!. -LOll LOAD
1979 1980 1981 1982 1983 1984 198'3 1986 1987 1988 1989
I. LOAD DEI'\AND
DEI1AND -KW 2.422 2.'350 2.678 2.806 2.934 3.062 3.190 3.318 3.446 3.574 3.702
ENERGY -I1WH 13.091 13.778 14.464 15. 1'32 1'3.838 16.525 17.212 17.899 18.'386 19.273 19,960
2. SOURCES -KW
A. EXISTING DIESEL
LOCATION OR UNIT 1 4. 14'3 4.145 4, 145 4.145 4.14'3 4.145 4. 14'3 4.14'3 4.14'3 4.14'3 4.14'3
2
3
4
'3
6
7
8
9
10
II
12
13
B. ADDITIONAL DIESEL
UNIT I ---- -
1.000 I ,000 1.000 1.000 I ,000 1.000
2
3
4
5
C. EXISTING HYDRO
ll'liT I
2
D. ADDITIONAL HYDRO
UNIT I - -
-- - ------- ------- - -
-
TOTAL CAPACITY -KW 4.145 4.145 4.145 4.145 4.14'3 5.14'3 '3. 14'3 5.14'3 '3. 145 5.145 5.145
LARGEST UNIT 1.000 1.000 I ,000 1.000 1,000 1.000 I ,000 1.000 1.000 I ,000 1.000
F I Rl1 CAPAC lTV 3.145 3,145 3.145 3.145 3.14'3 4.145 4.145 4.145 4.145 4.145 4.145
SURPLUS OR ( DEF I C I Tl -KW 723 '39'3 467 339 211 1.083 9'3'3 827 699 571 443
NET HYDRO CAPACITY -11WH
DIESEL GENERATION -11WH 13.091 13.778 14.464 1'3.152 15.838 16.'32'3 17.212 17.899 18.586 19.273 19.960
2-A
1990 1991 1992 1993 1994 19~ 1991> 1997 1998 1999 2000
1 • LOAD DEI'tAND
DEMAND -KW 3.830 3.917 4.004 4.091 4,178 4.21>5 4,352 4.439 4.526 4.1>13 4.700
ENERGY -l'tWH 20.647 21, 120 21.594 22.067 22.541 23.015 23.489 23.962 24.435 24.909 25.383
2. SOURCES -KW
A. EXISTING DIESEL
LOCATION OR UNIT 1 4.145 4.145 4,145 4.145 4.145 4.145 4,145 4.145 4,145 4.145 4.145
2
3
4
5
6
7
8
9
10
11
12
13
B. ADDITIONAL DIESEL
IJNIT I 1.000 1.000 1.ooo 1.000 1.000 1.ooo 1.000 1.000 1.ooo 1.000 1.000
2 - --1.ooo 1.000 1.000 1.000 1.ooo 1.000 1.000 1.000
3
4
5
C. EXISTING HYDRO
UNIT I
2
D. ADDITIONAL HYDRO
UNIT 1
TOTAL CAPACITY -KW 5.145 5. 145 5.145 6.145 6.145 6.145 1>.145 6.145 6.145 6.145 6.145
LARGEST UNIT 1.ooo I. 000 1.000 1.000 1.ooo 1.ooo 1.000 1.000 loOOO 1.000 1.000
Fl~ CAPACITY 4.145 4.145 4.145 5.145 5.145 5.145 5.145 5.145 5.145 5.145 5.145
SURPLUS OR IDEFICITI -KW 315 228 141 1.054 967 880 793 706 619 532 445
NET HYDRO CAPACITY -~
DIESEL GENERATION -~ 20.647 21.120 21 '594 22.067 22.541 23.015 23.489 23.962 24.435 24.909 25.383
2-A
1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989
3. INVESTMENT COSTS (t1000l
1979 DOLLARS
A. EXISTING DIESEL 3.S90 3.S90 3,590 3.S90 3,S90 3,S90 3.S90 3.590 3.590 3,S90 3.590
B. ADDITIONAL DIESEL
UNIT I -- -
-870 870 870 870 870 870
2
3
4
s
6
C. EXISTING HYDRO
D. ADDITIONAL HYDRO
UNIT I
2
3
E. TRANSMISSION PLANT ADDITIONS
UNIT I
2
F. MISCELLANEOUS ADDITIONS
UNIT I
2
TOTAL lt1000l
1979 DOLLARS 3.~90 3.590 3.590 3.590 3.590 4,460 4,460 4,460 4.460 4,460 4,460
INFLATED VALUES 3.590 3.590 3.590 3.590 3,590 4.668 4.668 4.668 4.868 4.868 4,868
4. FIXED COST (t1000l
INFLATED VALUES
A. DEBT SERVICE
!. EXISTING 144 144 144 144 144 144 144 144 144 144 144
2. ADDITIONS
SUBTOTAL 2:1. -----51 S1 51 S1 51 51
S'l. -- -
- -78 78 78 78 78 78
7'l. -- ---99 99 99 99 99 99
9:1. -- -
--121 121 121 121 121 121
B. INSURANCE II 12 13 14 IS 21 22 23 24 25 26
2-A
1979 1980 1981 1982 1983 1984 19~ 1986 1987 1988 1989
TOTAL FIXED COST CIIOOO>
2% 15:5 I :5o 1:57 I '58 1:59 216 217 218 219 220 221
:5Y. 15:5 I :5o 1:57 1:58 1:59 243 244 24:5 24o 247 248
7Y. 1:5:5 I '56 1:57 1'58 1:59 204 2os 2oo 2o7 2oe 2o9
9X 15!5 I !5o 1!57 1'58 1!59 2S6 287 288 289 290 291
5. PRODUCTION COST CSIOOO>
INFLATED VALUES
A. OPERATION AND KAINT
I. DIESEL 310 339 371 408 44o 489 s1o !543 !573 002 o3o
2. HYDRO
B. FUEL AND LUBE OIL 898 1.038 1.199 1.382 1.!590 1.825 2.013 2.219 2.443 2.oeo 2.949
TOTAL PRODUCTION COST (11000> I .208 I• 377 1.!570 1.790 2.030 2.314 2.!529 2.1o2 3,01o 3,288 3.!58!5
TOTAL ANNUAL COST CIIOOO)
2X 1.3o3 1.533 1.727 1.948 2.195 2.!530 2.74o 2.980 3.23!5 3.!508 3.eoo
!5X t.3o3 1.!533 1.727 1.948 2.19!5 2.!5!57 2.773 3.007 3,2o2 3.!53!5 3.833
7X t.3o3 1.!533 •• 727 1.948 2.19!5 2.!578 2.794 3.028 3,283 3,sso 3.8!54
9Y. t.3o3 1.!533 1. 727 1.948 2.19!5 2.ooo 2.e1o 3.0!50 3.30!5 3.!578 3,87o
ENERGY REQUIREMENTS -MWH 13.090 13.778 t4.4o4 1!5.1!52 15.838 to.!52!5 17.212 17.899 18.!580 19.273 t9.9oO
11ILLS/KWH
2X 104 111 119 129 139 1!53 too too 174 182 191
!5)(. 104 111 119 129 139 1!5!5 tot toe t7o 183 192
7% 104 111 119 129 139 1!56 to2 to9 177 18!5 193
97. 104 111 119 129 139 1!57 to4 170 178 teo 194
C. PRESENT WORTH
ANNUAL COST CSIOOOI
27. t.3o3 1.433 1.!508 1.!590 t.o75 1.804 1.830 t.~o 1.883 1.908 1.93!5
5X t.3o3 1.433 1.!508 1.590 1. o7!5 1.823 1.848 1.873 1.899 1.923 1.949
7X t.3o3 1.433 1.!508 1.!590 t.o7!5 1.838 1.eo2 t.eeo 1.911 1.934 1.9!59
9)(. 1.363 1.433 1.!508 1.!590 t.o7!5 1.8!54 t.e7o 1.899 1.924 1.940 1.970
D. ACCUI1UL. ANN. COST <SIOOO>
2X t.3o3 2.89o 4.o23 o.!571 e.7oo 11.290 14.042 17.022 20.2!57 23,7o!5 27.!571
!5X t.3o3 2.89o 4.o23 o.!571 e.7oo 11.323 14.o9o 17. 103 20.3o!5 23.900 27.733
77. t.3o3 2.e9o 4.o23 o.!571 e.7oo 11.344 14.138 t7.1oo 20.449 24.00!5 27.8!59
97. t.3o3 2,89o 4.o23 o.!571 e.7oo 11.3oo 14.182 17.232 20.!537 24.11!5 27.991
E. ACC~ATED PRESENT WORTH
ANNUAL COST (11000>
2X 1.363 2.796 4.304 !5.894 7.!5o9 9.373 11.203 13.0!59 14.942 to.eso 18.78!5
!5X t.3o3 2.79o 4.304 !5.894 7.!5o9 9.392 11.240 13.113 1!5.012 to.93!5 18.884
7X t.3o3 2.79o 4.304 !5.894 7.!5o9 9.407 tt.2o9 13.1!55 ts.ooo 17.000 18.9!59
9% t.3o3 2.79o 4.304 !5.894 7.~o9 9.423 11.299 13.198 1!5. 122 t7.ooe 19.038
2-A
1979 1980 !981 1982 1983 !984 !98S !986 1987 1988 1989
F. ACCUM PRES WORTH OF ENERGY
MILLS/i<WH
2% 104 208 312 417 S23 632 739 842 943 1.042 1.139
5% 104 208 312 417 523 634 741 846 948 1.048 ,, 146
7"1. 104 208 312 417 523 634 742 847 950 1.051 1.149
97. 104 208 312 417 523 63S 744 850 954 1.055 1,154
2-A
19110 1991 1992 1993 1994 1~ 1996 1997 1998 1999 2000
3. IHVESTI'IEfiiT COSTS ($10001
1979 IXll.LARS
A. EXISTING DIESEL 3.~90 3.:590 3.~90 3.590 3.590 3.590 3.~90 3.~90 3.590 3.~90 3.590
B. ADDITIONAL DIESEL
Uf!IT l 870 870 870 870 870 870 870 870 870 870 870
2 ---870 870 870 870 970 870 870 870
3
4
~
b
C. EXISTING HYDRO
D. ADDITIONAL HYDRO
UNIT 1
2
3
E. TRANSI''IISSION PLANT ADDITIONS
UNIT 1
2
F. MISCELLANEOUS ADDITIONS
UNIT 1
2
TOTAl. (110001
1979 DOLLARS 4.400 4.460 4.4b0 ~.330 ~.330 ~.330 ~.330 ~.330 ~.330 ~.336 5,330
INF!-ATED YAl.UES 4.8b8 4.8b8 4.868 b.b97 b.b97 b.b87 6.b87 6.b97 b.b97 b.687 b.b97
4. FIXED COST <11000)
INFLATED VALUES
A. DEBT SERVICE
t. EXISTING 144 144 144 144 144 144 144 144 144 144 144
2, ADDITIONS
SUBTOTAl. 2'X 51 51 51 124 124 124 124 124 124 124 124
~X 78 79 78 189 189 199 189 189 189 199 199
7X 99 99 99 239 239 239 239 239 239 239 239
97. 121 121 121 293 293 293 293 293 293 293 293
B. INSURANCE 27 28 29 42 44 45 47 49 ~· ~3 55
2-A
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000
TOTAL FIXED COST <SIOOOl
2~ 222 223 224 310 312 313 315 317 319 321 323
~~ 249 2~0 2~1 375 377 378 380 382 384 386 388
77. 270 271 272 425 427 428 430 432 434 436 438
97. 292 293 294 479 481 482 484 486 488 490 492
5. PRODUCTION COST (SIOOO)
INFLATED VALUES
A. OPERATION AND MAINT
I. DIESEL 670 703 737 773 812 852 893 936 981 1.031 I ,080
2. HYDRO
B. FUEL AND LUBE OIL 3.232 3.506 3.798 4.115 4.454 4.822 5.219 5.641 6.096 6.589 7.120
TOTAL PRODUCTION COST <SIOOO> 3.902 4.209 4.535 4,888 5.266 5.674 6,112 6.'577 7.077 7.620 8.200
TOTAL ANNUAL COST <SIOOO>
27. 4.124 4. 432 4.7'59 5.198 S,S78 5.987 6.427 6,894 7,396 7,941 8.523
57. 4. 151 4.459 4.786 5.263 5.643 6.0'52 6,492 6,959 7.461 8.006 8.588
77. 4. 172 4.480 4.807 5.313 5.693 6.102 6.'542 7.009 7.511 8.056 8.638
97. 4.194 4.502 4.829 5.367 5.747 6.156 6.596 7.063 7.565 8.110 8.692
ENERGY REQUIREMENTS -MWH 20.647 21.120 21.594 22.067 22,541 23.015 23.489 23.962 24.435 24.909 2'5.383
MILLS/KWH
27. 200 210 220 236 247 260 274 288 303 319 336
57. 201 211 222 239 2'50 263 276 290 305 321 338
77. 202 212 223 241 2'53 265 279 293 307 323 340
97. 203 213 224 243 2'55 267 281 295 310 326 342
C. PRESENT WORTH
ANNUAL COST ($1000)
27. 1.959 1.968 1.975 2.016 2.022 2.028 2.035 2.040 2.04'5 2.0~2 2.0'58
~7. 1.972 1.980 !.986 2.041 2.045 2.050 2.0'55 2.059 2.063 2.069 2.074
n: 1.982 1.989 !.99'5 2.060 2.063 2.067 2.071 2.074 2.077 2,082 2.086
97. 1.993 !. 999 2.004 2.081 2.083 2.085 2.088 2.090 2.092 2.096 2.099
D. ACCUMUL. ANN. COST (SIOOO>
27. 31.695 36. 127 40.886 46.084 51.662 57.649 64.076 70.970 78.366 86.307 94,830
57. 31,884 36.343 41.129 46.392 52.035 58.087 64.579 71.538 78.999 87.005 95.593
77. 32.031 36.511 41,318 46,631 '52.324 58.426 64.968 71.977 79,488 87.544 96.182
97. 32. 185 36.687 41.516 46.883 52.630 58.786 65.382 72.445 80.010 88,120 96,812
E. ACCUMULATED PRESENT WORTH
ANNUAL COST (S!OOO>
n 20.744 22.712 24.687 26.703 28.725 30,753 32.788 34.828 36.873 38,925 40,983
57. 20.8'56 22,836 24.822 26.863 28,908 30,958 33.013 35.072 37. 135 39.204 41.278
77. 20.941 22,930 24,92'5 26,985 29,048 31.115 33,186 35,260 37.337 39,419 41.50'5
97. 21.031 23.030 25.034 27.115 29,198 31.283 33,371 35,461 37,553 39.649 41.748
2-A
1990 1991 1992 1993 1994 199'!1 1996 1997 1998 1999 2000
F. ACCUtl PRES WORTH OF ENERGY
I'IILLS/KWH
2X 1.234 1.327 I •'118 I .!510 I ,bOO t.b8a I, 775 1.960 lo944 2.026 2.107
!!'X. 1' 241 1.335 1.427 1.~20 1·611 1. 700 1. 7$7 1.873 lo9!57 2.040 2.122
7X 1.245 1.339 1.432 1.52!5 1·617 1.707 I, 79!5 lo882 1.967 2.050 2.132
9'l. 1' 2!50 1.345 1.438 1.532 1.624 I, 714 1.803 1.890 1.976 2.060 2.143
POiolER COST STUDY ALTERNATE 3-A
10 VILLAGES -LOCAL DIESEL -LOW LOAD
197" 1080 1981 1"'82 1983 1984 1"85 1986 1987 !988 1989
1. LOAD DEMAND
DEMAND -1<1.1 1 ~ ~5:: 1 ':::73 1, 288 1' 303 1 '3 1" I, 334 1 '34" 1' 366 1, 3e4 1' 401 1.419
ENERGY -MlolH :·"os.-:. :::.::40 :2~3Q4 2,548 2.702 :1856 3.010 3. 164 3.318 3~472 3,626
2. SOURCES I<J..I
A. EXISTING DIESEL
LOCATION OR UN IT I 100 100 101) 100 !(H) 100 too 1•)0 100 100 !00
2 t3e. 13:"· 135 13:"· 135 135 135 135 135 135 135
_, 100 100 too 100 100 100 100 100 100 100 100
4 7'5 75 7~· 7:"· 75 7~ 75 75 75 7~ 75
5 19:5 195 195 195 195 195 195 195 195 195 !95
6 50 50 so 50 50 so 50 50 so 50 so
7 !35 135 135 135 135 135 135 135 135 135 !35
8 40 40 40 40 40 40 40 40 40 40 40
" 10
11
12
B. ADDITIONAL DIESEL
UNIT I 700 700 700 700 700 700 700 700 700 700
2 --100 100 100 100 100 100
3
4
5
6
c. EXISTING HYDRO
UNTT 1
2
D. ADDITIONAL HYDRO
UNIT 1
2
3
TOTAL CAPACITY -Klol 830 1.530 1.530 1,530 I ,530 1.630 1· 630 I .630 1.630 I, 630 1.630
LARGEST UNIT 100 100 100 !00 100 100 100 100 100 100 100
FIRM CAPACITY 730 !.430 1' 430 1 '430 I .430 I, 530 1, 530 I ,530 1, 530 1.530 1.530
SURPLLIS OR !DEFICIT> -~-~o~ {~22) !57 142 127 I 1 I 1"'6 181 H.•4 146 129 1 11
NET HYDRO CAPACITY -MWH
DIESEl-GENERATION -MlolH 2.08~-2.240 2.394 2,54€: 2.7o:: 2,856 :>..0!0 3, 1&4 3,318 3.472 3.62c·
3-A
1990 1991 19<>2 1993 1994 t995 1996 1"'97 1991:' 1999 2000
1. LOAD D£11ANO
DEI'IANO -KW 1. 436 1 .. 482 t.S2S 1.573 t.6t<> 1.665 1.7t2 1. 759 1.807 1.854 t .901
ENERGY -I'IWH 3.780 4-,012 4.245 4.477 4.710 4.943 5. t75 5.408 5.64t 5.874 6.107
2. SOURCES -KW
A. EXISTING DIESEL
LOCATION OR UNIT 1 tOO tOO 100 tOO 100 100 100 100 100 100 100
2 135 135 135 13'5 135 135 135 135 135 135 t35
3 100 100 100 100 100 too too 100 100 100 too
4 75 75 7!5 7'5 7'5 75 75 75 75 7'5 75 s 195 195 195 1<>5 t95 t95 195 195 19::> 195 195
6 :50 so 50 50 50 50 50 so so 50 '50
7 135 t35 135 t3S t35 135 135 13'5 135 135 135
8 40 40 40 40 40 40 40 40 40 40 40
9
10
II
12
B. ADDITIONAL DIESEL
(") UNIT I 700 700 700 700 700 700 700 700 700 700 700
I 2 100 100 100 tOO 100 100 100 100 100 100 100 N 3 200 200 200 200 200 200 200 200 200 200 200 ....... 4 ----200 200 200 200 200 200 200
5 ------ -100 100 100
6
C. EXISTING HYDRO
UNIT 1
2
D. ADDITIONAL HYDRO
UNIT 1
2
3
TOTAL CAPACITY -KW 1.930 t.S30 1.830 t. El30 2.030 2.030 2.030 2,030 2.130 2.130 2.130
LARGEST UNIT 100 100 100 100 100 100 100 100 100 100 100
FIRI'I CAPACITY 1.730 1.730 1. 730 1. 730 1.930 1.930 1.930 1.930 2,030 2,030 2.030
SURPLIJS OR (DEFICIT l -I<:W 294 249 202 157 311 26'5 218 171 223 176 129
NET HYDRO CAPACITY -MWH
DIESEL GENERATION -I'IWH 3.780 4.012 4.245 4,477 4.710 4.943 s.175 ~;. 408 5.641 5.874 6.107
3-A
1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 !989
3. INVESTMENT COSTS (SIOOOl
1979 DOLLARS
A. EXISTING DIESEL 722 722 722 722 722 722 722 722 722 722 722
B. ADDITIONAL DIESEL
UNIT 1 -690 690 690 690 690 690 690 690 690 690
2 -----87 87 87 87 87 87
3
4
5
6
c. EXISTING HYDRO
D. ADDITIONAL HYDRO
UNIT 1
2
3
E. TRANSMISSION PLANT ADDITIONS
UNIT 1
2
F. MISCELLANEOUS ADDITIONS
UNIT 1
2
TOTAL !SIOOOl
I 979 DOLLARS 722 !. 412 1.4!2 1. 4! 2 1. 412 !.499 !.499 1.499 !.499 1.499 !.499
INFLATED VALUES 722 1.467 1.467 1.467 1. 467 1.595 1.595 1.595 !.595 1.595 !.595
4. FIXED COST lf!OOOl
INFLATED VALUES
A. DEBT SERVICE
1. EXISTING 29 29 29 29 29 29 29 29 29 29 29
2. ADDITIONS
SUBTOTAL 2'1. -30 30 :<o 30 35 35 35 35 35 35
57. -45 45 45 45 53 53 53 53 53 53
77. -58 58 58 58 68 68 68 68 68 6a
97. -70 70 70 70 82 a2 82 a2 82 a2
B. INSURANCE 2 5 5 6 6 7 7 8 a a 9
3-.\
1979 1900 1981 1982 1983 1984 198'5 1986 1987 1988 1989
TOTAL FIXED COOT ISIOOOI
2X 31 64 64 6~ 6~ 71 71 72 72 72 73
~X 31 79 79 eo 80 89 89 90 90 90 91
7x 31 92 92 93 93 104 104 ·~ ·~ ·~ 106
9X 31 104 104 I~ 105 118 liS 119 119 119 120
~. PRODUCTION COST ISIOOOl
INFLATED VALUES
A. OPERATION AND I'IAIN'f
1. DIESEL 181 216 233 2~2 272 294 306 318 331 344 3"58
2. HYDRO
B. Fl.EL AND LUBE OIL 4~9 ~42 638 747 870 1.012 1.130 1.260 1.401 1.5~2 1. 7tQ
TOTAL PRODUCTION COST !S1000) 640 758 871 99'9 1.142 1.306 1.436 1.578 t. 732 1.896 2.077
TOTAL ANNUAL. COST l$1000)
2X 671 822 93:5 1.064 1.207 1.377 1.~7 1.6~ 1.804 1.968 2.150
~X 671 837 ~0 1o079 1o222 1.395 1.~~ 1o668 1.822 1.986 2. ll>EI
7X 671 Er.50 963 1·092 1. 23:5 1. 410 1.~o 1.683 1.837 2.001 2.183
9X 671 862 975 1' 104 1.247 1o424 ,.~~4 1.697 loS'S I 2o0l~ 2.197
ENERGY REQUIREIENTS -P1WH 2.086 2.240 2.394 2.~8 2.702 2.8~ 3.010 3.164 3.318 3.472 3.626
111LL8/I<WH
2X 322 367 391 418 447 482 ~01 ~21 ~4 ~67 ~n
. ~X 322 374 397 423 452 488 ~07 527 ~49 ~72 5913
7X 322 379 402 429 457 494 ~12 ~32 5~4 ~76 602
9X 322 ~ 407 433 462 499 ~16 ~36 ~58 ~80 606
C. PRESENT WORTH
AM«JAL COOT lSI 000)
2X 671 768 817 869 921 982 1.004 1o028 1.050 1. 070 1.093
~X 671 782 830 881 932 995 1 '016 1.039 1 '060 1.080 1.102
7X 671 794 &41 891 942 1.005 1.026 1.048 1.069 1 '088 1.110
9% 671 806 852 901 9~1 1.015 1.035 1o057 1.077 1.096 1.117
D. ACCU11UL. ANN. COST CS1000)
2X 671 1o493 2.428 3.492 4.699 6.076 7.583 9.233 11.037 13.005 15.1~
5X 671 1.~08 2.458 3.537 4.7~9 6.1~4 7.679 9.347 11.169 13.155 15.323
7X 671 ··~21 2o484 3.576 4.811 6.221 7.761 9.444 11.281 13.282 15.465
9X 671 1.~33 2.~08 3.612 4.859 6.283 7.837 9.~34 11.~ 13.400 1~.597
E. ACCUMULATED PRESENT WORTH
ANNUAL COST lSI 000 l
2X 671 1.439 2.~ 3.125 4.046 5.oze 6.032 7.060 8.110 9.180 10.273
5X 671 1.4~3 2.283 3.164 4.096 ~5. 091 6. 107 7.146 8·206 9.286 l0o3ea
7X 671 lo465 2.306 3.197 4ol39 5.144 6.170 7o218 8.287 9.375 10.485
9'1.: 671 1.477 2.329 3.230 4.181 5.196 6.231 7.288 a.36~ 9.461 10.578
3-A
1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989
F. ACCUM PRES WORTH OF ENERGY
MILLS/KWH
2"1. 322 665 1 .oo7 1.348 1.689 2.033 2.367 2.691 3.008 3.316 3.617
5r. 3.,., 672 1.019 1.364 1.709 2.()57 2.395 2.723 3.043 3.354 3.658
7r. 322 676 I .027 1.377 1.726 2.078 2.419 2.750 3.072 3.385 3.691
9"(. 322 682 I .037 1.390 I .742 2.098 2.442 2.776 3.101 3.416 3.724
3-A
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000
3. INYESll'IENT COSTS (S1000)
1979 DOLLARS
A. EXISTING DIESEL 722 722 722 722 722 722 722 722 722 722 722
B. ADDITION~ DIESEL
UNIT 1 690 690 690 690 690 690 690 690 690 690 690
2 97 87 97 97 97 97 97 97 87 87 97
3 174 174 174 174 174 174 174 174 174 174 174
4 ----174 174 174 174 174 174 174
5 --------87 87 87
6
C. EXISTING HYDRO
D. ADDITIONAL H'I'DRO
UNIT 1
2
3
E. TRANSHI SS I ON P'I.ANT ADDITIONS
UNIT 1
2
F. "ISCELLAIIIEOUS ADDITIONS
UNIT 1
2
TOTAl.. <•1000)
197-, fQ..LARS 1.673 1.673 1.673 1.673 1.947 1.947 1.847 1.847 1, 934 1.934 1.934
INFLATED VALUES 1.919 1.919 1.918 1.918 2.296 2.296 2.296 2.296 2.517 2.517 2.517
4. FIXED COST t•1000)
INFLATED VALUES
A. DEBT SERVICE
1. EXISTING 29 29 29 29 29 29 29 29 29 29 29
2. ADDITIONS
SUBTOTAl. 2'X 48 49 49 48 63 63 63 63 72 72 72
5X 73 73 73 73 96 96 96 96 109 109 109
7X 93 93 93 93 122 122 122 122 139 139 139
9X 113 113 113 113 149 149 149 149 170 170 170
B. INSURANCE 11 11 12 12 15 16 16 17 19 20 21
3-A
1990 1991 1992 1993 1994 199~ 1996 1997 1998 1999 2000
TOTAL FIXED COST ($1000)
27. ea ea 69 69 107 108 108 109 120 121 122
S:t. 113 113 114 114 140 141 141 142 157 158 159
7')( 133 133 134 134 166 167 167 168 187 tea 189
97.. 153 153 154 1 '$4 193 194 194 195 216 219 220
5. PRODUCTION COST <S1000l
INFLATED VALUES
A. OPERATION AND MAINT
1. DIESEL 372 387 402 418 43~ 452 470 489 509 529 !550
2. HYDRO
B. FUEL AND LUBE OIL I ,900 2-136 2.397 2.679 2.989 3.326 3.689 4.088 4.518 4.989 5.495
TOTAL PRODUCTION COST (S!OOOl 2.272 2.523 2.799 3.097 3.424 3.778 4.159 4.577 5,027 s.s1a 6.045
TOTAL ANNUAL COST <S1000l
2% 2.360 2·611 2.888 3.186 3.531 3.886 4.267 4.686 5.147 5.639 6.167
57.. 2 .. 385 2.636 2.913 3. 211 3.564 3.919 4.300 4.719 5.184 5.676 6.204
7:1. 2.405 2.656 2.933 3. 231 3.590 3.945 4.326 4.745 5.214 5.706 6.234
9% 2.425 2.676 2.953 3.251 3.617 3.972 4.353 4.772 5.245 5.737 6.265
ENERGY REQUIREMENTS -MWH 3.780 4.012 4.245 4.477 4.710 4.943 :;, 175 5.408 5.641 5.874 6.107
MILLS/KWH
2% 624 651 660 712 750 786 825 866 912 960 1.010
S:t. 631 657 686 717 757 793 631 873 919 966 1.016
n. 636 662 691 722 762 798 836 877 924 971 1.021
97. 642 667 696 726 768 804 641 882 930 977 1.026
C. PRESENT WORTH
ANNUAL COST ($1000)
2% I, 121 1.159 1.198 1.236 1.280 1.316 1.351 1. 386 1.423 1.457 1.489
5% 1, 133 1.170 1.209 1,245 1.292 1, 326 1.361 1.396 1,433 I, 467 1.498
7'"1. 1.143 1, 179 1· 217 1.253 1· 301 1. 336 1.370 1.404 1.442 1.475 I, 506
9X 1.152 l· 188 1 '225 1.261 I, 311 1.345 1.378 1.412 1. 450 1.483 1. 513
D. ACCUMUL. ANN. COST <S!OOOl
2:t. 17.515 20.126 23,014 26.200 29.731 33.617 37.684 42.570 47.717 53.356 59 .. 523
5% 17.708 20.344 23.257 26.468 30.032 33.951 38.251 42.970 48.154 53.830 60.034
7% 17.870 20.526 23.459 26.690 30.280 34.225 38.551 43.29l:-48.510 54.216 60.450
97. 18.022 20.698 23.651 26.902 30.519 34.491 38.844 43.616 4~!. 861 54.598 60.863
E. ACCUMULATED PRESENT WORTH
ANNUAL COST <S1000l
2Y. 11.394 12.553 13.751 14.987 16.267 17.583 18.934 20.320 21.743 23.200 24.689
5'X 11.521 12.691 13.900 15.145 16.437 17.765 19.126 20.522 21,955 23.422 24.920
7% 11.628 12.807 14.024 15.277 16.578 17.914 19.284 20.688 22.130 23.60'5 25. 111
97. 11.730 12.918 14' 143 !5.404 16.715 18.060 19.438 20.8~0 22.300 23.783 25.296
3-A
1990 1991 1992 1993 1994 199~ 199~ 1997 1998 1999 2000
F. ACC1J!1 PRES WORTH OF ENERGY
PULLS/KWH
n 3.913 4.202 4.484 4.7w 5.032 5.298 ~.SS9 ~.815 ~.~·; 6.31~ 6.559
54 3.~a 4. 2'50 4o53!5 4.813 ~.087 5.~ ~.~19 5.877 6.131 ~.381 6.~26
7'X. 3.993 4.287 4.574 4.854 5.130 5.400 5.~6~ 5.924 6.179 ~.430 6.677
9?:: 4.029 4. 32'5 4.~14 4.896 5.174 5.44~ 5.712 !$.973 ~.230 6.482 ~.730
POWER COST STUDY ALTERNATE 4-A
DILLINGHAM/NAKNEK/10 VILLAGES CENT1!AL DIESEL -LOW LOAD
1'>7<> 1'>80 1981 1982 1<;/83 1984 !985 198~ !987 !98E: !08'>
!. LOAD DEMAND
DEMAND -KW 5.074 5.820 5,:0.66 5.8!2 ;,.,os8 6.304 6~550 e"ato 7.070 7.330 7,50!)
ENERGY MWH 20.88:2, :2:2.336 23.783 25 .. 230 2t .• ~77 2-9~ 12~, 29.572 30~978 32.385 33.701 35. 198
z. SOURCES -KW
A, EXISTING DIESEL
LOCATION OR UNIT l 2.~00 2.600 2,600 2 .. 600 2.600 2.~00 2',600 2.600 2.600 2.600 2.600
2 4 ~! 45 4. 14:0· 4.,145 4. !45 4. 145 4. 145 4-145 4.145 4.145 4.145 4.145
3 830 830 830 830 830 830 830 830 830 830 830
4
-· 6
7
8
0
10
11
12
B. ADDITIONAL DIESEL
LIN IT I -I, 700 I, 700 I, 700 I, 700 I .700 I, 700 1.700 I. 700 !.700 1' 700
2 1.000 1 .ooo I.QQO I ,000 1 .ooo t.ooo 1.ooo 1.000 1 .ooo
3 -----1.100 1. 100 1.100 1.100 1.100 1.100
4
5
6
c. EXISTING HYDRO
UNIT 1
2
D. ADDITIONAL HYDRO
UNIT 1
2
3
TOTAL CAPACITY -KW 7.575 9,275 10.275 10.275 10~275 11.375 1 1' 375 11' 375 11,375 11.37::. 11.375
LARGEST UNIT 2.000 2.000 2.000 2.000 2.000 2.000 z.ooo 2.000 2.000 2,000 2,000
FIRM CAPACITY 5.'575 7-.275 8t27S 8.275 8.275 9,375 9,375 9.375 9.375 9.375 9.375
SURPLUS OR WEF I CIT l -KW 50! !.955 2.70<;1 2.463 2.217 3.071 2.825 2.565 2.305 2 .. 045 1) 78~·
NET HYDRO CAPACITY -MWH
DIESEL GENERATION MWH 20.888 22,336 23.783 25 .. 230 26.677 2Q., 1:?5 29,572 30.978 32.38'5 33.791 3'5.1 98
4-A
1990 1901 1992 1993 J904 1"'95 1996 1997 1998 1009 2000
1 • LOAD DEI"'AND
DEI'IAND -KW 7.Er.50 a.oa8 8.326 8.'564 8.802 9.040 9.282 9.524 9.766 to.oos 10.2'50
ENERGY -PftiH 36.604 37.8'50 39.095 40.340 41 .'58'5 42.831 44.076 4'5.322 4b.568 47.814 49.060
2. SOURCES -KW
A. EXISTING DIESEL
LOCATION OR UNIT I 2,600 2.600 2.600 2.600 2.600 2~600 2.600 2.600 2.600 2.600 2.600
2 4.145 4.145 4.145 4.145 4.145 4.145 4' 14'5 4. 14'5 4. 14'5 4. 14'5 4.145
3 830 830 830 830 830 830 830 830 830 830 830
4
5
6
7
8
9
10
11
12
B. ADDITIONAL DIESEL
UNIT 1 1.700 1.700 1.700 1.700 1, 700 1, 700 1.700 1. 700 1. 700 1.700 1.700
2 1.ooo 1.ooo 1.ooo 1.000 1 .ooo 1 .ooo 1 .ooo 1.ooo 1.000 1.ooo t.ooo
3 1.100 1.100 1.100 I, 100 1. 100 t.too 1. 100 1.100 1.100 I .tOO 1.100
4 t.zoo 1. 200 1.200 I .200 1.200 1. 200 1.200 1.200 1.200 1.200 1.200
5 ----2,200 2.200 2.200 2.200 2.200 2.200 2.200
6 ---- ----1' 100 1. 100
C. EXISTING HYDRO
UNIT 1
2
D. ADDITIONAL HYDRO
UNIT 1
2
3
TOTAL CAPACITY -KW 12.575 12.'57'5 12.575 12.'575 14.77'5 14.77'5 14.77'5 14.775 14.775 1'5.87'5 15.875
LARGEST UNIT 2.000 2.000 2.000 2.000 2.000 2.000 2.000 2.000 2.000 2.000 2.000
FIRt1 CAPACITY 10.575 10.575 10.575 10.575 12.175 12.77'5 12.175 12.775 12.175 13.87'5 13.87'5
SURPLUS OR I DEFICIT> -KW 2.725 2.487 2.249 2.011 3.973 3.735 3.493 3.251 3.009 3.867 3.625
NET HYDRO CAPACITY -MWH
DIESEL GENERATION -MWH 36.604 37.8'50 39.095 40.340 41.585 42.831 44.076 45.322 46.568 47.814 49.0b0
4-A
197" 1"80 1981 1982 1983 1"84 198~ 1986 1987 1988 1"8"
3. INVESTMENT COSTS ('f1000)
1"79 DOLLARS
A. EXISTING DIESEL 5~86: ~tBb2 5.86:' 5.86:' 5'"862 5~86;2 5,862 5,862 5.86:' ~ .. 862 ~ .. 862
B. ADDITIONAL DIESEL
UNIT 1 -1. 47" 1.47" 1.47" 1.47" 1.479 1' 479 1.479 1.479 1.479 1.47<>
:;:: -870 870 870 870 870 870 870 870 870
3 -"57 957 957 957 957 957
4
5
6
c. EXISTING HYDRO
D. ADDITIONAL HYDRO
UNIT 1
2
3
E. TRANSMISSION PLANT ADDITIONS
UNIT 1 --4,.Q75 4.975 4.975 4.975 4.975 4.975 4,975 4.975 4,975
2
F. MISCELLANEOUS ADDITIONS
UNrT 1
2
TOTAL <S!OOOl
!979 DOLLARS 5.862 7.341 13.186 13.186 13.186 14. 143 14.143 14.143 14,143 14,143 14. 143
INFLATED VALUES S,S62 7.459 14.277 14,.277 14.277 !5,683 15.683 15.683 15,683 15.683 15.683
4. FIXED COST ($1000)
INFLATED VALUES
A. DEBT SERVICE
I. EX I STING 238 238 238 238 238 238 238 238 238 238 238
2. ADDITIONS
SUBTOTAL 2'7.. 64 337 337 337 393 393 393 393 393 393
5Y. 98 514 514 514 600 600 600 bOO 600 600
7f. -123 650 650 650 759 759 759 759 759 7SQ
9(. 151 796 796 796 929 929 929 929 929 929
B. INSURANCE 18 24 50 54 58 69 72 75 78 81 84
~-A
1979 1980 1981 1982 1983 1984 1 oss 1986 10S7 !0 88 1989
TOTAL FIXED COST 1110001
27. 256 326 62'5 629 633 700 703 706 709 712 71'5
:;x 2'56 360 802 806 810 907 910 013 916 <>t<> 922
7'1. 2'56 385 938 942 946 1.066 1, 069 1.072 1, 07'5 1.078 1.081
'<>r. 256 413 1.084 1 .oea 1.092 1.2:;16 1, 23<> 1.242 1, 24'5 1.248 1 '251
5. PRODUCTION COST <11000)
INFLATED VALUES
A. OPERATION AND 1'1AINT
1. DIESEL 6'51 803 64'5 710 780 92'5 966 1.021 1.076 1. 137 1.198
2. HYDRO
B. FUEL AND LUBE OIL 1.695 1.994 1.994 2.326 2.707 31-.251 3.498 3,886 4.304 4,762 5.256
TOTAL PRODLICTION COST <11000) 2.346 2.797 2,639 3.036 3.487 4.176 4.464 4,907 5.380 '5.899 6.4'54
TOTAL ANNUAL COST 111000)
2h 2.,602 3.123 3.264 3.665 4.120 4d376 s. 167 '5.613 6.089 6.6!1 7.16°
s:r. 2.602 3.i57 3.441 3,842 4,297 5.083 5,374 5,820 6.296 6.818 7.376
n 2,.602 3.182 3.577 3.978 4.433 5.242 5.533 '5.979 6.45'5 6,977 7.535
9% 2.602 3.210 3.723 4.124 4.'579 5.412 ~ .. 703 6.149 6,625 7.147 7.70'5
ENEROY REQUIRE~ENTS -MWH 20,888 22.336 23.783 25.230 26.677 29.125 29.572 30.978 32.38'5 33.791 35.198
~ILLS/KWH
2X. 125 140 137 145 154 167 175 181 188 196 204
5'Y. 125 141 145 152 161 175 182 188 194 202 210
7'Y. 125 142 150 158 16.6 180 187 193 199 206 214
9Y. 125 144 157 163 172 186 193 1?8 205 212 219
c. PRESENT WORTH
ANNLIAL COST (11000)
2'Y. 2.602 2.919 2.851 2.992 3.143 3.477 3.443 3.49'5 3.'544 3.'596 3.644
5:r. 2.602 2.950 3.006 3.136 3.278 3,624 3.581 3.624 3·664 3.70<> 3.750
7:1. 2.602 2.974 3.124 3.247 3.382 3.737 3.687 3,723 3.757 3.795 3.830
9:1. 2.602 3.000 3.2'52 3.366 3.493 3.859 3.800 3.829 3.856 3.887 3.917
D. ACCU~UL. ANN. COST ($1000>
2:1. 2.602 5 .. 725 8.989 12.654 16.774 21.650 26.817 32.430 38.'519 45. 130 '52.299
sx 2.602 5.759 9.200 1:3.042 !7.339 22.422 27.796 33.616 39,912 46.730 54.106
7"1. 2.602 5.784 9.361 13.339 17.772 23.014 28.'547 34.526 40.981 47,958 5'5.493
9'Y. 2.602 5.812 9.535 13.659 18,238 23.650 29.353 35.502 42.127 49.274 56.97<>
E. ACCU~ULATED PRESENT WC~TH
ANNLIAL COST ($1000)
2% 2.602 ~~. 521 8.372 u. 364 14.507 17.984 21.427 24,922 28.466 32.062 35.706
5Y. 2.602 5"#552 8.558 11.694 14.972 18.596 22.177 25.801 29.465 33.174 36.924
7')( 2.602 5.576 8.700 11.947 15.329 19,066 22-,753 26.476 30.233 34.028 37.858
9':t 2.602 '5.602 8.854 12.220 15.713 19.572 23,372 27.201 31.057 34.944 38.861
~-A
1Q70 !980 !981 !98::' 1983 1984 !08~· 1986 !987 1°88 1'>8<>
F. ACCUH PRES WORTH OF ENERGY
MILLS/KWH
:::r. 125 256 376 494 611 730 847 960 1.06° I. 17b 1.280
~"-1~5 257 384 508 631 7~·6 877 994 I, 107 I. ::'17 '· 324 7'Y. 125 258 38° 518 645 77< 8':::>8 1.018 '· 134 I, ::'46 1.355
<?I.. 125 260 307 530 bbl 7"4 0~3 I, 04b 1. lb5 1.::'80 !.391
4-A
1990 1"'91 1992 1993 1994 1995 1996 1997 1998 199<> 2000
3. INVESTMENT COSTS <•10001
1979 POLLAR$
A. EXISTJNG DIESEL 5.862 5.862 s.abz '5.86:2 5.862 '5.862 5.862 5.862 '5.862 ~J, 862 5.86:
e. ADDITIONAL DIESEL
UNIT 1 1.47'il 1.47'il 1.479 1.479 1 '47<> 1 '47<> 1.479 1.479 1.479 1.479 }.479
2 870 870 870 870 870 870 870 870 870 870 870
3 9!57 957 9!57 957 9'57 957 957 9'57 9'57 957 ~
4 I ,044 t. 044 1.044 1,044 1. 044 1.044 1, 044 1.044 1. 044 1.044 1.044
'5 ----1. 914 t. 914 1.914 1. 914 1, 914 1.914 1.914
6 ---------9'57 9'!57
c. EXISTING HYDRO
D. ADDITIONAL HYDRO
LNIT 1
2
3
E. TRANSMISSION PLANT ADDITIONS
llNIT 1 4,975 4.975 4.975 4.975 4.97'5 4.97'5 4.97'5 4.97'5 4 .. 975 4.975 4.975
2
F. MISCELLANEOUS ADDITIONS
LINIT 1
2
TOTAL <•1000)
1979 POLLARS 15.187 1'5.187 1:!'.187 1'5. 187 17.101 17·101 17.101 17.101 17. l 01 18.0'58 18.058
INFLATED VALLIE$ 17.624 17.t.24 17.624 17.624 21.787 21.787 21.787 21· 787 21' 787 24.319 24.319
4. FIXED COST <•1000)
INFLATED VALUES
A. DEBT SERVICE
1. EXISTING 238 238 238 238 238 238 238 238 238 238 238
2. ADDITIONS
SLIBTOTAL 27. 471 471 471 471 638 638 638 638 638 739 739
~i. 719 719 719 719 973 973 973 973 973 1' 128 1. 128
7)( 909 909 909 '9(19 1. 231 1.231 t. 231 t. 231 1 't 231 1 t427 1.427
9)( 1.113 ld 13 1.113 1' 113 1 ''507 1 ''507 1' '507 1't507 1. '507 1' 747 1. 747
B. INSURANCE 98 102 106 111 142 148 1:54 160 166 193 201
4-A
19"0 1""'1 1992 100'] 1"94 1905 1"''>6 1'>"'7 1Q0 8 1'>99 2000
TOTAL FIXED COST ($1000)
2% 81)7 811 81'5 820 1·018 1.024 1.0:30 !.036 1, 04:2 1, 170 1,178
'5'! 1.05'5 1.059 !. 06:3 1. 068 1.35:3 1 .35" 1· 365 I, 371 1. 377 1·'559 1.'567
n: 1 ~ :::!45 1 "240 1 .. ~53 1.2'58 I .611 1.617 1 623 1 .. 629 1·635 1.858 1.866
9";: ], 44" 1.4'53 1.4'57 l .462 1.887 !.8°3 I 809 I ,905 1. "11 2'0178 2.186
t PRODUCTION COST ($1000) -·· INFLATED VALL!ES
A. OPERATION AND MAINT
I. DIESEL 1 .. 265 1 ~ 331 I ,402 1.475 1.554 1.634 1· 718 1.809 1. 901 2,001 2.103 .., HYDRO
B. FUEL AND LUBE OIL 5,795 6.353 6.955 7.605 8.312 <>,073 9.899 10.788 11.752 12.788 13.911
TOTAL PRODUCTION COST ($1000) 7.060 7.684 8.357 9.080 9.866 10.707 11 '617 12,597 13.653 14,789 16.014
TOTAL ANNLIAL COST ($1000
2'1.. 7.867 8.495 9,172 9,900 l(l,$84 11 '731 12.647 13.633 14.6'>5 15.959 17~1~2
5% 8,! 15 8.743 9,420 10.148 11,21Q 12.066 12."'82 13.968 15.030 16.848 17.581
7/. 8,305 8,933 9,610 10.338 11.477 12 .. 3:24 13.240 14.226 15,288 16.647 17.880
9% 8.509 9.137 '9,814 1().,542 11.753 12 .. 600 13.516 14.502 15.564 16.967 18.200
ENERGY REQUIREMENTS MWH 36.604 37.850 39, 09~· 40.340 41.585 42,831 44.076 45 .. 322 46.'568 47.814 49.060
MILLS/KWH
2/. 215 224 235 245 262 274 287 301 316 334 3:)0
57. 222 231 241 252 270 282 295 308 323 342 358
7"/.. 227 236 246 256 276 288 300 314 328 848 364
97. 232 241 251 261 283 294 307 320 334 3!55 371
c. PRESENT WORTH
ANNUAL COST ($1000)
2';1,. 3.731;: 3. 772 3.806 3.839 3.945 3.974 4,004 4.034 4.063 4.124 4, 152
!5% 3.855 3,882 3.909 3.936 4.066 4.087 4. 110 4. 133 4, 1'56 41225 4.246
7% 3.94(:. 3.966 3,988 4.009 4,160 4.175 4.191 4.209 4,227 4.302 4.318
97. 4.043 4.057 4.072 4.088 4.260 4.268 4.279 4.291 4.304 4.385 4,396
D. ACCUMUL. ANN. COST ($1000)
2/. 60.166 69.661 77.833 87,733 99.617 110,348 122 .. 995 136.628 151.323 167,282 194,474
!5/. 62-.221 70.9/!:.4 80.394 90,532 101, 7'51 113.817 126.799 140.767 155.797 172.145 18'9,726
77. 63,7"8 72,731 82.341 '02,679 104.156 116.480 129.720 143.946 159.234 175.881 193.761
91. 65.488 74.625 84.439 94,081 106.734 119.334 132~850 147,352 162.916 17'9,883 199,083
E. ACCUMULATED PRESENT WORTH
ANNUAL COST ($1000)
2% 39.444 43.216 47.022 50.861 54 .. 806 58.780 {:.2.784 66.818 70.881 75,005 79, I 57
54 40.779 44.661 48.570 52.506 56 .. 572 60.6'59 64.769 68.902 73.058 77.283 91.529
n. 41.804 45.770 49.758 53.767 57.927 62.102 66.293 70.502 74.729 79.031 83.349
97. 42.904 46,961 51.033 551121 '59.381 63.649 67,928 72.219 76.523 80.909 95.304
4-A
1990 1991 19'92 19'93 1994 199'5 19'96 1997 1998 199'9 2000
F. ACCUI'l PRES WORTH OF ElEROY
"ILLS/KWH
2'X 1.382 1.481 1.~79 1.674 t.769 1.862 1.9'53 2.0"12 2.1~ 2.215 2.300
'!5Y. 1.429 1 ~~32 1.632 1.730 1.828 1.924 2 .. 017 2.108 2.197 2.28l5 2.371
n: 1.463 1.'!568 1.670 1. 769 1.869 1.967 2:.062 2.1'!1'5 2.246 2.336 2.424
9'X 1.'!101 1.608 1 '712 1.813 1. 916 2.016 2.113 2 .. 208 2.300 2.392 2.482
POI.IER COST STU[IY A!.. n:RNA IE S-A
D IU.l NGHA.'I ELVA -LOll LOAD
107l4 198!"> )981 198::' !983 1984 t<>8!:· 1986 19!;'17 1988 1989
1. LOAD DEMAND
DEMAND vw 1 ~ 40(1 1' 500 1. 608 1. 716 1, 824 1-932 2.040 2.148 :.::.2'56 ;?,365 2.472
ENERGY MWH 5.958 6,523 7.088 7.654 8,21Q 8.784 9,3'50 9.915 10,480 1 1 • 046 11.612
SOURCES KW
A. EX I STING DIESEL
LOCATION OR UNIT 1 2,t.oo ;;:,600 ::'.600 2.600 2·600 2.600 2.600 2.600 2.600 2,600 2.600
::'
3
4
5
6
7
8
<;>
10
1 1
12
B. ADDITIONAL DIESEL
UNIT 1
2 -1.ooo 1.ooo I .000 1.ooo 1.ooo 1 .ooo 1,000 1.000 t.ooo !. 000
3
4
5
6
c. EXISTING HYDRO
UNIT 1
2
o. ADDITIONAL HYDRO
UNIT 1 - - -1.500 1. 500 1.500 1.500 1. 500 1.500 I. 500
2
3
TOTAL CAPACITY -KW 2.600 3.600 3.600 3.600 !), 100 5.100 5.100 5.100 5.100 5. 100 5.100
LARGEST UNIT 1.000 1 .ooo 1 .ooo I ,Qoo I ,500 1.500 1.500 1.500 1.500 !.500 !.500
FIRM CAPACITY !. 600 2.600 2.600 2.600 3.600 3.600 3.600 3.600 3.600 3.600 3.600
SURPLUS OR <DEFICIT> KW 200 I, 100 992 884 t. 776 1. 668 1. 560 !.452 !. 344 1,235 !. 128
NET HYDRO CAPACITY -MWH -- - -
8.070 8.070 8.070 8.070 8.070 8.070 8.070
DIESEL GENERATION MWH S?958 o~S23 7.088 7.654 149 714 I, 280 j, 845 2.410 2.976 3.542
~-A
1'990 19'91 19'92 19'93 1'994 1"'95 1996 1997 19'98 1999 2000
1. LOAD DE~D
DEMNO-KW 2.580 2.687 2.794 2.901 3.oo8 3. 115 3.220 3.327 3.434 3.541 3.650
ElEROY -I'!WH 12.177 12.716 13.2'55 !3.794 14.::>34 14.873 !5.412 15.9!51 16.490 17.030 17.569
2. SOURCES -KW
A. EXISTING DIESEL
LOCATION OR UNIT 1 2.600 2.600 2,600 2.600 2.600 2.600 2.600 2.600 2.600 2.600 2:-.600
2
3
4
5
6
7
9
9
10
11
12
B. ADDITIONAL DIESEL
UNIT 1
2 t.ooo 1.000 1.000 t.ooo t.ooo 1.ooo t.ooo t.ooo 1.000 1.000 1.ooo
3 1.000 1.000 1.000 1.000 1.000 1.ooo 1.ooo 1.ooo 1.000 1.000 1.000
4
5
6
C. EXISTING HYDRO
UNIT 1
2
0. ADDITIONAL HYDRO
UNIT 1 1.500 1, 500 1. 500 1.500 1·500 1. 50(l 1.500 1.500 1.5oo I ,500 1. 500
2
3
TOTAL CAPACITY -KW 6.100 6.100 6.100 6.100 6o100 6.100 6.100 6.100 6.100 6.100 6.100
LARGEST UNIT I, 500 1. 500 I, 500 1.500 1. 500 1.500 !.500 1.500 1, 500 I ,500 I, '500
FIRf1 CAPACITY 4.600 4.600 4.600 4.600 4o600 4.600 4.600 4.600 4.600 4.600 4.600
SURPLUS OR <DEFICIT> -KW 2.020 J, 913 1.906 1.699 1.592 1.485 !.380 1.273 1.166 1, 0'59 950
NET HYORO CAPACITY -t1WH 8.070 8.o7o 8.070 8.070 8.o7o 8.070 8.070 8.070 e..070 8.070 8.070
DIESEL GENERATION -t1WH 4.107 4.646 5.18'5 '5.724 6.264 6.603 7.342 7.861 8.420 8.960 9.499
S-A
1979 1980 1 "'81 1"'8~ 1983 1"'84 1"'8'5 1"'86 1987 !988 19$9
3. INVESTMENT COSTS ($1000)
1979 DOLLARS
A. EX I STING DIESEL 1.550 j, 5'50 1.5'50 I. 5'50 1.'550 ], 550 1. '550 1. 550 1. :;.so 1.5'50 1.550
B. ADDITIONAL DIESEL
LINIT I -870 870 870 870 870 El70 870 870 870 870
2
3
4
5
6
c. EXISTING HYDRO
D. ADDITIONAL HYDRO
UNIT 1 ---12.940 12.940 ]2,.940 12 .. 940 12.,940 1::::",940 1:,>;140
2
3
E. TRANSMISSION PLANT ADDITIONS
UNIT 1
2
F. MISCELLANEOUS ADDITIONS
UNIT 1
2
TOTAL ($1000)
1979 DOLLARS 1.550 2.420 2.420 2.,420 15.360 15.360 15.360 15.360 15.360 15.360 15.360
INFLATED VALUES 1.550 2.490 2.490 2.490 20.095 20.095 20.095 20.095 20,095 20,095 20.095
4. FIXED COST <S1000)
INFLATED VALUES
A. DEBT SERVICE
1. EX I STING 66 66 66 66 66 66 66 66 66 66 66
2. ADDITIONS
SUBTOTAL 27. -38 38 38 742 742 742 742 742 74~ 742
57. -57 57 57 1' 116 1. 116 1' 116 1.116 I .116 I. 116 I, 116
77. -73 73 73 I, 433 1.433 I. 433 I ,433 1.433 I, 43'3 1. 433
9% 89 89 89 1' 755 I• 755 1 '755 1. 755 1. 75'5 1, 755 1.755
B. INSURANCE 5 8 9 9 82 89 92 96 100 104 108
5-A
1970 1980 1981 1982 1983 1984 19~ 19S6 1987 1988 1989
TOTAL FIXED COST CS1000l
27. 71 112 113 113 El90 897 900 9(14 908 912 916
54 71 131 132 132 1, 264 1, 271 1.274 1.278 1,282 1.286 1·~
77. 71 147 148 148 1.581 1.588 1.591 1.595 1.599 1.603 1.607
9::'. 71 163 164 164 1.903 1.910 1, 913 1, 917 1, 921 1.925 1,929
5. PRODUCTION COST CS1000l
INFLATED VALUES
A. OPERATION AND MAINT
1. DIESEL 169 233 25.6 2'82 23'5 260 276 292 310 330 350
2. HYDRO - - --7 7 8 8 8 9 9
B. FUEL AND LUBE OIL 412 497 '59'5 706 14 80 152 231 321 418 529
TOTAL PRODUCTION COST CS1000l 581 730 851 988 256 347 436 531 639 757 888
TOTAL ANNUAL COST CS1000l
27. 652 842 964 1, 101 1.146 1, 244 1.336 1.435 1.547 1.669 1.804
57. 652 861 983 1.120 1.520 1, 618 1, 710 1.809 1. 921 2.043 2.178
77. 652 877 999 1, 136 1.837 1, 93'5 2.027 2.126 2.238 2.360 2.495
9::'. 652 893 1.015 1.152 2.159 2.257 2.349 2.448 2.560 2.682 2.817
ENERGY REQUIREMENTS -MWH 5.958 6,523 7.088 7.654 8.219 8.784 9,350 9,915 10.480 11.046 11.612
MILLS/KWH
27. 109 129 136 144 139 142 143 145 148 151 155
5::'. 109 132 139 146 185 184 183 182 183 185 188
77. 109 134 141 148 224 220 217 214 214 214 21'5
9::'. 109 137 143 151 263 257 251 247 244 243 243
c. PRESENT WORTH
ANNUAL COST CS1000l
2::'. 652 787 842 899 874 887 El90 894 900 908 917
57. 652 805 859 914 1, 160 1.154 1. 139 1.127 1. 118 1. 111 1.107
77. 652 820 873 927 1.401 1.380 1· 351 1.324 1.303 1. 284 1.268
97. 652 835 887 940 1.647 1.609 1.565 1.524 1.490 1. 459 1.432
D. ACCU?'IUL. ANN. COST CS1000l
27. 6S2 1. 494 2.458 3.5'59 4.705 5.949 7.285 8.720 10.267 11.936 13.740
57. 652 1. 513 2.496 3.616 5.136 6.754 8.464 10.273 12.194 14.237 16.41'5
n. 652 1.529 2.528 3.664 5.501 7.436 9.463 11.589 13.827 16.187 18.682
97. 652 1· 54'5 2.560 3.712 5.871 8.128 10.477 12.925 15.48'5 18.167 20.984
E. ACCU?'IULATED PRESENT WORTH
ANNUAL COST <S1000l
2::'. 652 1.439 2.281 3.180 4.054 4,941 5.831 6.725 7.625 8.533 9,450
:57. 652 1.457 2.316 3.230 4,390 5.544 6.683 7.810 8.928 10.039 11.t46
77. 652 1. 472 2.34'5 3.272 4.673 6.053 7.404 8.728 10.031 11.315 12.583
97. 652 1.487 2.374 3.314 4.961 6.570 8.135 9.659 11. 149 12.608 14.040
S-A
1979 1980 1°81 108::.' !1>83 1<>84 1<>85 )986 )987 J<;88 1989
F ACCUM PRES WORTH OF ENERGY
MILLS/I<WH
2"1.. 10'9 230 349 467 573 674 76<> 859 <>45 1.027 1.106
5% 10<> 23~ 353 472 613 744 866 97<> 1' 086 1.187 1 '283
7% 10<> 234 357 478 64" 806 051 1.084 1 .20"' 1 ~ 325 1· 434
9/, 100 ~'37 3~::! 485 686 869 1.031:· 1.190 t .. 33::! 1. 464 ).588
5-A
19<>0 1991 1992 1993 19<>4 1995 1996 1':>97 1998 I <>9<> 2000
3. INVESTMENT COSTS <$1000>
1979 DOLLARS
A. EXISTING DIESEL 1.5'!50 1.550 1.5so 1.550 1.550 1.550 1.sso 1.550 1·550 I.SSO t.sso
B. ADDITIONAL DIESEL
UNIT 1 870 870 870 870 970 870 870 870 870 870 870
2 870 870 870 870 870 870 870 870 870 870 870
3 --------870 870
4 s
6 ---.-
C. EXISTING HYDRO
D. ADDITIONAL HYDRO
UNIT 1 12.940 12.940 12~940 12.940 12~940 12.940 12.940 12.940 12.940 12.940 12.940
2
3
E. TRANSMISSION PLANT ADDITIONS
UNIT 1
2
F". PUSCELLNIIEOUS ADDITIONS
UNIT 1
2
TOTAL <•1000>
1979 DOLLARS 16.230 16.230 16.230 16.230 16.230 16.230 16.230 16.230 16.230 17.100 17. 100
INFLATED VALUES 21.712 21·712 21.712 21.712 21.712 21.712 21.712 21.712 21.712 24.014 24.014
4. FIXED COST <•1000)
INFLATED VALUES
A. DEBT SERVICE
1. EXISTING 66 b6 66 66 66 66 66 66 66 66 66
2. ADDITIONS
SUBTOTAL 2'1. 807 807 807 907 807 807 807 807 907 899 899
5'7. 1.21!5 1. 215 1.215 1. 215 1.215 1.215 1' 215 I ,215 1.215 1.356 1.356
7'X 1.558 1 .sse 1.s5a 1 .sse 1 ''558 1.sss 1.5sa 1.sss 1.sss 1· 736 1. 736
9'7. 1.908 1.908 1. 908 1.908 1.908 1.908 1.908 1.908 1.908 27126 2.126
8. INSURANCE 121 126 131 136 142 147 153 159 166 191 198
S-A
1990 199! !9<>2 !9'?3 !994 1905 !996 !997 !999 1999 200<>
TOTAL FIXED COST ($1000)
27.. 994 999 1. 004 1.009 1· 0!5 1.020 1.026 1.032 1 ,Q3<;> 1· 156 1. 163
57.. 1.402 1, 407 1·412 1.417 1.,423 1o428 1· 434 1. 440 1.447 1.613 1.620
77.. 1, 745 1. 7'50 1. 755 1. 760 1.766 1.771 1.777 1.783 1, 790 1,993 2.000
97.. :!,.09~· :2.100 2.105 2, 110 2. 11¢. 2.121 2.127 2,133 2.140 2.383 2.300
~ .... PRODUCTION COST <S1000J
INFLATED VALUES
A. OPERATION AND MAINT
1. DIESEL 371 392 416 441 465 493 5""''"' ,_ 550 582 616 6"19
2-HYDRO <;> 10 10 10 11 1 1 12 12 13 13 14
B. FUEL AND LUBE OIL 1>'51 780 923 1.oao 1.2'53 1.443 1.6'50 1.678 2.123 2·39'5 2.691
TOTAL PRODUCTION COST ($1000) 1. 031 1 '182 1. 349 1 ''531 1· 729 1.947 2.184 2.440 2.718 3.024 3.35"1
TOTAL ANNUAL COST ($10001
2% 2.025 2. 181 2,353 2.'540 2.744 2.967 3.210 3.472 3.757 4.180 "1.517
'57.. 2.433 2.'589 2.761 2.948 3.152 3.375 3.6!8 3.880 4. 16'5 4.637 4.974
77.. 2.776 2,932 3.104 3,2'91 3.49'5 3.719 3.961 4.223 4.508 5.017 '5.35"1
97.. 3.126 3,282 3.4'54 3.641 3.845 4.068 4.311 4,573 4.858 5.407 5.744
ENERGY REQUIREMENTS -MWH !2. 177 12.716 !3.25'5 13.794 14.334 14.873 15.412 15.951 16.490 17.030 t7.S6<>
MILLS/KWH
27. !66 172 178 184 191 199 208 218 228 245 257
57.. 200 204 208 214 220 227 235 243 253 272 283
77.. 228 231 234 239 244 250 2S7 265 273 295 305
97.. 257 2'58 261 264 268 274 280 287 29'5 317 327
c. PRESENT WORTH
ANNUAL COST ($!000)
2~ 962 968 976 99'5 995 1 .oos 1.016 1.027 1.039 1,090 1 ,oot
57. 1' !56 1.150 1.146 1.143 11'142 1.143 1. 14'5 1.148 lo152 1' 198 1 '201
77. 1.3!9 1.302 1, 288 1. 276 1-267 1. 2'59 1.254 1' 249 1.246 1.296 1.293
97.. 1.48'5 1.457 1.433 1.412 1. 394 1.378 1.365 1.353 1. 343 1.397 1· 387
D. ACCliMUL. ANN. COST ($1000)
2'1. 1'5.76~ 17.946 20.299 22.839 25.583 28.5'50 31.760 35.232 38.989 43.169 47.6Bb
S'X 18.84€' 21.437 24.199 27.146 30.298 33.673 37.291 41.171 45.336 49.973 54.947
77. 21.459 24.390 27.494 30.785 34,280 37.998 41.959 41!>.182 50.690 55.707 61.061
97.. 24.110 27.392 30.846 34.487 38.332 42.400 46.711 51.284 56. 142 61.549 67?293
E. ACCUMULATED PRESENT WORTH
ANNUAL COST ($1000)
Z% 10.412 11.380 12.356 13.341 1"1.336 15.341 16.357 17.384 18.423 19.503 20.'594
57. 12.302 13.452 14.59€' 15.741 16.883 18.026 19.171 20.319 21,471 22.669 23.870
77. 13.902 15.204 16.492 17.768 19.03'5 20.294 21.548 22.797 24.043 25.339 26.632
97.. 15,525 16,982 18.415 19.827 21.221 22.'599 23.964 25.317 26.660 28.0'57 29.444
~A
1990 1991 1<>92 1093 19'!N 1<>95 1996 1997 1998 190<> 200(1
F. ACCUI'I PRES WORTH OF ENERGY
lULLS/KWH
n 1.185 1· 261 1.335 1.406 1.<17'5 1.542 I ,608 I ,672 1, 735 1.798 1.860
!n I, 378 1.<169 1. '5'55 1.638 1, 718 1.7~ 1.869 I, 9<1 I 2.011 2.081 2.1<19
n; 1.5<12 I ,6<15 1· 7<12 1.835 1.923 2.008 2.089 2.167 2.242 2.318 2.392
en. I. 710 1.825 1.933 2.035 2.132 2.225 2.314 2.399 2.481 2.563 2.6<12
READY
POioiER COST STL'!">Y ALTEI\liATE 5-B
D1LLIN~1 -ELVA -HIGH LOAD
1"'79 198" 19$1 1982 19133 1994 198'5 1996 1987 1998 1999
l. LOAD DEMAND
DEMAND KW 1 '400 1 '500 1 '74t. 1 ~ 9°2 2.2:38 2.489 2.730 .2 .. 776 3 .. 222 3.468 :3 .. 712
ENERGY -MWH '5. Q~,<J 7 .. 281 8.6(17 9.983 11 '358 12.73'5 14.110 15.485 16.862 18.237 19.612
2. SOURCES KW
A. EXISTING DIESEL
LOCATION OR UNIT 1 2.600 2.600 2.600 2.600 2,600 2.600 2.bOO 2.b00 2 .. 600 2.600 2.600
2
3
4
'5
6
7
8
9
10
11
12
B. ADDITIONAL DIESEL
UNIT l l .ooo 1.ooo 1 .ooo 1.000 1.ooo 1.000 1.000 1 '000 1 .ooo 1.ooo
2 ------1.ooo 1 .ooo
3
4
5
6
c. EKlSTING HYDRO
UNIT 1
2
o. ADDITIONAL HYDRO
UNIT 1 ----1.soo 1,soo t.soo 1.500 1. '500 1 .soo t.soo
2
3
TOTAL CAPACITY -KW 2.b00 3.600 3.bOO 3.bOO 5,100 '5. 100 '5. 100 s. 100 '5.100 b. 100 b. 100
LARGEST UNIT 1.ooo 1.000 1.000 1 .ooo 1.500 1.500 1 .soo 1 .soo 1 .soo 1 ''500 1.500
FIRM CAPACITY 1d•OO 2.bOO 2.b00 2.bOO 3.bOO 3.600 3.b00 3.!>00 3,bOO 4,bOO 4.bOO
~JRPLUS OR <DEFICIT) -KW 200 1' 100 8'54 b08 1 .3b2 1.111 970 824 378 1. 132 889
NET HYDRO CAPACITY -MWH ----8.070 8.070 8.070 8.070 8.070 8.070 8.070
DIESEL GENERATION -MWH 5,959 7.231 8.607 9,983 3.288 4.bb5 b.040 7.415 8.792 10, 167 11 '542
:i-B
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 zooo
1. LOAD DE~D
DE~D-KW 3.960 4.430 4.900 5.370 5.840 6.310 6.780 7.250 7.720 8.190 8.660
ENERGY -I'IWH 20.988 23.896 26.EtQ4 29,711 32.619 3!5.!527 38.483 41.343 44.251 47.1!5" SO,Ob7
2. SOllf!CES -KW
A. EXISTING DIESEL
LOCATION OR UNIT 1 2.600 2.600 2.600 2.600 2t600 2.600 2.600 2.600 2.600 2.600 2.600
2
3
4
5
6
7
8
9
10
11
12
B. ADDITIONAL DIESEL
UNIT 1 1.000 1.000 }.000 1.000 1 .ooo 1.ooo 1.ooo 1 .ooo 1.ooo 1.ooo 1.000
2 1.000 1.ooo 1.000 1 .ooo 1.ooo 1.ooo 1.ooo 1.ooo 1.ooo 1.ooo 1.000
3 2.600 2.600 2·600 2.600 z,.ooo 2.600 2.600 2.600 2.600 2,600
4 ----2.600 2.600 2.600 2.600 2.600 2.600 2.600
5
6
C. EXISTfNG HYDRO
UNIT I
2
D. ADDITIONAL HYDRO
UNIT 1 1.500 1>:500 1.:500 1.500 1.500 1.500 1,5oo 1.500 1.500 I • :500 1.500
2
3
TOTAL CAPACITY KW 6.100 8,700 8.700 8.700 11.300 11.300 11.300 11.300 11.300 11.300 11.300
LARGEST UNIT 1.500 2.600 2.600 2·600 2.600 2.600 2.600 2.600 2.600 2.600 2.600
FIR'I'I CAPACITY 4.600 6,100 6t100 6.100 8.700 8.7oo 8.700 8.700 8.700 8.700 8.700
SL~PLUS OR <DEFICIT> -KW 640 1.670 1.200 730 2.860 2.390 1.920 1.450 980 510 40
NET HYDRO CAPACITY -~WH 8.070 8.070 8.070 8.070 8.070 8.070 8.070 8.070 8.070 8.070 8.070
DIESEL GENERATION -~WH 12.918 1'!5.826 1a,734 21.641 24.549 27.4:>7 30.413 33.273 36. 181 39.089 41.997
S-B
1">70 1980 1981 198: !983 1984 1085 !986 19S7 1988 1989
3. INVESTMENT COSTS <S1000
1979 DOLLARS
A. EXISTING DIESEL !. 5'50 I, 550 t .,s~o 1 • 5'5(" l ~ 5'50 1.550 I. 550 1.550 I. 550 I .550 1.550
B. ADDITIONAL DIESEL
UNIT 1 870 870 870 870 870 870 870 870 870 870
:: --870 870
3
4
5
6
c. EXISTING HYDRO
D. ADDITIONAL HYDRO
UNIT 1 -12,'>40 12 .. '940 12,94(\ 1;',04(\ 12.940 12,940 12.940
2
3
E. TRANSMISSION PLANT ADDITIONS
UNIT 1
2
F. MISCELLANEOUS ADDITIONS
UNIT I
2
TOTAL (ti!OOO)
1979 DOLLARS 1. 5'50 2?420 2.420 2.420 15.360 15.360 15.360 15.360 15.360 16.230 16.230
INFLATED VALUES 1.550 2.490 2.490 2.490 20.095 20.095 20.095 20.095 20.095 21.590 21.590
4. FIXED COST (ti1000>
INFLATED VALUES
A. DEBT SERVICE
1. EXISTING 66 66 66 66 66 66 66 66 66 66 66
2. ADDITIONS
SUBTOTAL 2':1. 38 38 38 742 742 742 742 742 802 802
sx 57 57 57 1. 116 1.116 I, !16 1.! 16 1' 116 I, 207 I ,207
7':1. -73 73 73 I. 433 1,433 1.433 1 '433 I ,433 1.548 1.548
97. 89 89 89 1' 755 I, 755 1.755 I, 755 1.755 I, 896 1,8'>6
B. INSURANCE 5 8 9 9 82 89 92 96 100 111 116
~-B
197<;1 1980 1<>91 198:::! 1993 1984 lOSS 1996 1987 }Q88 1989
TOTAL FIXED COST l$1000)
2% 71 112 113 113 890 8'>7 900 904 908 979 984
~% 71 131 132 132 1, 264 1. 271 !, 274 1.278 1· 2'82 1.W4 1.389
77. 71 147 149 149 !. 581 1.588 1. '!iQI 1.59'5 !.5Q9 1.72~ I, 73Q
9')! 71 163 164 164 },903 1 '9!0 1, 913 1.917 J, 921 2.073 2.079
5. PRODUCTION COST ($1000!
INf'LinED VALUES
A. OPERATION AND ~AINT
1. DIESEL 169 239 268 302 264 299 325 352 393 414 447
2. HYDRO ---7 7 a 8 8 9 9
B. FUEL AND LUBE OIL 412 552 721 921 333 521 715 930 1· 169 !.434 !. 724
TOTAL PRODUCTION COST ($1000) 581 790 989 1.223 604 827 1.048 1. 290 1. 'ShO !.857 2.100
TOTAL ANNUAL COST ($1000!
2% 652 902 1 ,.102 ,, 3:!16 t. 494 1. 724 I, 948 2.194 2.468 2.836 3.164
5% 652 921 1,. 121 1.355 1.868 2.098 2.322 2.568 2,842 3.241 3.569
7% 652 937 1.137 I· 371 2, 18~ 2.415 2.63Q 2.885 3. !59 3.'582 3,Q}0
9% 652 953 1.153 1.397 2.507 2,737 2.961 3.207 3.481 3.930 4,258
ENERGY REQUIREMENTS -MWH 5.958 7.,231 9.607 9.983 11.358 12.735 14 .t 10 15.485 16.862 18.2:37 19.612
~ILLS/KWH
27. 109 1:25 128 134 132 135 138 142 146 !56 161
5% 109 127 130 136 164 165 16'5 166 169 178 182
n: 109 130 132 137 192 190 187 186 IB7 196 199
<n: 109 132 134 139 221 215 210 207 206 215 217
c. PRESENT WORTH
ANNUAL COST !SIOOOl
27. 652 843 963 1.091 I, 140 '· 229 1.298 !. 366 I ,436 1.543 1.608
5% 652 861 979 1.106 1. 425 1.496 1. 547 1.599 1.654 ,, 763 1. 814 n 652 876 99:::1 I, 119 1.667 ,, 722 1.758 I, 797 1.939 1.949 1.988
9:r. 6~2 891 !.007 1, 132 1.913 1.951 1.973 1,997 2.026 2.138 2.165
D. ACCLIMUL. ANN, COST ($1000)
TJ; 652 1.554 2.656 3.992 5.486 7.210 9.158 11.352 13.820 16.656 19.820
s:r. 652 1.573 2.694 4,049 5.917 8.015 10.337 12.905 15.747 18.988 22·557
77. 652 1.589 2.726 4.097 6,292 8.697 11.336 14.221 17.380 20.962 24.872
9% 652 1.605 2.758 4.145 6.652 9.389 12.3'50 15.557 !9,03S 22.968 27.226
E. ACCUMULATED PRESENT WORTH
ANNUAL COST l$1000!
2:r. 652 1.495 2.458 3,~49 4.689 5.9!9 7.216 e,5s2 10.019 I I , '561 13.169
5% 6'52 1,513 2.492 3.'598 5.023 6.519 8.066 9.665 11.319 13.082 14.896
7% 6'52 1.528 2,521 3.640 5.307 7.029 8.787 10.584 12.423 14.371 16.3'59
9'Y. 652 1.543 2.'550 3.692 5.'59'5 7.546 9,~19 11.'516 13.542 1'5.680 17 .84'5
5-l\
197~ JOS(l !08! 1982 1983 !984 1985 198~ !987 1988 198"'
F. AC'Cll!'l PRES WORTH OF ENERC:Y
MJLLS/I<WH
2i: 10" 22~ 338 447 548 644 73~ 824 90° 994 1.07~
s:: 10" 228 342 453 578 696 80~ 909 1.007 I, 104 I, !97
7% 10" 230 345 457 ~03 738 863 <>79 I .oss 1.195 1.296
"X ' ,~ ,") 232 34" 462 631 784 924 I ,053 1, 173 1 ·290 !.400
s-B
1990 1°91 10"9~ 1093 1<>94 199'5 1906 19<>7 1 o<>g 1999 2000
3. INVESTMENT COSTS <S1000)
1979 DOLLARS
A. EXISTING DIESEL 1 • '5'50 1.'5'50 1. '5'50 1 ,'550 1. '5'50 1 • '5'50 1.5'50 1. 5'50 1.550 1.550 1.550
B. ADDITIONAL DIESEL
UNIT 1 870 870 870 870 870 870 870 870 870 870 870
2 870 870 870 870 870 870 870 870 870 870 870
3 -2.26: 2,262 2.262 2.262 2.262 2.262 2.262 2 .. 262 2.262 2.262
4 - -
--2.262 2.:262 2.262 2.262 2.262 2.262 2.262
'5
b
c. EXISTING HYDRO
D. ADDITIONAL HYDRO
LINIT 1 12.940 12.940 12,940 12.940 12.940 12.940 12.940 12.940 12,940 12.940 12.940
2
3
E. TRANSMISSION PLANT ADDITIONS
LINIT 1
2
F. MISCELLANEOUS ADDITIONS
UNIT 1
2
TOTAL ($1000)
1979 DOLLARS 16.230 18,492 18.492 18.492 20.754 20.754 20.754 20.754 20.754 20.754 20.754
INFLATED VALUES 21, '590 2'5.964 25.964 25.964 30.884 30.884 30.884 30.884 30.884 30.884 30.884
4. FIXED COST ISIOOO>
INFLATED VALUES
A. DEBT SERVICE
I. EXISTING 66 66 66 66 66 66 66 66 66 66 66
2. ADDITIONS
SLIBTOTAL 2~ 802 977 977 977 I. 174 I, 174 I, 174 I, 174 1.174 I. 174 1.174
5% 1.207 1.474 1.474 1.474 1.774 1. 774 1.774 1.774 1. 774 1. 774 1.774
77. I. '548 I ,886 1.886 1.88t. 2,266 2.266 2.266 2.266 2.266 2.266 2.266
97. 1.896 2.310 2.310 2.310 2.776 2.776 2.776 2.776 2.776 2.776 2.776
B. INSLIRANCE 120 151 157 163 202 210 218 227 236 245 25S
5-B
1990 1991 1~92 1993 1994 1995 1906 1997 1908 1999 2000
TOTAL FIXED COST ($1000)
2•t. 988 I, 194 I .200 I .206 1.442 1.450 j .458 1.467 1.476 1.4~ 1 .. 405
5% I. 3°3 I, 691 1,607 I, 703 2.042 2.050 2.058 2.067 2.076 2.085 2.095
7% I, 734 2, 103 2. 109 2.115 2.534 2,542 2 .. 550 2 .. 559 2.568 2.577 2.587
9% 2.08::' 2.527 2.533 2.539 3.044 3.052 3.060 3.069 3.078 3.087 3.097
5. PRODUCTION COST CSIOOOl
INFLATED VALUES
A. OPERATION AND MAINT
I. DIESEL 481 616 681 750 822 900 983 I .069 1 > 162 1. 262 1. 364
2. HYDRO 9 10 10 10 11 11 12 12 13 13 14
B. FUEL AND LUBE OIL 2.046 2.656 3.332 4.079 4.908 5.818 6.830 7.920 9.128 10.457 11.908
TOTAL PRODUCT! ON COST ($1000) 2.536 3,282 4,023 4 .. 839 5.741 6.729 7 .. 8~ 9,001 10.303 11.732 13.286
TOTAL ANNUAL COST ($1000)
2% 3.524 4,476 5.223 6.04~· 7.183 8.179 9 .. 283 10.468 11.779 13.217 14.781
57. 3,929 4,973 5,720 6.542 7.783 8.779 9.883 11.068 12.379 13.817 15.381
7% 4.270 5.385 6,132 6,954 8.275 Q,271 10.375 11.560 12.871 14.309 15.873
9% 4.618 5.809 6.556 7.378 8.785 9,781 10.885 12.070 13.381 14.819 16.383
ENERGY REQUIREMENTS -MWH 20.988 23.896 26.804 29.711 32.619 35.527 38.483 41.343 44.251 47.159 50.067
MILLS/KWH
2?'. 168 187 195 203 220 230 241 253 266 280 295
5% 187 208 213 220 239 247 257 268 280 293 307
7% 203 225 229 234 ~4 261 270 280 291 303 317
9% 220 243 245 248 269 275 283 292 302 314 327
c. PRESENT WORTH
ANNUAL COST ($1000)
2% 1.674 1.987 2.167 2.344 2.603 2.771 2.939 3.097 3.257 3.416 3.570
5% 1. 867 2.208 2.374 2.537 2,821 2.974 3.129 3 .. 275 3.423 3.571 3.715
7"1. 2.029 2.391 2.545 2.697 2,999 3.140 3.284 3.420 3.559 3.698 3.834
9"1. 2. 194 2.579 2.721 2.861 3.184 3.313 3.446 3.571 3.700 3.830 3.957
D. ACCUMUL. ANN. COST ( $1000)
2% 23.344 27.820 33.043 39.088 46.271 54.450 63.733 74.201 85.980 99.197 113.978
5% 26.486 31.459 37.179 43.721 51.504 60.283 70.166 81.234 93.613 107.430 122.811
7"1. 29.142 34.527 40.659 47.613 55.888 65.159 75.534 87.094 99,965 114.274 130.147
9% 31.844 37.653 44.209 51.587 60.372 70.153 81.038 93.108 106.489 121.308 137.691
E. ACCUMULATED PRESENT WORTH
ANNUAL COST ($1000)
2"/. 14.843 16.830 18.997 21.341 23.944 26.715 29.654 32.751 36.008 39.424 42.994
5% 16.763 18.971 21.345 23.882 26.703 29.677 32.806 36.081 39.504 43.075 46.790
7% 18.388 20.779 23.324 26.021 29.020 32. 160 35.444 38,864 42.423 46.121 49.955
9% 20.039 22.618 25.339 28.200 31.384 34.697 38. 143 41.714 45.414 49.244 53.201
5-B
19Q() 1QQ1 1'992 tOQ~ 1"'"'4 1'9<>'5 !096 1<><>7 19"'8 JOOO :?one;
F. ACCUM PRES WORTH OF ENERGY
!'!ILLS/KWH
2% I, I '56 1.2:::>9 1· 320 1,399 1. 479 1 • '5'57 1.633 1, 708 1. 782 1.8'54 1.92'5
'5% 1.2:86 1. 379 1.4b6 I , '5'51 1·638 1 ~ 722 1.803 1 t88:2 1' 9'50 2.0~ 2 .. 100
7:1. 1,3~:2 t.492 1. '587 1.679 1. 770 1.8'58 1,Q43 2.026 2.106 2.184 ~,261
9'1. 1.50'5 1.613 1, 71 '5 1. 811 1.<>os 2.001 2.091 2,177 2,261 2.342 2.421
POWER ('r)"OT S TIJOY ALTERNATE 6-A
DltLI~GHA!1 -'~R.A.~T -LOW LOAD
1979 1 "08·~' !981 1?82 !'>83 1 '0')4 1?8'5 1986 1987 1933 1989
I. LOAD DEMAND
DEMAND -KW I. 400 l. '500 1.603 1. 716 t. 824 l '?'32 2 .. 040 2. !48 2.256 2.365 2.472
ENERGY -MWH 5.958 6,~23 7.088 7.6'54 8.219 '3· 784 9 .. 3~0 9.<>1'5 10.480 II, 046 II, 612
2. SOURCES -KW
A. EXISTING DIESEL
LOCATION OR UNIT I ::.,600 :: ~ t:.on 2.60u 2 .. 6()0 2.600 2.600 2 .. 600 2.600 2.600 2.600 2.6QO
3
4
'5
6
7
3
9
10
11
12
6. ADDITIONAL DIESEL
UNIT 1
2 -1.000 1.000 1 .ooo I .000 1.ooo 1.ooo 1.ooo 1.ooo I .000 1.ooo
3
4
5
6
c. EXISTING HYDRO
UNIT I
2
D. ADDITIONAL HYDRO
UNIT I ----2.700 2.700 2.700 2.700 :2.700
2
3
TOTAL CAPACITY KW :2.600 3.600 3.600 .600 3.600 3.600 6.300 6.300 6.300 6.300 6.300
LARGEST IJNIT 1.ooo I· 1)00 1.ooo .ooo 1.ooo I, 000 2 .. 700 2.700 2.700 :2.700 2.700
FIRM CAPACITY I ,600 2,600 2,6()0 .600 2.600 2.600 3.600 3.600 :;.600 3.600 3.600
SURPLUS OR <DEFICIT) -KW 200 I, 100 QQ2 884 776 669 I ,560 I. 452 I, 344 1' 23~ I, I :.C8
NET HYDRO CAPACITY MWH -----11.700 11. 70<) 11.700 11.700 11.700
Dlt~EL GENERMtiON MWH '5.959 6t52J 7.098 7.6'54 8.,21Q 8.784
-
6·A
1'~>90 199! 1092 !99:;l 1°94 J09'5 1906 1"97 !09$ 1<>99 2000
1. 1. OAD DE !'lAND
DEI'IAND -KW 2.5!'\0 :2.6!'\7 2 .. 794 2.901 3.008 3.11'5 3.220 3~327 3. 434 3.~41 3.6'50
ENERGY -l'tWH 12.177 12.716 13.:255 13.794 14.334 14.873 1S,412 15.9'51 lb.490 17.030 17.569
2. SOURCES -KW
A. EXISTING DIESEL
LOCATION OR UNIT I 2.600 2.600 2.600 2.600 2 .. 600 2.600 2.600 2.600 2-600 2.600 2,600
2
3
4
5
6
7
a
Q
10
I I
12
B. ADDITIONAL DIESEL
UNIT I
2 1.000 I. 0~)0 1. 000 1.000 1.000 I, 000 1.000 1.000 1.000 I .000 J,(l()t)
3 --------'500 500
4
5
6
c. EXISTING HYDRO
LIN IT 1
2
o. ADDITIONAL HYDRO
UNIT I 2.700 2.7oo 2.700 2,700 2. 700 2.700 2.700 2,700 2 .. 700 2.700 2.700
2
3
TOTAl. CAPACITY -KW 6.300 6.300 6.300 6.300 6.300 6.300 6.300 6.300 6.300 b.800 6.800
LARGEST UNIT 2.700 2.700 2.700 2 .. 700 2.700 2 .. 700 2.700 2.700 2.700 2.700 2.700
FIRM CAPACITY 3.600 3.600 3.600 3.600 3.600 3.600 3.600 3.600 3.600 4.100 4.100
SURPLUS OR <DEFICIT) -KW 1-.020 913 806 699 592 48'5 380 273 166 5'59 450
NET HYDRO CAPACITY -I'IWH II. 700 11.700 11.700 11.700 11.700 11.700 11.700 11.700 11.700 11 '700 11.70()
DJESEL GENERATION -MWH 477 1.016 1, '5'5'5 2.094 2.634 3.173 3.712 4.2'51 4.790 '5.330 '5.869
6-A
1Q70 1"'80 1"'81 !Q8:' 1983 1"'8'1 198~ !986 1Q87 !988 !980
3. INVESTMENT COSTS (~10001
1"'79 DOLLARS
A. EXISTING DIESEL I, 550 1. 550 1.55fl 1.550 1.5~0 !. ~50 1.550 1.~50 1.550 1.550 1.550
B. ADDITIONAL DIESEL
UNIT 1
~ -870 870 870 870 870 870 870 870 870 870
3
4
5
6
c. EXISTING HYDRO
D. ADDITIONAL HYDRO
UNIT I ----1"'.36? 19,362 19,36? 1"'.36? 19,362
:::::
E. TRANSMISSION PLANT ADDITIONS
IJNIT 1
::'
F. MISCELLANEOUS ADDITIONS
UNIT 1
::
TOTAL ($1000)
1979 DOLLARS 1.550 2.420 2.420 2.420 2.420 2.420 21.782 21.782 21,782 .21~782 21,782
INFLATED VALUES 1, 550 2 .. 490 2.490 2.490 2.490 2.490 32.077 32.077 32.077 32.077 32.077
4. FIXED COST ($1000)
INFLATED VALUES
A. DEBT SERVICE
1. EXISTING 66 66 66 66 66 66 66 66 66 66 66
2. ADDITIONS
SUBTOTAL 2'% -38 38 38 38 38 1,221 1, 221 1 .. 221 1, 221 1 '221
5% -57 57 57 57 57 1.837 1.837 1. 837 1.837 1.837
71. -73 73 73 73 73 2 .. 358 2 .. 358 2.358 2 .. 358 2.358
91. -89 89 89 89 89 2.889 2.889 2.889 2.889 2.889
B. INSURANCE 5 8 9 9 10 11 147 153 159 165 172
6-A
1<;179 1<;180 1981 t<1S2 1983 1<;184 J<;l8'5 1986 1<>s7 t<>8? toe<>
TOTAL FIXED COST (fl000)
::::.'~ 71 112 113 113 114 11'!5 t. 434 I. 440 1. 446 1 "452 1.4'!5°
'!5:: 71 131 13~ 132 133 1'34 2.0'!50 2.0'56 =.062 2.068 z,o7~
7"1. 71 !47 !48 148 149 150 2.571 2.577 2.583 ::-.ss<:) ;:.,~96
9'l. 71 163 164 164 16'!5 166 3.102 3. 108 3. 114 3.120 3.127
5. PRODUCTION COST atoOOJ
INFLATED VALUES
A, OPERATION AND MAINT
1. DIESEL !69 233 256 282 310 330 263 273 284 29'5 307
2. HVORO -----q 10 10 12 13
B. FUEL AND Lllf:lE OIL 412 497 59'5 706 834 980
TOTAL PROPLICTION COST <S1000> '58! 730 8'51 988 1.144 1.31° 27: 283 294 307 320
TOTAL ANNUAL COST ('J!000)
2/. 652 84::' 964 1, !01 1 .. 258 t. 434 '· 706 ,, 723 !. 740 1.7'59 1, 779
5% t.S2 St. I 983 1 ~ 120 ,, 277 1. 4~".'3 2.322 2,339 2-356 2.37~ 2,39~
n. 652 877 Q9Q 1, 136 1' 2Q3 1· 469 2.843 2.860 2.977 2.896 2.916
9% 652 803 1 t 015 1.1~~ 1.309 I· 485 3.374 3,39! 3.408 3.427 3,447
ENERGY REQUIREMENTS -MWH 5.9'58 6.523 7.088 7.6'54 8.219 8.784 9.3'!50 9,91'5 10.480 11.046 11·612
!'!ILLS/KWH
2"1. 109 129 136 144 1'53 163 182 174 166 1'59 153
57. to<> 132 139 146 155 165 248 236 225 215 206
77. 109 134 141 148 157 167 304 288 27'5 262 2::51
9"1. 109 137 143 1'51 159 169 361 342 325 310 297
c. PRESENT WORTH
ANNUAL COST C'JIOOOJ
2'Y. 652 787 842 899 960 1.022 1.137 1.073 1, 013 9'57 904
5X 65.2 80'5 Er-59 914 974 1.036 1. :547 1.4'57 1. 371 1,292 1.217
77. 6'52 820 873 927 986 1.047 1.894 1. 781 1.674 1 ''575 1.482
9'Y. 6'52 835 887 940 999 1.,059 2.248 2. 112 1,983 1· 864 1 .. 752
D. ACCUI1UL. ANN. COST ($1000)
2'Y. 6~2 1.494 2.4'58 3.559 4.917 6.2'51 7.957 9,680 11.420 13.179 14.958
'5'X 652 1.'513 2.496 3.616 4.893 6.346 8.668 11.007 13.363 1'5.738 18.133
7'Y. e. 52 1. '529 2.'528 3.664 4,957 6.426 9.,Zb9 12. 129 1'5.006 17.902 20.818
9'l. 652 1. '545 2.560 3.712 5.021 6.506 9.980 13.271 16-.679 20. 106 23.553
E. ACCUMULATED PRESENT WORTH
ANNUAL COST ('J1000)
2'l. ~·"52 1.439 2r281 3.180 4.140 '5. 162 6-.2Q9 7.372 8.38"5 9.342 10.246
57. ~·S2 1t457 2.316 3.230 4.204 5.240 6.787 8.244 9.,015 10.907 12.124
7'l. 6'52 1· 472 2.34'5 3 .. 272 4,.2S~ ~ .. 30~ 7.199 8.980 10.b'54 12.229 13.711
9'Y. 652 1.487 2.374 3.314 4.3!3 5.372 7.b20 9.732 11.715 13.579 1'5.331
OcY!O & o-"'('I') O'"J
0 -MI{) .() ro
('
< I .,
r ~ ro r ,j (f)
-.uo "' [f, -~~ 'l;f ,-,
ro
0
.u -o 0
(.j I() V"! .(!
" 0-('.j "' ro
0
0 C• 0 C· ( ~ (' ~ 0 CfJ
.(! 0 oo -ro
0
..... (*'IC. r
( ~ ,..._ ('I "'' ,-, ro (Jj o 0
OJ
0
C· 0) f'. "'' 0 0 ....... (I
" """ r
CfJ
0
q" C.•rJ'.I .(!
(iJ 0 0 0 ,, V"II(JI{j -(;
UJ
0
,... (,j OJ If!
.(!"" o-,
(I ...... " ,,,
"
0 f,.l,..,.. (I
'l;f \(! l(i -(;
(Y}(ri('! c··l
UJ
0
C· (~ ¢ r
{YJ('Jf'J r~.
0 (j(l(l fi
(f,
0
0 0 0 0
C C. C• C•
ff ,,
C•
>-<:: a: w z w
u.
0
I
I-a:
0
3 ~~...: ~~
N \(!"' 0
(/> w I a: 3
"-2:'
1: "' :J __J
lJ __J
lJ
<I J:
..:
6-A
1990 1991 1QO: 1°02 J004 lOOS J006 J007 1Q0 8 JOOO .::'000
3. INVESTMENT COSTS (SlOOOl
1979 DOLLARS
A. EXISTING DIESEL 1 .~~0 1 .sso 1?550 l.SSO 1.'5'50 1.~so t.sso 1 .~so 1 .sso !.S'SO 1 .sso
B. ADDITIONAL DIESEL
LINIT I --- --- -
----
2 870 870 870 870 870 870 870 870 870 870 870
3 - -
---- -- -435 435
4
s
6
c. EXISTING HYDRO
D. ADDITIONAL HYDRO
UNIT 1
2 19,362 19.36.::' 10,36.::' 19,362 19.36:' 10,3(..: 10,362 1".362 19,362 10,362 19.362
3
E. TRANSMISSION PLANT ADDITIONS
LINIT I
2
F. MISCELLANEOUS ADDITIONS
UNIT I
2
TOTAL <SIOOOl
1979 DOLLARS 21.782 21.762 21,782 21.782 21.762 21.762 21.782 21.782 21.782 22.217 2~.217
INFLATED VALUES 32.077 32.077 32.077 32.077 32.077 32.077 32.077 32.077 32.077 33.228 33.228
4. FIXED COST (SlOOOl
INFLATED VALUES
A. DEBT SERVICE
I. EXISTING 66 66 66 66 66 66 66 66 66 66 66
2. ADDITIONS
SUBTOTAL 2Y. 1.221 1' 221 1.221 1·221 1.221 1.221 1.221 1.221 1.221 1·267 1.267
57. 1.637 1.837 1.837 1.837 1 .8::<7 1.837 1.837 1.837 1.837 1,907 1,907
77. 2.3'58 2.358 2.358 2.358 2.358 2.358 2.358 2.3'58 2.3~8 2.447 2.447
97. 2.88° 2.889 2.88" 2.880 2.88° 2.889 2.889 2.889 2.689 2.998 2,998
B. INSURANCE 179 186 194 201 209 218 226 23'S 245 264 274
TOT~L FIXED COST <S1000l
2%
'5~~
7')'.
"''%
5. PRODUCTION COST l$10001
INFLATED VALUES
A. OPERATION AND MAINT
1. DIESEL
2. HYDRO
F. FUEL AND LUBE OIL
TOTAL PRODUCTION COST IS10001
TOTAL ANNUAL COST l$10001
51.
71.
'>'%
ENERGY REQUIREMENTS -MWH
MILLS/KWH
:n:.
57.
7%
9%
C. PRESENT WORTH
ANNUAL COST IS1000l
2%
57..
7Y.
9/.
D. ~CCUMUL. ANN. COST IS10001
2Y.
5%
7Y.
'"'I.
E. ACCUMULATED PRESENT WORTH
ANNUAL COS:T I S 1000 I
21.
5/.
71.
9/.
lQO(l
I, 4&f
2.082
2.603
3· 134
32~·
13
75
4l3
l· 879
2· 4°-:-,
3~016
3,547
12. 177
154
205
248
2q1
893
t. 185
1, 433
I, 685
16d337
20~628
23~834
27' 100
11' 139
13.309
15.144
17.016
1<1'>1
1' 473
"2~08°
2~610
"' 141
34t
14
170
530
2, oo:::
:?~61Q
:<' 140
3,671
12,716
158
206
247
289
88<>
1' 163
1 '394
I ,630
18.840
23.247
26,974
30,771
12,028
14.472
16,.S38
18.646
tQO=
1.481
,QQ"'1
61E:
14°
368
14
:77
65<>
2,140
2.756
3.277
3-.808
13?2'55
161
208
247
287
888
1. 144
1.360
1,580
20,980
26.003
30.2'51
34.579
12,916
15,616
17.898
20,226
l":)OJ
1.488
2. 104
~,62'5
:::, \Sf
380
15
3C>5
7<>0
:,287
:,903
3.424
3,9'55
13.7'>4
166
210
248
287
887
1' 126
1.328
1,534
23.267
28,906
33.e.75
38,5'34
13.803
16,742
19,226
21.760
10Q4
1,496
~-11~
2.633
2. lf:-.4
413
15
527
95":.
2 .. 451
3.ot.7
3.588
4.11 Q
14.334
171
214
250
287
888
1' 112
1. 300
1 '493
2'5.718
31.973
37.263
42,6S3
14,691
17.,854
20.,526
23.253
lQQ~,
1,505
2? 121
2.642
3. 173
436
16
673
1' 125
2.630
3. 24~.
3.767
4,298
14.873
177
218
253
28"'
891
1.100
1.276
1, 456
28 .. 348
35.219
41,(130
46.951
15.582
18,'954
21.802
24,709
l ''"'I->
1 '513
:: .. 1:29
~.650
3, 181
463
16
834
1.313
2 .. 826
3.442
3,963
4.494
15.41~
183
223
257
29=
895
1,0°0
1, 255
1' 423
31.174
38.661
44,9<13
51.445
16,477
20,044
23,0S7
26,132
1'>97
1 ,5;:::;:
2,138
2~ ~.-;)Q
3,190
4°1
17
1.013
1 '521
3~043
3.659
4, 180
4.711
15.951
191
229
262
295
900
1.083
1' 237
1 '394
34?217
42?320
49.173
56.156
17.377
21' 127
24.294
27.526
!00$
1 ~'53:'
2, 148
:2,6c.o
3~ 20('1
519
18
1.210
1.747
3,27CJ
3. 8'?-:·
4,41t
4,0 47
16,490
199
236
268
300
907
1 '077
1 t 221
1o368
37, 4ot.
46.215
53,599
61.103
18.284
22~204
25t515
28.894
6-A
!OQO
1.597
2~ ::37
2.777
3,3::8
550
19
1 '427
1 ' QQ~,
3~5°3
4-23?
4.773
~., :3::4
17.030
211
249
280
313
928
1.094
1 '233
I, 376
41.08"'
50.448
58,3~-2
~.6. 427
19 .. .212
23.298
26.748
30,270
2000
1.607
2.247
2.7B7
3.338
583
!9
1.665
2.,267
3.874
4.514
5,054
5.605
17.569
221
257
298
319
936
1.090
1' 221
1. 354
44,963
54.962
63.416
72,032
20,148
24.388
27,96<>
31.624
b-A
1<><>o 1"'01 IOQ_: 1QQ3 1004 100~, 1<>96 1QQ7 1"'98 1">00 2000
F. ACCliM PRES WOI'TH DF ENEF•~'
MlLLS/I'WH
~v 1 '.263 ,, 333 1.400 1.464 1.s:e I. 58t· 1· 644 -701 1~7~6 1. 811 1. 864
S% 1-470 1-561 l.t--47 lo:?2& 1.806 1.880 1 ~ <>'51 .01"' Z~084 :;:, 14$ 2.210
"1f: 1. (:.48 I· 758 1. 860 1. <>st. ~?04"':" :.!3:3 :0?214 .~o: 2.366 2.438 2?508
O .. f l.S~7 1,055 :.074 2 .. 18~ 2.290 :.387 2.47° .566 ::1'64() :;:. 73l) 2?807
PC~[~ CC·:r ~;~LID¥ 1\LTL:..:.!SA':"E ,,_:::,
l'T'.UNCllA'! -CR.i'S! -l{!G:l LOll.~
1<'>JCI f<;..::_ 1 "~' !08::? 198? 1"8~ 199'5 1981: 1987 1"8"' ~Q9?
!. LOAD DEMAND
DEMi""l!' -K~ 1 • 4 00 . ' e.('l(' ! 1 -:'"4~ l.l")o::-;o.:?q '2.4?":> :'.7?0 ~.77t;.. 1..:::!2~ :::<. 46t' 3y71:?
ENERGV -M\.IH ~·~ Q~·c -, . .::· ~i: , c•C, c;. ~ .... " ;::; ;-11' 3~<:; l 14.! 10 l -=·~ 4:'1::-. l6.86:C l8t237 j0,6J:
2. SOLIRCES -1<1.
A, EXISTING DIESEL
LOCATION OR UNIT I 21'600 2,600 2.600 2,M.>(; ::.600 2.600 2.600 2, 60!) 2,600 2.600 2-600
2
3
4
5
6
7
8
9
10
II
12
B. ADDITIONAL DIESEL
UNIT 1
2 -j, 000 1.000 t. 000 1.ooo t.ooo I• 000 1.000 1.000 t.ooo 1.000
3 - ----·--t.ooo 1. 000
4
w -· 6
c. EXISTING HYDRO
UNJT 1
2
D. ADDITIONAL HYDRO
UNIT I ------2.700 2.700 2.700 2.700 2.700
2
3
TOTAL CAPACITY Kl>l 2.600 3,600 3.600 3.600 3.600 3.600 6.300 6.300 6.300 7.300 7.300
LARGEST UNIT 1.ooo t.ooo 1.ooo 1.000 1.000 1.000 2.700 2.700 2.700 2.700 2.70('
FIRM CAPACITY !.600 2.600 2.600 2.600 2.600 2.600 3.600 3.600 3.600 4.600 4.600
SURPLUS OR !DEFICIT> -Kl>l 200 l· 100 954 608 362 111 970 824 378 1.132 888
NET HY~~~ CAPACITY -MI>IH ------1!.700 11.700 11.700 11.700 tf; 700
DIESEL GEN~RATION -MI>IH ~.959 7.231 8.607 9.<>83 11.359 12· 735 2.410 3. 78~· :s. 162 6. s:n 7.'>12
b-ll
19'il'O 1991 1992 1993 1994 1995 1996 1997 199€' 1<>99 2000
1 • LOAD OEMND
DEMND -KW s. 96() 4.430 4.900 ~ .. ::.'170 '!1.840 6.310 6.780 7.Z50 7.720 8.190 8.6b0
ENERGY -I'IWH 20.988 23.89b 26.804 29.711 32~bt9 35.'!127 38.483 41,343 44. 2'!11 47. 159 '!IO.Ob7
2. SOURCES -I<W
A. EXISTING DIESEL
LOCATION OR UNIT 1 2.bOO 2.600 2.600 2.600 2.bOO 2.600 2.b00 2.600 2.600 2.600 2~600
2
3
4
'!I
6
7
8
9
10
11
12
B. ADDITIONAL DIESEL
UNIT I
2 t.ooo 1.ooo 1.ooo 1.ooo 1. 000 1.ooo 1.000 1.ooo 1.ooo 1.ooo 1.ooo
3 t.ooo 1.ooo 1.ooo 1.ooo 1.ooo 1.ooo 1.ooo 1.ooo 1.ooo 1.ooo 1' 000
4 --2.600 2,.600 2.600 2.600 2.600 2.600 2.600 2.600 2.600
5 -------2,600 2.boo 2.600 2 .. ~.00
6
C. EXISTING HYDRO
UNIT 1
2
D. ADDITIONAL HYDRO
UNIT 1 2.700 2.700 2.700 2.700 2.700 2.700 2.700 2.700 2.700 2.700 2.700
2
3
TOTAL CAPACITY -KW 7.300 7.300 9,900 9.900 9.900 9.900 9.900 12.'!100 12.500 12.500 12.500
LARGEST UNIT 2.700 2.700 2.700 2,700 2.700 2.700 2.700 2.700 2.700 2.700 2.700
FIRtl CAPACITY 4.600 4.600 7.200 7.200 7.200 7.200 7.200 9.800 9.800 9,800 9,800
SURPLUS OR <OEFICin -KW 640 170 2.300 1.830 1.360 890 420 2.:550 2.080 I, 610 1.140
NET HYDRO CAPACITY -MWH ''·• 700 1J.700 11.700 11.700 11.700 11.700 11.700 11.700 11.700 11.700 11.700
DIESEL OENERATIUN -MWH 9.288 12. 196 15.104 11:1.011 20.919 23 .. 627 26.793 29.643 32.5'!11 35.4'!19 38.367
6-!l
} 07C> 1980 J<l8J 1Q8::' 1983 1984 1 fV8~· 1"'81. !987 !988 1980
3. INVESTMENT COST~. ($1000)
1979 DOLLARS
A. EXISTINC· DIESEL l. '5~·0 1. '55(\ 1.~-::.o 1 ''5'50 1 • '5*50 1. 5'50 1 ~ 5~·('1 1.5'50 1 .sso 1.':·50 1.sso
B. ADDITIONAL DIESEL
UNIT 1
:;-870 870 870 870 870 870 870 870 870 870
3 ---870 870
4
:;,
6
c. EXISTING HYDRO
D. ADDITIONAL HYDRO
UNIT I 19~ 3~<2 J0,3t.2 19.362 1'9,362 19,36~
~
3
E. TRANSMI:3SION PLANT ADDITIONS
UNIT I
-,
F. MISCELLANEOUS ADDITIONS
UNIT 1
2
TOTAL ($1000)
1979 DOLLARS 1. '550 2 .. 420 2,420 2.420 2.420 2.420 :21.,782 21.,782 21,782 22,t;.S2 22.,652
INFLATED VALUES 1 '550 2.,490 2.490 2.490 2.490 2.490 32.077 32.077 32,077 33.,572 33,572
4. FIXED COST ($1000)
INFLATED VALUES
A. DEBT SERVICE
1. EXISTING t.t. t-~· 66 66 6t.. 66 6~· 6t. 66 66 66
2. ADD IT IONS
SUBTOTAL 2% 38 38 38 3S 38 1.221 1.221 1 '221 1.281 1,281
51.. 57 57 57 57 57 I, 837 1.837 1,837 1.928 1,928
7'/, 73 73 73 73 7-' .;:. 2,3~~8 2.358 2.3'58 2.473 2~47?.
9'1. 89 89 89 89 89 2.889 2.889 2.889 3.030 3.030
B. INSURANCE '5 e 9 9 10 11 147 153 1'59 173 180
TOTAL FIXED COST <SIOOO>
2"1.
~"I.
7"1.
9'%.
~. PRODUCTION COST (SIOOO>
lNFLATEl• VALUES
A. OPERATION AND HAINT
1. DIESEL
2. HYDRO
B. FUEL AND LUBE OIL
TOTAL PRODUCTION COST <S!OOOI
TOTAL ANNUAL CO<O.T ( SIOOO l
2"1.
5"1.
7"1.
q·;.
ENERGY REOUIREHENE. -HWH
MILLS/KWH
2"1.
5%
7%
9%
C. PRESENT WORTH
ANNUAL COST ( U 000 >
:n
S%
7%
9%
D. ACCUMUL. ANN. COST (SIOOO>
2'%
5'%
7%
<rl.
E. ACCUMULATED PRESENT WORTH
ANNUAL COST <SIOOO>
2"1.
57.
7%
9%
} ":.J7C•
71
71
71
71
169
412
'581
c.s;:
6':·2
6~:"
6':·2
5.95~:
!09
109
109
109
652
652
652
652
652
652
652'
e.s2
652
~ C'" --~ C•J..._
e. '52
!·52
!980
112
131
147
163
:::38
55:?
790
90:?
921
0 37
os:::-:
7.231
125
127
130
132
843
861
S76
891
1.~54
1.573
J-,589
1 .60':•
1.495
1 .. 51:3
1 .'528
t. ~·43
J08J
113
1 ~-. .,_
148
164
268
721
989
1' 102
1. 121
1,137
],!53
8.607
128
130
132
134
963
979
993
1.007
2, ~.se.
2.694
2.726
2.758
2.45::::
2.492
2.521
2,5-:.o
J<::i8:?
113
I ~~ "~
148
164
30:'
~21
1.223
t .. 33t-
1.3S'5
J,371
1.387
0,983
134
t3e.
137
139
I ,091
J, 106
!. 119
J, 132
3,992
4.049
4.097
4.145
3.549
3.'598
3.640
3.682
J983
114
133
149
16'5
338
I, !'53
1.491
1 '60'5
I .624
I .640
I ,6':•6
11.3'58
141
143
144
146
1.224
1.239
1.2'51
t.2t·3
~·.'597
"'··673
'5.737
5.801
4.773
4.837
4.891
4.94'5
1984
II':·
134
15()
16!·
37°
1.421
1 .soo
1.915
1, 934
I .9':·0
1.966
12.735
ISO
1'52
153
154
I .365
1.379
1.390
J,402
7.512
7.607
7.687
7, u.7
b. 13E:
6.216
6.281
6.347
19E!5
I ,434
2.050
2.571
:<. 102
287
II
285
583
.017
.633
, 154
• 685
14.110
143
187
224
261
1.344
1.7'54
2.102
2,4S~·
9.529
10.240
10.841
11.4'52
7.482
7.970
8.383
8.802
!986
.440
.ost.
.577
I 108
314
II
474
799
::.239
2.8SS
3.376
3,907
15.48':·
14'5
184
218
252
I ,394
1.778
2,102
2.433
II .768
13.09'5
14.217
15.359
8.876
9.748
10.48'5
II ,23'5
I o-;n
I. 44t·
2.06:'
~.583
3.114
34:!
12
b86
I .040
2.486
3.102
3.~·23
4.154
16.86:2
147
184
215
246
1.447
1 .8os
2.109
2.418
14.2~4
16.197
17.840
19, '51;.
10.323
II ,553
12.594
13.653
J988
I .520
2. ll:·7
:".712
3.269
371
12
921
I ,304
2.824
3.471
4.ote .
4.573
18.237
15'5
190
220
2~1
I, 53!·
1.888
2.184
2.487
17.078
19.668
21, 8'5!.
24. 08!.
II ,859
13.441
14.778
16.140
&-8
198'9
1.527
2.174
2~719
3,276
404
13
J, 181
!.598
3~12'5
3~772.
4.317
4.874
!9,612
!59
192
220
249
J,S89
J,917
2. 19'5
2,478
20.203
23.440
2!..173
28.960
!3.448
15.358
Jt.,973
18.618
6-!1
1Q"7Cj 1 o-7;r 1Gf'1 tv;:-::_
1 "'
lQS.e 1QS-:r 1 08~ 1 o:o;7 1Q88 !98<>
F, ACC'UM PRE,-. IJORTH OF ENEF>r.•
MILLS/KIJH
2'% 10"> ::-~-:?38 447 ~s~ ~·~-:: 757 847 G~3? 1 '0!7 l ,Q98
S'"l. l ~"' 34_ 4'33 5t.: ~7n 79~· Oj(l l ,(>17 1' 120 1' 218
7'%. l(tq 3(l ~4~· 457 '5·67 b7o· 8:'~· Ot,! 1 .08& !.206 1.318
Q~t~ 1(l<:": ·'-'.<40 4t:· 573 68:' 857 I • 014 1. 157 1 .,Z94 1. 421
f>-B
]9'>(> 1"'""1 1<:!0_2 lo<?::: 1094 !90':', )QQ6 1007 1<:)-:)8 19'00 2000
3. INVESTI'IENT COSTS IS1(l(l(ll
!979 DOLLAR'S
A, EKISTING r•IESEL 1, -s~o 1. 55(1 1.550 1.550 1,550 1 '55(> 1.550 1 '55(> I ,550 !.550 1.5~
B. ADDITIONAL DIESEL
UNIT 1 ----
2 870 870 870 870 870 870 870 870 870 870 870
3 870 970 870 870 970 870 870 870 S70 870 870
4 -2.:26:? 2.:?62 z,ze-2 2.262 2,262 Z¥262 2.262 2,262 2,.262
5 ---~.262 2 .. 262 2-26:2 2.262
6
c. EXJ STI NO HYDRO
D. ADDITIONAL HYDRO
UNIT l 19.362 to,:=:e-2 ]9, 3~.:::: l Q. 3~-:::: 19, 3e.2 19.362 J9,'362 19, 3~.:::: 19. 3~.2 1°.36:? 1".3~2
2
3
E. TRANSMISSION PLANT ADDITIONS
UNIT 1
2
F. MISCELLANEOUS ADDITIONS
liNIT 1
2
TOTAL ($1000)
1 979 DOLLARS 22,652 22.652 24.914 24,914 24,914 24.914 24.914 27, 176 27.17l· 27,176 27.176
INFLATED VALUES 33.572 33.572 38. 121 38.121 38.121 38,121 38. 121 43.655 43.655 43.655 43.655
4. FIXED COST ($1000)
INFLATED VALUES
A. DEBT SERVICE
1. EKISTING 6(:. 66 (:.~. 66 66 66 66 6<1:· 66 66 66
2. ADDITIONS
SUBTOTAL 2'1: 1' 281 1. 281 1 '46~: t. 4e.3 l' 463 1.463 1, 4e.3 1.684 l.i:-84 1.684 1.684
!5X 1.928 1 ~929 2,206 2w20e. 2.20¢. 2,20~· 2t 2(16 2.544 2.544 2t544 2.544
7'1: 2.473 2,473 2 .. 824 2,824 2.824 2.824 2,824 3,251 3,251 3.251 31251
9'1: 3.030 3.030 3. 4t.(l ?..460 3,4C.O 3.460 3.460 3.984 3.984 3.984 3.984
B. INSURANCE 187 195 230 239 249 2'59 269 3:20 32:,:}: 347 360
TOTAL FJXE[l CO~.T CSIOOOl
21.
5%
7%
9"1.
5. PROOUCT!ON COST CSIOOn)
JNFLATE[l VALUES
A. OPERATION AN[l MAINT
I. OIESEL
2. HY[IRO
B. FUEL AN[l LUBE OIL
TOTAL PROOUCTJON COST CS1000l
TOTAL ANNUAL COST < S !C>C>O l
2%
5%
7%
9%
ENERGY REQUIREMENTS -MWH
MILLS/KWH
2/.
5%
7%
9%
C. PRESENT WORTH
ANNUAL COST (S1000)
2%
5%
71.
9%
[1. ACCUMLIL. ANN. COST CS1000l
2%
5/.
71.
9i'.
E. ACCUMULATE[l PRESENT WORTH
ANNUAL COST CSIOOOl
27..
5"/.
71.
9"/.
109()
1, 534
2.181
2. 72b
3 ~ 28:..:
437
13
1.470
1.920
C:.4"i4
4.101
4.1>46
5.203
20.988
1t-5
195
221
248
I ,641
1.948
2.207
2.472
23.657
27.'541
30.819
34.163
15.089
J7, 30t.
19.180
21.090
1Q0 1
1 .":•4:2
::.180
::.734
3.2°1
570
14
2.046
2.630
4, 17?.
4.819
5' 31.4
5.9:.21
:23. 89t.
175
202
224
248
1.852
2, 140
2.382
2.629
27.829
32.360
36.183
40,084
16.941
19.446
21 .'562
23.719
1992
1.750
2. 5(l:.'
3. 12'(l
~:. 7~•t·
t31
14
2.688
3.333
'5.002
~·.835
6.4'53
7.08?
26.804
190
218
241
264
'113
.421
.678
,942
32.921
38.195
42.636
47.173
19.054
21 .. 867
24.240
26.661
1QQ3
1.768
2.511
3. 1:?0
3-765
698
15
3.397
4.110
":•.878
t•o621
7.:?3?
7.87':·
29.711
198
223
244
265
2.280
2.568
2.807
3.054
38.799
44.816
49.875
55.048
21.334
24.435
27.047
29.715
1'>94
I .778
2.521
3. 13-;.
3.775
770
1':·
4.181
4,9t.t.
6.744
7.487
8.10'5
8.741
32.61Q
207
230
248
268
2.444
2.714
2.938
3.168
45.543
52 .. 303
57,980
63.789
23.778
27.149
2Q.,98':r
32.883
100::,~,
I, 788
2.531
3.149
2.78'5
843
H·
5.048
5.907
7. t..<>s
8.438
9.0":·~·
9.692
3':·.527
217
238
255
273
2.607
2.858
3.068
3.283
53.238
60.741
67.03~.
73.481
26,385
30,007
33.053
36.166
1<>06
1' 79S
2.541
3. 159
3.795
924
16
6.014
6.954
8.752
9.49'5
10.! 13
10.74"
38.483
227
247
263
279
2.771
3.006
3.202
3.403
61.990
70.236
77. 149
84.230
29.156
33.013
36.255
39.569
1007
2.070
2.930
3.637
4.370
1.010
17
7.058
8.085
10. 15'5
11.015
11.722
12~455
41.343
246
266
284
301
3.004
3.259
3.468
3.685
72.145
81.251
88.871
96.685
32,160
36.272
39,723
43.2'54
1098
2.083
:'.943
3.6'50
4.383
1.099
18
8.215
9.332
I .415
1 .275
1 .982
13.715
44.251
258
277
293
310
3.156
3.394
3.590
3.792
83.560
93.'526
101.853
110.400
35,316
39,666
43,313
47, 04l-
lQQQ
2~0Q7
2,0 57
3.UA
4,307
1,196
19
9.485
10.700
12,797
13.657
14.364
15.007
47.159
271
290
305
320
3.307
3.529
3.712
3.901
96.357
107,183
116.217
125.497
38.623
43. 19'5
47,025
50.947
b-8
2000
2.110
::.97(1
3.677
4.410
1.298
1Q
10.877
12.194
14.304
15. 164
1'5.871
16.604
50.067
286
303
317
332
3.45'5
3.662
3.833
4.010
110.661
122.347
132,088
142. 101
42,078
46.857
50.858
54.9'57
b-B
1~0() t<><>t 19<>:: t0V3 !<><>4 1 <><>'5 1<><>6 1<><>7 1°<>8 1 <><><> 2000
F. ACCll!'l PRES WORTH OF ENERC·Y
l'llLLS/I<WH
:;"~ 1. 1 7{ 1' 2~·4 1 '333 1.410 1.4~· 1.ss<> 1.631 1.704 1.775 1. 845 1.<>14
~·% 1. 311 I• 401 1. 491 1.577 1.660 I• 741 1.81<> 1. 898 1.9~ :;::.oso 2.123
n .. 1, 423 1,5£2 ! • .;.:;:;; 1. 717 I , 807 1.893 1.976 2,0,l.(t z, 141 2~220 2.297
<>% 1, 53<> 1.64" 1 • 75<> I, 86:: l • <>S<> 2 .. 0~1 ~. 13~· 2.228 2. 314 2.3<>7 2: .. 477
POWER COST STUDY
ALTERNATE 7-A
DILLINGHAM -EJ.VA & GRANT -LOW LOAD
1979 1980 !'?81 1':182 1983 1984 1985 1980. 1987 1988 1989
1. LOAD DEMAND
DEMAND -KW 1.400 1,500 1.608 1, 716 1, 824 1 ~ 932 2,040 2, 148 2.256 2c.365 2.472
ENERGY -MWH 5,958 6·523 7.088 7.654 8.219 8.784 9.350 9.915 10.480 11,046 11.0.12
2. SOURCES -KW
A. EXISTING DIESEL
LOCATION OR UNIT 1 2.600 2.0.00 2,600 2.600 2.600 2,600 2.0.00 2.600 2,600 2,600 2.600
2
3
4
5
b
7
e
9
10
11
12
B. ADDITIONAL DIESEL
UNIT 1
2 -1.000 1 .ooo 1.ooo 1.ooo 1 .ooo 1 .ooo 1, 000 1.000 1 .ooo 1.000
3
4
s
6
c. EX I STING HYDRO
UNIT 1
2
D. ADDITIONAL HYDRO
UNIT I ---I .500 1, 500 1.500 1, 500 1.500 1' 500 1, 500
2 ---- -2,700 2.700 2.700 2.700 2,700
3
TOTAL CAPACITY -KW 2.600 3.600 3.60<) 3.600 5.100 s.1oo 7.800 7.800 7.800 7.800 7.800
LARGEST UNIT 1.ooo 1. 000 1.000 1 .ooo 1.soo 1.soo 2.700 2.700 2.700 2,700 2.700
FIRM CAPACITY 1.600 2.600 :z,o.oo :2, ~.oo 3.600 3.600 5.100 5.100 5.100 5.100 5.100
SURPLUS OR ( OEF l CIT I -KW 200 1. 100 9·n 884 1.77b 1.668 3.060 2,9S2 2.844 2.735 2.626
NET HYDRO CAPACITY -MWH --8.070 '3.070 1'>,770 19,770 !9.770 \9,770 !9,770
DIESEL GENERATION MWH 5. <>5:3 o.5::::J 7.088 7 • .<,54 14"' 714
7-A
19'1>0 1991 1992 1993 19">4 1995 1996 1997 1998 1999 2000
1 • LOAD DEt1AND
OEI'IIIIND -KW 2.580 2.687 2.794 2.901 3.008 3. 115 3.220 3,327 '3.434 3.!541 3.650
ENEROY -t1WH 12.177 12.716 13. 2'53 13.794 14.334 14,8T3 15,412 15,951 16.490 17.0:30 17.369
:. SOURCES -KW
A. EKISTtNG DIESEL
LOCATION OR UNIT 1 2.600 2.600 2,600 2.600 2.600 2.600 2,600 2.600 2,600 2.600 2.600
2
3
4
3
6
7
8
9
10
11
12
8. ADDITIONAL DIESEL
UNIT 1
2 1.ooo t.ooo 1.ooo t.ooo t.ooo 1 .ooo 1.ooo 1.ooo 1.000 1.ooo 1.ooo
3
4
~
6
c. EXISTfNQ HYDRO
LINIT 1
2
D. ADDITIONAL HYDRO
UNIT 1 1.500 1.500 1.500 1· 300 1.500 1.500 1.500 1.500 1.5oo 1.500 I, 'SOO
2 2.700 2.700 2.700 2.700 2.700 2,70('1 2.700 2.700 2;,700 2,700 :2 .. 700
3
TOTAL CAPACITY -KW 7.800 7.800 7.300 7.800 7.800 7.800 7.800 7,800 7.800 7,800 7,8!)0
LARGEST l!NIT 2.700 2.700 2,700 2~700 2,71)0 2,71)0 2,700 2.700 2,7(.)t) 2,700 2~70i)
FIRM CAPACITY s. 100 '5·100 5.100 5.100 5.100 5. 1~10 5.100 5.100 5.100 5.100 5.100
SURPLUS OR <DEFICIT) -I<'W 2.520 2,413 2,306 2, l'?'i> ~t ~""192 1 t "?85 1. 88<) 1.773 1·'!:.66 1.559 1' 4~0
NET HYDRO CAPACTTY -MWH 19.770 19.770 19,770 10,770 19.770 1<?,770 19,770 lq,770 !<?,770 19,770 1",770
DIESEL GENERATION -MWH
i-A
107<:' 1<>80 1981 1 op:· 198:0 1984 1 OB.~· !986 t0f'7 1Q8;:: 1080
3. INVESTMENT COSTS < S 1 (>00 l
!<>79 f\OLLARS
A. EXlST!NO DIES.ECL 1, :'SC• 1, 5'50 1.~·~·0 t.~:.o 1 '~5-(1 1. '55(! 1 '~.~,(} l ''5'5(• I, 5'5(> 1.550 I, ~'50
B. ADDITIONAL DIESEL
UNIT 1 870 f:7(l 87() :::7(1 ~:7() 870 B70 870 870 870 -3
4
5
6
c. EXIST I NG HYDRO
D. ADDITIONAL HYDRO
UNIT I t:: .. 940 12,94(1 12,Q4(l 12.940 12,Q4(l 12.940 12,940
--19, 3c·2 19,362 1<1.362 19,362 19.362
E. TRANSMISSION PLANT ADP!T!ON'3
UNIT 1
2
F. MISCELLANEOUS ADD IT IONS
UNIT 1
2
TOTAL ($1000)
1979 DOLLARS 1 , 5'50 2~420 2 .. 420 2.420 15.360 15.360 34~722 34ct722 34,722 34,722 34' 72'2.
INFLATED VALUES 1.550 2 .. 49(> 2.490 2,490 20,095 20.095 4~ .. 682 49t682 49.682 49.682 49.682
4, FIXED COST ('1>1000)
I NFLATEIJ VALUES
A. DEBT SERVICE
1. EXISTING 66· 66 66. 6c· 66 66 c·6 6c· 6c· t.t. 66
2 .. ADDITIONS
SUBTOTAL 2'1. 38 3E: 38 742 742 1.925 1,925 1. 925 1 .. 925 1 .. 92!5
5% 57 57 '57 1.116 1.116 2 .. 896 2.89<'· 2 .. 89~· 2~896 2.8<>6
74 7:• 73 73 1 .43:': 1.43~: 3.718 3,718 3, 71E> 3,718 3. 718
94 89 89 89 1,755 1, 755 4,555 4. 5~·5 4, 55~· 4~555 4.555
B. I w::LIRANCE 5 8 "' "' 82 e<> 228 237 24~. 2SC, 2~·6
7-A
1 <r;-<> I"'BO 1"-'81 19$~ 1083 1<>84 JQ8~ 1986 1"87 1988 198<>
TOTAL FIXED COST ($1000)
~·· 71 11:::: 113 113 890 897 2 .. 21Q' 2·228 ;:,237 2.247 2.257
~7.. 71 13! 1'32 132 I .264 1 '271 3,190 3.!9<> 3.20S 3 .. 218 3,228
77. 71 147 !48 148 1.581 1.~88 4.012 4-021 4.030 4.040 4.0~0
Q'%, 71 16~: 1~-4 164 I, 903 1. 91(> 4.849 4.858 4.867 4.877 4.887
~ .>. PROOLICT ION COST f$1000)
INFLATED VALUES
A. OPERATION AND MAINT
l. DIESEL 16" 233 256 28:' 23~ 260 263 273 284 2Q5 307
2. HYDRO --7 7 9 10 10 12 13
B. FUEL AND LLIBE 0 I L 412 497 595 706 14 eo
TOTAL PROOLICTION COST ($1000) 581 730 851 988 2'5~. 347 272 283 294 307 320
TOTAL ANNUAL COST ($!0<)0)
:Z'% 6'52 842 964 I, 101 ,, 14t 1' 244 2.491 2 .. 511 2 .. 531 2.'554 2,'577
'5% .052 861 983 I, 120 1 .. ~·20 1. 618 3 .. 462 3~482 3,~02 3 .. 52~· 3.~~48
77. 652 877 99" 1' 13~· 1.837 1,935 4 .. 284 4.304 4 .. 324 4.347 4.::no
"% 652 893 1.015 1 .. 152 2,150 2 .. ::-~,7 5 .. 121 5. 141 5. 161 5, 1E:4 5.207
ENERGY REQUIREMENTS MWH S,Q58 6' 5:?:::~ 7, 08E: 7' 6~·4 8.219 8.784 9t350 9.915 10.480 11,046 11 ,.ot2
MILLS/KWH
27. 109 129 136 144 139 142 266 253 242 231 222
57. 109 132 139 14~. 18'5 184 370 3'51 334 319 306
7'l. 109 134 141 148 224 220 4'58 434 413 394 376
9'l. 109 137 143 1'51 263 257 548 519 492 469 448
c. PRESENT WORTH
ANNUAL COST 1$1000)
27. 652 787 842 899 874 887 I, 6./:.0 1.564 1' 473 1.389 I, 310
57. 6'52 8(>'5 8'59 914 1' 160 1.1'54 2.307 2.168 2.038 1 .917 1 '804
71. 652 9:20 E!73 927 1 ' 401 1' 380 2.85'5 2.~·80 2,517 2,364 2, 221
9'):. 6C'",.¥ -'k 83'5 E:87 940 1·647 1' 60"' 3~412 3,202 3,004 2.820 2,647
D. ACCUMUL. ANN. COST ($1000)
2/. i!:-52 I ,494 21-458 3.559 4,7(JS ~.,q,4() 8,44(1 10,9~1 13,482 16.036 18.613
57. 6'52 1.513 2.49<!. 3.616 '5. 136 6.754 l(J, 21f.. 13.698 17.200 20,725 24.273
71. 652 1' 5~~ 2,52:?: 3 • .1; • .1;.4 5.5(J1 7, 43<!, 11 '72(l 16,024 20.348 24.695 29,065
9'% 652 1, 545 2. '5.1;.(> "''· 712 '5.871 8,128 13.249 18.390 23,551 2€:. 735 33.942
E. ACCLIMULATEO PRESENT WORTH
ANNUAL COST {$1000)
2'% 6'52 I ,439 2,281 3.180 4' 0'54 4.941 .1;., .1;,(>1 8,16'5 9.638 11 .027 12.337
5% e.s2 1. 4'57 z,.3t6 3t230 4. 39(> 5.'544 7,8'51 10.019 12.057 13.974 15.773
7% 652 1,472 2t345 8,272 4.673 6.0'53 8.908 11.588 14.!0'5 16.4~,9 18.690
97. 6:;'·2 1.487 2.374 3.314 4.961 6. 57(1 9,982 13.184 16.188 19,008 21,655
7-A
i q~.:_. 1'>81 !"" 1Q87 l'>S4 10:?:':• ! Q(:( 198"."' 1'>8<:' 1<>89
F. ACCUM PRES WOPTH OF ENERG'<
MILLS/KWH
;''X ]()<::-· ::::'30 ::t4<t 4~7 :'"·73 (:.74 9Sl I , OO"' 1, 1 =·0 l ''276 1.389
51. ! 0'" ,....,"',... :::'5 47:;:· f.. I 744 90! 1 ';:'1(1 I , 404 I .57S l. 734
71. ~ () .;-, :-:,4 35 47,t: <·4"' 8t)b 1 ,J ll 1' 3>?:1 l ,621 1.85~· 2y()2b
9(. zn<J ':.:?7 ::t. 485 68.'· se-c: 1' ::-::4 ! '5~7 I .848 2~ (IQ.O:: :. 82<
7-A
t<X>O 1-1 1 o<..:; JQ93 1<><>4 lQ<;I~, tQ<><> JQ07 tO<:'JS ]QQ¢ 20Q(I
3. IN\I£STP1£NT COSTS <'*1000>
1'979 DOLLARS
A. £)(!STING DIESEL I, :5'50 I, '550 1.550 I .550 I. '550 1.550 1.550 1.550 I ,550 1 ·~·50 !.5:50
e. ADDITIONAL DIESEL
UNIT I B70 870 $70 870 ~'70 87(') 870 870 87(1 870 870
~ 870 870 870 870 870 870 870 870 870 1:!70 870
3
4
5
~
c. EXISTING HYDRO
D. ADDITIONAL HYDRO
UNIT 1 12.940 12,940 12,940 12. 94(1 12,04(! 12~940 12.940 12.Q4(! 12,Q4(l 1:2.94(> 12,04(1
2 19, 3~·2 10,362 19,3b: 19.31:.:::-1q~3:62 19.'3b2 1<>. 36:::· 19. 3t·2 19,362 1 Q, 3l·2" 1 <), 3~·2
3
E. TRANSMISSION PLANT ADDITIONS
UNIT 1
2
F. MISCELLANEOUS ADDITIONS
UNIT 1
2
TOTAL <S1000l
1979 DOLLARS 35.592 35.592 35.592 35.592 35 .. S92 35.592 35 .. 592 35,592 35,592 35,~92 35.":592
INFLATED VALUES 51' 299 51.299 51 .. 299 51.299 51.299 51 .. 299 51 ,2'99 51.299 51,:29'9 51 .. 299 51' 299
4. FIXED COST lS1000>
INFLATED VALUES
A. DEBT SERVICE
t. EXISTINC• 66 ~ 66 66 66 66 66 66 bt. 6~ 66
2. ADDITIONS
SUBTOTAL 2X 1.990 1.990 1.990 1.990 1. 99(> 1.990 1 '99(> I, 990 1.<>90 1.990 1.990
57. 2 .. 995 2.995 2.99'5 2,995 2,995 2 .. 995 2 .. 9915 2.995 2,99!"'1 2.99~ 2.9<;>:;,
77. 3.843 3.843 8.843 3.84:< 3,843 3t843 3 .. 843 3,$43 3,843 3.843 3.843
97. 4. 7(>8 4.708 4.70fl 4.708 4.708 4,708 4,7(>8 4.708 4.708 4,7(1€: 4.708
B. INSURANCE 2S6 298 309 322 335 :0:48 362 377 392 407 424
TOTAL FIXED COST <t>1000)
Zl.
5:%
7%
9/.
:'•. PRODliCTlON COST ( $1000 >
INFLATED VALUES
A. OPERATION AND MAINT
1. DIESEL
2. HYDRO
B. FUEL AND LUBE OIL
TOTAL PRODUCTION COST ( $1000 l
TOTAL ANNliAL COST < $! 000
21.
51.
71.
91.
ENERGY REQli!REMENH: -MWH
MILLS/KWH
21.
5%
77.
97.
C. PRESENT WORTH
ANNUAL COST ($1000
21.
57.
7%
9%
D. ACCUMUL. ANN. COST <t>IOOOl
2%
57.
77.
9%
E. ACCUMULATED PRESENT WORTH
ANNUAL COST ($1000>
2'7.
~,Yo,
71.
91.
1 O<;.(,
2~342
3.347
4, 19~.
~ •• Ot.(J
319
1 ~:
332
2. t.74
3,67°
4~527
5.392
12. 177
220
302
372
443
1 , 270
I, 748
2~151
2 .. 502
21.287
27,952
33.592
39.334
13.607
17. 52e·
2(>.841
24,217
10~1
::. 3~·4
3.3~·Q
4.2(17
s.o7.:::
332
1'5
347
;.;,7(>1
3.706
4,5S4
5.419
12,716
212
291
358
426
1 ,)99
1, 64e.
2,022
2 .. 40b
23,988
31.,658
38. 146
44. 75~:
14.806
19. 172
22,1363
26,62'3
1<00~
;::.365
3.~?0
4.218
5~0t3
34S
lt·
361
:;'.72b
3.731
4.57<>
5.444
13.2S5
206
281
345
411
I, 131
1.548
1.900
z,25'9
26.714
35.389
42.725
50.197
15.937
20.720
24,763
28.882
1 Q<;)~,
2.378
3~382
4.231
5.0"'6
3~t'9'
17
376
~,754
3,759
4.t.07
5~472
13.794
200
273
334
397
1.068
1.458
1 '787
2.122
29,468
39.148
47.332
55.669
17.005
22,178
26.550
31.004
1"'"'4
:;::.~91
3130t.
4.:?44
5. l (10
374
20
394
2. 78'5
3.790
4' 63~:
5.503
14,334
194
264
324
384
1.009
1. 374
1· 681
1.995
32.253
42.938
S1.970
61 "72
18.014
23 .. 552
28.231
32.999
1~05
2.404
3.400
4. :'57
sl 122
389
20
409
2.813
3.818
4.66<:·
5.531
14.873
189
~7
314
372
953
1.,293
1 ''581
1,874
35.066
46.756
S6.636
66.703
18.967
24.845
29,812
34.873
190t,
:;:'.418
3.4:-3
4.271
5. 13<·
404
21
425
2.843
::;,848
4.69Jc.
5.561
1S,412
184
250
305
361
90(>
1 '218
1.487
1. 760
37.90"'
50.604
61.332
72.264
19.867
26.063
31,299
36.633
1<>0 7
2.433
3.438
4.286
s. 1S1
420
24
444
2t877
3.882
4,730
5l595
15,9~1
180
243
297
351
851
1.149
1,399
1 ,6S~
40.786
54.486
66.062
77.859
20.718
27,212
32.698
38.288
1"98
2.448
3.4'53
4. 301
5.166
437
25
462
2,910
3 .. 915
4. 7t.3
5,628
16.4"'0
176
237
289
341
80S
1, 083
1, 317
t.sst.
43.696
58.401
10.825
83.487
21. ~23
28,295
34,015
39.844
7-A
199<>
2.463
3-468
4.316 s. 181
455
26
481
z.,944
3.949
4.7<>7
5 .. 662'
17.030
173
232
282
332
761
1.020
1' 240
1.463
4!,. 640
62.350
7'.5. 622
89,149
22.284
29.315
3S.2SS
41,307
2000
2·480
3 .. 485
4.333
51 19S
473
30
508
2,983
3,Q8B
4.83b
s.701
17.569
170
227
275
324
720
963
1' 168
1 '377
49.623
66.338
80.4S8
94.850
23.004
30,278
36.423
42.684
-q-r~ ... cr, q-..() o-. 0 _,.....N,..... g N NMC""J N < ,!. 0 ()-..()(') 0' OJ o,-0 0 ~-" 0' 0 Ci NM (") lllO'Mr--VJ "'NNN 0-<J-~ 0 0' N NM(t"J ....o c··,(t"·f···
().. ..() q-('·,
" 0' u"l o o1
0
0 ... NC'"JC'"J
""' -I(J 0 q ()-.. ~) (~
~ 0' ., 0' .,
0 ... r~ N (t"J
1(,
~ N OJ.-, ;;~;;:; .,.
!) -NN C~
-I()NQ-.. NNU"'IOO c.J cr,,.....-
0'
0 -r~ r~ C')
-()-~~~, 0
.... , l'\l(t"Jtrl
(', r--N~O
0
0 ... C~N ('J
('J C'"J ,,., ..(;
r--C< 0 0'
(j .() _,,., (Jj
0
0 -C< C< C<
f/J .() r~ II",
([) 0 .() (<
W"'J ocr,,.... g -NC< Cl
q-r--. ('; .(J
0 r--.o rr.
0 q-f/J r~ w--, g --NN
> ~
~
UJ
u_
0
I
I-
~
3 ~;-.:.,..:~
Ntr1,..... Q>.
"' LIJ I
R: 3
¥
' ~ (fJ
..J u ..J w
<t 1:
u:
POWER COST STUDY ALTERNATE 7-B
DILLINGIIAM -ELVA & GRANT -liiGH LOAD
1070 !98,-, 1981 tQ8:2 1983 1984 !985 !986 1987 1°88 !Q!;'9
!. LOAD DEMAND
DEMAND -KW 1,400 1.500 !. 746 !.99::' 2,238 2 .. 48Q 2,7JO 2.776 -. "")""')-""} .=., ......... _ 3.468 3.712
ENERGY -MWH -s~95E' 7.231 8.(;,07 Q~'98:?/ II, 358 12,73~ 14.! 10 15-485 16.862 18.237 IQ,612
2. SOURCES -KW
A. EXISTING DIESEL
LOCATION OR UNIT 1 :2 .. 600 2.600 2.600 2.600 2.600 2,600 2.600 ~,ooo ;2.600 2.600 2.600
~.
3
4
c
~
6
7
8
Q
10
II
12
B. ADDITIONAL DIESEL
UNIT 1
2 -1.000 1.000 1 .ooo 1.000 1.000 I ,000 1.000 t.ooo 1.ooo 1' 000
3
4
5
6
c. EXISTINO HYDRO
UNIT I
2
D. ADDITIONAL HYDRO
UNIT 1 --1.500 1.500 1. !500 1.500 1. !500 1. 500 1.500
2 ---2.700 2 .. 700 2.700 2.700 2.700
3
TOTAL CAPACITY -KW 2t600 3.600 3.600 3.600 5.100 5.100 7.800 7.800 7.800 7.800 7.800
LAROEST UNIT 1.ooo 1.ooo 1.ooo 1.ooo 1.500 I, !500 2.700 2.700 2.700 2,700 2.700
FIRM CAPACITY 1.600 2.600 2.600 2.600 3.600 3.600 !5. 100 !5.100 !5. 100 !5. 100 5.!00
SURPLUS OR <DEFICIT) -KW 200 1.100 854 608 I .362 I , 111 2.370 2.324 !. 878 !.632 1.388
NET HYDRO CAPACITY -MWH --. --8.070 8.070 19.77" 19.770 19.770 19.770 19.770
DIESEL GENERATION -MWH 5,958 7.231 8,607 9,983 3.:?88 4.665
7-ll
1990 1991 199:::? 1993 1994 !99'5 199~ 1997 1998 1999 2000
1 • LOAD DEI'IAND
DEI1AND -KW 3.960 4.430 4,900 '5.370 '5.840 6.310 6.790 7.250 7.720 9,190 8.660
ENERGY -11WH 20.988 23.896 26.S04 29,711 32.619 3'5.'527 39.483 41.343 44.2'51 47.1'59 '50.067
2. SOURCES -KW
A. EXISTING DIESEL
LOCATION OR UNIT 1 2.600 2.t:.oo 2.~00 2.600 2.600 2.600 2.600 2.600 2"b00 2.600 2.600
2
3
4
5
6
7
e
C)
10
11
12
B. ADDITIONAL DIESEL
UNIT 1
2 1.ooo t.ooo t.ooo t.ooo t.ooo 1.ooo 1 .ooo 1.ooo 1.ooo 1 .ooo 1.000
3 --2,600 z~ooo 2.600 2.600 2.600 2.600 2.600 2.600 2.~00
4 -- ---2.600 2.600 2.600 2.600
'5
6
C. EXISTING HYDRO
UNIT 1
2
D. ADDITIONAL HYDRO
UNIT 1 1.500 t.soo 1.soo 1 ''500 1.500 1, '500 1.500 1.500 1.500 1.500 1.500
2 2.700 2.700 2.700 2.700 2.700 2 .. 700 2.700 2.700 2.700 2.700 2.700
3
TOTAL CAPACITY -KW 7,800 7.900 10.400 10.400 10.400 10.400 10.400 13.000 13.000 13.000 13.000
LARGEST UNIT 2.700 2.700 2.700 2.700 2.700 2.700 :2.700 2.700 2.700 2.700 2.700
FIAtt CAPACITY 5.100 5.100 7.700 7.700 7.700 7.700 7.700 10.300 10.300 10.300 !0.300
SURPLUS OR !DEFICIT> -KW 1. 140 670 2.800 2.330 1.860 1. 390 920 3.050 2.580 2.110 1.640
NET HYDRO CAPACITY -HI.H 19.770 19.770 19.770 19.770 19.770 !9.770 19.770 1'9,770 !9,770 !9.770 19.770
DIESEL GENERATION -"WH I. 218 4.126 7.034 9.941 :2.849 15.757 18.713 21, S/3 24.491 27,3S9 30,297
7-'6
1Q:'O 1980 1981 1 Cf!: 1983 19<''4 198':· 1°86 19~:7 1988 198°
3'. INVESTMENT COSTS l$1000l
1979 DOLLARS
A, EXISTING DIESEL I, 5?(• 1 ,~.~(1 1.550 1, S~·O I, 550 1 .. ~~so 1.550 I, 550 1 '550 I ,550 I ,550
B. ADDITIONAL DIESEL
UNIT I -870 870 870 870 870 870 S?(l 870 €<70 870
3
4
-· lo
c. EX I STING HYDRO
D. ADD I Tl ONAL HYDRO
UNIT 1 !2,940 12.940 12 .. G4t) 12,<>4(1 12.Q40 12.Q4() 12 .. Q4(1
2 1 ~, :..:c:.:' 1.:;;~362 19.36:: 19 .. 3C·2 19,362
3
E. TRANSM I S'3 I ON PLANT ADD I Tl 0N'3
UNIT 1
2
F. MISCELLANEOUS ADDITIONS
UNIT 1
2
TOTAL (S1000l
1979 DOLLARS 1.550 2 .. 420 2 .. 420 2.420 15. 36(1 15~360 34,722 34 .. 722 34,722 34,722 34,722
INFLATED VALUES 1 '550 2.490 2.490 2,490 20.095 20.095 49.682 49.6€<2 49,682 49.682 49.6€<2
4. FIXED COST <S1000)
INFLATED VALUES
A. DEBT SERVICE
1. EXISTING 66 66 66 t.6 66 66 6e. t,.t. 66 66 66
2. ADDITIONS
SUBTOTAL 2Y. -38 38 38 742 742 t , '92'5 1 .. 92~ 1t925 1,925 1.925
5"(. 57 57 57 1.1 H· 1' 116 2.sn. 2.€<96 2,896 2.89t. 2.896
7'Y. 73 73 73 1, 433 I, 43:: 3.7!8 3.718 3.718 3.718 3.7!8
9'Y. -89 89 8:9 I, 75'5 1,755 4, 55~5 4 .. ~~~5 4,55~· 4.555 4.555
B. INSURANCE £ ·-' 8 9 9 82 89 228 237 246 256 26t·
7-B
1Q70 1<>80 1<>BJ 1.;.s:: IQB? 1984 1"8~ 1 <>s~ ]987 1C!SS 198-0
TOTAL FIXED COST ($1000)
2'1. 71 112 113 113 890 897 2.219 2Y228 z~237 2.247 z,:z57
:5'1; 71 131 132 13::' 1. 264 1. 271 3.190 3.199 3,208 3.218 3.228
71( 71 147 148 148 1 .~81 1 .~88 4.012 4.021 4.030 4.040 4.050
9'1; 71 163 164 164 1.903 1' 910 4 .!~4<> 4.8:58 4.867 4,87'7 4.887
5. PRODUCTION COST ($1000)
INFLATED VALUES
A. OPERATION AND MAINT
1. DIESEL 169 239 268 302' 264 ::?<Q9 263 273 284 29'S 307
2. HYDRO - -
7 7 12 14 17 19 21
B. FL~L AND LUBE OIL 412 ~S2 721 921 333 '521
TOTAL PRODUCTION COST ($1000) '581 790 989 1' 223 604 827 27:5 2S7 301 314 328
TOTAL ANNUAL COST ($1000)
2'%. 6'52 902 1' 102 1 '33~. 1.494 '· 724 2,494 2.515 2 .. 538 21t561 2,':·85
~·% 652 921 1. 121 l $ 35tS 1.868 2, 09::::~ 3.465 3.486 3 .. 509 3,532 3.':'"·56
77. t.~2 937 1, 137 1. 371 2 .. 185 2,41~ 4.287 4.308 4.331 4 .. 8~·4 4.378
9% 652 9'5:3 1' 1~3 1.387 2.::.o7 2 .. 737 s, 124 5. 14'5 5,168 '5. 191 5.::?15
ENERGY REQUIREMENTS -MWH ::;,958 7.2C:H 8.~.o7 9.983 I 1 , 3'58 12.735 14.110 1'5.48'5 16.862 18~237 19,612
MILLS/KWH
21( 109 12S 129 134 132 13'5 177 162 1'51 140 132
sx 109 127 130 136 164 16'5 246 22S 208 194 181
7% 109 130 132 137 192 190 304 278 257 23~ 223
9% 109 132 134 139 221 21'5 363 332 306 28'5 266
c. PRESENT WORTH
ANNUAL COST ($1(>00)
2'1:. 6~2 843 963 I ,091 1, 140 1, 229 1,662 1.566 1. 477 1,393 I, 314
5'Y. 652 861 979 1.106 1.42'5 1.496 2.309 2. 171 2.042 1.921 1.808 n 652 876 993 1.119 1 '667 1, 722 2·957 2.683 2,521 2,368 2.226
9% ~·'52 8'91 i .oo7 1.132 1 '913 1 '951 3.414 3.204 3.008 2,824 2, t.st
D. ACCUMUL. ANN. COST ($1000)
2% 652 1,554 2.656 3.992 5.486 7,210 9.704 12.219 14.7'57 17.318 19,903
5% 652 1 '573 2.694 4.049 5.917 8.015 11.480 14.966 18.475 22,007 25.'563
7% 652 1 ''589 2.726 4.097 6.282 8.697 12.984 17.292 21.623 25.977 '30,355
97. 652 1,605 2,758 4.145 6.652 9,389 14.513 19.658 24.826 30.017 35.23~
E. ACCUMUUHEO PRESENT WORTH
ANNUAL COST ($1000)
2% 6'52 1.49'5 2.458 3.'549 4,689 5.918 7.580 9,146 10.623 12.016 13.330
5% 652 1.513 2.492 3.598 5·023 6.519 8.828 10.999 13.041 14' 96.2 16.770
77. 652 1.528 2.521 3.640 5.307 7.029 9.886 12.569 15.090 !7.458 19.684
9% 652 1.543 z,sso 3.682 5.'595 7' '546. 10.960 14.164 17' 172' 19.996 22.647
"' v c -" 0 .. : v Cf'• I(; c g· "" ... .., N fl 0 .., j~. v f-f (") i(J ;Q i)y ' 0 _. ..... .,. ..... I(JU .,.:. ...... " "' -li '(f (•: 0
t"<, c <t .,u C· -fLO -,.
f~ c ...... ..(•
.{).{) .. ( / ,,, " ({, 0 c
(lj
()
<t ".• (c~ q'
<tO' (fl (/J
" ..... ..f.J !"'· f'· •J:
·;
(;j 6:· (,.-, ......
<t " C·f-"1
U"l 11"1 -.;J-i)
f' (') ('. I"·( ... l(J ....... ...; • .. .. ....
wq 'no
(")<f ....
M M (') f"''
()j
0
-.() i..fj Qf-1
(\f C.t (';(#'I
(i (',1 N ( 4
·) ij 0 (} cc cc .
0
~
~ w z w ... a
I ,_
"' 0 :z 0'! .~ ;-..:;;,•
(4 t(J ,..._ (j
'•' w i ~ ~
§ If>
...J u ...J
•.) <t r
...
7-l!
l<x><• 1901 199;:' 1°Q3 1904 1 <><>:5 t<>96 1'?<n 1"'98 JOOO 20(>(•
3. INVEST1'1ENT COSTS tS1000l
1 979 DOLLARS
A. EXISTING DIESEL 1.550 t. !550 !.550 t.5so 1.550 !.550 t.s5o 1.550 1.550 !.550 1 ~ ~~(t
B. ADDITIONAL DIESEL
UNIT I
2 870 870 870 870 870 B70 870 870 870 870 870
3 --2.262 2,:262 2.262 2.262 2.262 2-262 2 .. 262 2.262 2-.26:2
4 -------2t2b2 2 .. 262 2.262 2.262
s
6
c. EXISTING HYDRO
D. ADDITIONAL HYDRO
UNIT I 12.940 12.940 12.940 12.940 12.940 12.940 12,940 12.940 12.940 12.940 12,940
2 19.362 !9.362 19.36:: 19.362 19~362 19.362 19,362 19-.362 19, 3C·2 19.362 10.36~
3
E. TRANSMISSION PLANT ADDITIONS
UNIT 1
2
F. MISCELLANEOUS ADDITIONS
UNIT 1
2
TOTAL (IJlOOO)
1979 DOLLARS 34.722 34.722 36.984 36.984 36.984 36.984 36.984 39.246 39.246 39.246 39,:246
INFLATED VALUES 49,682 49.682 54.231 54.231 54,231 54.231 54.231 59.765 59.765 59.765 :59.765
4. FIXED COST !S1000l
INFLATED VALUES
A. DEBT SERV I C£
1. EXISTING 66 66 66 66 66 66 66 66 66 66 66
2. ADDITIONS
SUBTOTAL 2')( 1.925 1.925 2.107 2.107 2.107 2.107 2 .. 107 2.32B 2.328 2 .. 328 2.328
5')( 2.896 2.89~. 3.174 3.174 3.174 3.174 3.174 3.512 3.512 3.512 3.!512
7')( 3,719 3.718 4.069 4.069 4.069 4.069 4.069 4.496 4,496 4.496 4.496
9'1. 4-.555 4,~55 4.985 4,985 4,9B~· 4.985 4,995 5.509 5.509 5.509 5.509
B. INSURANCE '217 288 327 340 354 368 383 439 456 474 493
TOTAL FHED CO"ST ('liOOOl
:'X
5'%
7'%
9/.
5. PRODUCTION COST !'ll00('l
INFLATED VALUES
A. OPERATION AND MAINT
I. DIESEL
2. HYDRO
B. FUEL AND LUBE OIL
TOTAL PRODUCTION COST ($IOOOl
TOTAL ANNUAL COST ('liOOOl
::?/.
'5'l..
7%
9/.
ENERGY REQUIREMENTS -MWH
MILLS/KWH
2%
5%
71.
91.
C. PRESENT WORTH
ANNUAL COST ($1000>
21..
~z
71.
9%
D. ACCUMUL. ANN. COST l$1000>
2'l.
5'1. n.
91.
E. ACCUMULATED PRESENT WORTH
ANNUAL COST ('l1000>
2'%.
51.
7%
91..
1 Q9(l
2· 268
3 .. 23'9
4.061
4. 8"8
:'<34
1<:>4
550
2., 81::::
3, 789
4, 611
~~ .. 448
20,<188
134
181
220
260
1 ,)39
1, 800
2.191
2,588
22,721
29.352
34,966
40.680
14.669
18,570
21,875
25.235
l""l
2,';.?7G
3~250
4,072
4,.909
464
23
693
1' 180
:::..;,.450
4.430
5 .. 25:'
6,089
23co$9b
145
185
220
255
1.536
1 '967
2,332
2.704
26.180
33.782
40.218
46.769
16.205
20.537
24.207
27.939
!q-O:_·
2.500
3.~67
4-.. 462
5,.378
5:2
24
1 .. 251
1 '797
4,2°7
5.364
f:,~ 2S9
7' 175
26.804
160
200
234
268
1. 783
2.226
2,597
2.977
30,477
39. 146
46.477
53.944
17.988
22.763
26.804
30.916
1 ~9 :~~
2.513
3.580
4.475
5.391
583
25
I. 874
2.462
4,995
f:-,06:2
l·· 957
7.87~:
29.711
168
204
234
265
I, 937
2.3~1
2.698
3,.0'53
3~ .. 472
45 .. 208
53.434
61.817
19,925
25. 114
29.502
33.969
1994
2, s:n
3.5<:>4
4,48<:>
~~405
650
2~-
2.567
3co243
:: •• 770
6.837
7.732
8,648
32~619
177
210
237
265
2 .. 091
2.478
2,.802
3. 134
41 '242
52~045
61, 16£.
70.465
22 .. Ott.
27.592
32.304
37.103
lQQ~
:-,'541
3.608
4.:502
~·~ 41 Q
721
27
3~339
4.087
~n6:?8
7' 6'?'5
8,5'>0
9 .. '50~.
35.527
187
217
242
268
2.245
2.607
2,910
3,220
47.870
59.740
69.756
79,<:>71
24,261
30.199
::t5.214
40.323
t<O<>,:,
2.55t·
3.623
4.518
5.434
797
28
4.203
~.028
7.584
8.651
9.546
10. 4t.2
38.483
197
225
248
272
2.401
2.739
3.022
3,312
55,454
68.391
79.302
90 .. 433
26 .. 662
32,938
38.236
43.635
1°<:>7
2~933
4.017
5.001
6.014
875
29
5.135
6.03<:>
8.872
l o. 0'5~.
11,040
12.053
41.343
215
243
267
292
2 .. 625
2.97S
3 .. 266
3.'566
£.4, 326
78.447
90.342
102,486
29.287
3:: •• 913
41.502
47.201
1 OQf::
2,8SO
4.034
'5.018
6.031
961
31
6.176
7.168
10.018
11 .zo::
12. 186
13,199
44 .. :?~1
226
258
275
298
2.770
3.097
3.370
3.650
74.344
89.649
102.529
115.68'5
32.057
39 .. 010
44.872
50.851
7-8
10QQ
2 .. 968
4.~2
5.036
6.04"
t.o~o
3::'
7.328
8.410
11, 27€:
!2.462
13.446
14.45"
47.159
239
764
285
307
2.914
3.220
3.475
3.736
gs,622
102.111
115,974
130.144
34.971
42.230
48.347
54 .. ~87
;:'(>(•(•
~~S:S7
4.071
5.os::
t:>.068
l' 147
8.'591
9,771
12.6S8
1:.<.84:'
]4,.826
15. ";::?O
~.n.o~.7
253
276
2"6
3H.
3 .. 057
3.343
3.581
3+S2S
98.280
ll !-, 9S3
130.8(l(l
14'5,983
3$3.028
4S,573
51-.928
se~412
7-1!
1 Q<;i"(l 1"'""1 !99:: 1QQ3 1<;194 )¢¢!, t<><>~o. !997 1~8 10<;10 2000
F. ACCL~ PRES WORTH OF ENERGY
l''!lLLS/KWH
21.. l. !58 1 ...... """)-· ... _ .... 1. 2BS 1 ~353 1.417 1.480 I ,542 I .t.06 !,US 1, 730 1, 791
5:~ 1.405 I, 487 I, '570 I .64<> 1 '7::?'5 1 '799 I ,B7C• 1.042 2,012 2.080 2.147
7% 1, 61Z I, 710 I .807 1 .s<>s 1 '984 2.obt. 2.1-4~ 2·224 2.300 ;:,374 2.445
91. 1 .. 825 t. Q38 2.049 ;:, 152 ::.249 2.33'9 2,425 2. 511 2~:593 2.672 2.748
POWE"R Ct:':, 1 STi I!:':Y ALTERNATE 8-A
J:''LLINGliAM/IiAK'lE:K/10 VILI..ACES -ELVA & GRA"7 -LOW Wf~~
}Ci'Q t9P'--. 1981 198::? 1983 1"'84 1 98':· 198~ 1987 1988 198Q
I. LOAD DEMAND
[lf"lANO -l<W :'),(\74 5.3~0 '=·~ 566 5.81:.; 6,058 6.3(14 6~~-;,o ~.81 C• 7.070 7.330 7,-soo
ENERGY -MWH :?0.888 2~. '?'"J.f, :?3~ 7E<?· 2~·· ~30 Zb· t·77 :_'0 ~ 1 :2~, 2~~57:' 30.<>78 32.38'5 33.7Q1 3'5. 198
SOURCES KW
A, EXISTING DIESEL
LOCATION OR UNIT I ::.600 2.600 z.~oo :?.bOO 2,600 :2.600 2,600 2~600 2t600 2.<:.00 2.600
z 4. 145 4. 14~:. 4. 14'5 4.145 4' 14~5 4, 145 4. 1 4'5 4.145 4,145 4,145 4,145
3 830 830 830 830 830 830 830 830 830 830 830
4
5
~
7
8
Q
10
11
12
B. ADDITIONAL DIESEL
LIN IT I 1.700 1.700 1,700 l. 700 1. 700 1. 700 1.700 1. 700 1.700 1. 700
2 -1. 100 1' 100 1' 100 1. I 00 1. 100 1' 100
3
4 -- - -7
5
~
c. EXISTING HYDRO
UNIT I
2
D. ADDITIONAL HYDRO
UNIT 1 ----1.500 1.500 1.500 1. 500 1.500 1.500 1.soo
2 ----2.700 2,700 2.700 2.700 2.700
3
TOTAL CAPACITY KW 7,575 9.275 9,275 9.275 10,775 11.875 14~575 14.575 14.'575 14.57'5 14.575
LARGEST UNIT I ,830 2. '530 2.'530 2.530 2.530 2.530 3.580 3.530 3.530 3.530 3.530
FIRM CAPACITY 5.745 6.745 6.745 6.745 8.245 9.345 11.045 11.045 11 '04'5 11.045 11.045
SURPLUS OR <DEF !CIT) -KW 671 I, 425 I, 179 933 2.187 3.041 4.495 4.23~ 3.975 3~715 3.455
NET HVORO CAPACITY -MWH --8.070 8.070 19.770 19.770 19,770 19.770 19.770
DIESEL GENERATION MWH 20.888 22.336 23.783 25.230 18.607 21.055 <;>.802 ll. 208 12.615 !4,021 15.428
8-A
1990 1991 1992 1993 1994 199'5 1996 1997 1998 109() 2000
1 • LOAD DEMAND
DEI"'AND -KW 7.850 8.oss 8.326 8.564 8.802 9,040 9,282 9,524 9.766 10.008 10.2'50
ENERGY -I1WH 36.604 37.850 39,095 40.340 41 '585 42.831 44.076 45.322 46.568 47.814 49.060
2. SOURCES -KW
A. EXISTING DIESEL
LOCATION OR UNIT 1 2.600 2 .. 600 2.600 2.600 2·600 z.~oo 2·600 2.600 2.600 2.600 2.600
2 4.145 4.145 4.145 4.145 4,145 4.145 4.145 4.145 4.145 4.145 4.145
3 830 830 830 830 830 830 830 830 S30 830 830
4
5
6
7
8
9
10
11
12
B. ADDITIONAL DIESEL
UNIT 1 1. 700 1. 700 1. 700 1 '700 1, 700 t. 700 1 • 700 1. 700 I, 700 1.700 1, 700
2 1.100 1,100 1.100 1.100 1, 100 1. 100 1.100 1.100 1.100 1.100 1.100
3 1. 200 1.200 t. 200 1.200 1. 200 1.200 1.200 1. 200 1.200 1.200 1 .zoo
4 -- -1. 000 1.ooo 1.ooo 1.ooo 1.ooo 1.ooo 1.ooo 1, 000
5 -------1.100 1.100
6
C. EXISTING HYDRO
UNIT 1
2
D. ADDITIONAL HYDRO
UNIT 1 1.500 1.soo 1.5oo 1.500 1.soo 1.soo 1.soo 1.500 1 • 500 1.500 1.5oo
2 2.700 2.700 2.700 2.700 2.700 2.700 2.700 2.700 2.700 2.700 2.700
3
TOTAL CAPACITY -KW 15.77'5 15.775 15.775 16.775 16.775 16.775 16.775 16.77'5 16.775 17.875 17.875
LARGEST UNIT 3.530 3.530 3.530 3.530 3.530 3.530 3.530 3.530 3.530 3.530 3.530
FIRM CAPACITY 12.245 12.24'5 12.245 13.245 13.245 13.245 13.245 13.245 13.245 14.34'5 14.345
SURPLUS OR <DEFICIT> -KW 4.395 4.157 3.919 4.681 4.443 4.205 3.963 :!!. 721 3.479 4.337 4.095
NET HYDRO CAPACITY -MWH 19.770 19.770 19.770 19,770 19.770 19.770 19.770 19.770 19.770 19.770 19.770
DIESEL GENERATION -MWH 16.834 te.oeo 19.325 20.570 21.815 ?"1.061 24.306 25.552 26.798 28.044 2'>'-':>90
8-A
107<':.• 1 08(1 1°81 1°2:: tCJ83 !084 !0085 I o8t. 1087 1088 108"
-"• INVESTMENT COSTS (S100(1 )
I 07•0 DOLLARS
A. EXISTING DIESEL : .• 2C-::-~·· 8&:· '=·· 8~·=-5,86:" 5. ~:6: 5-f:.::.: s.so..:: ~ .• E:t.:-~·.86::' ~ .. s.o . .:: 5. st.:
B. ADDITIONAL DIESEL
UNIT I J, 47" 1 '4 7~--I, 470 I, 470 1.47° I, 47" 1-470 I. 47"' 1,47Q I, 47"
2 957 0 57 957 957 057 9~7
_,
4
5
6
c. EXISTING HYDRO
D. ADDITIONAL HYDRO
UNIT I --12.940 12,04(> 12,040 12,040 12,940 12,040 12 .. 04(1
2 19, 3~.::? tC:•, ::62 10.36:." to,::-:t.:' t9,3C.::
.:0
E. TRANSMISSION PLANT ADDITIONS
liN IT 1 4, "'7~· 4. ~~7~· 4.,97':· 4,075 4.975 4,975 4.975 4.<>7'5 4,975
2 13.::.:::20 !3.320 13.320 13.320 13.320 13.320
F. MISCELLANEOUS ADDITIONS
UNIT I
2
TOTAL (S1000)
1979 DOLLARS 5.862 7.341 12 .. 3tt. 12.316 25.256 39.533 58.895 58 .. 895 58.895 58.895 S8,8Q~,
INFLATED VALUES 5.862 7.459 13,262 13.262 30.867 5!.845 81.432 81.432 81.432 81.432 81.43:?
4. FIXED COST ($1000)
INFLATED VALUES
A. DEBT SERVICE
1. EXI~:TING 238 ')':>0 238 238 238 23~: 238 "'~" ..... ..:-...... 238 238 23:?
2. ADDITIONS
SUBTOTAL 2% 64 296 296 1.000 I .839 3.022 3.02:" 3.02:: 3.022 3. 02:·
'5% 98 4'5:2 452 J,'5!1 2.79';: 4.572 4.572 4,572 4.572 4,'57:'
7% 123 57! 57! I ,931 3.551 ~~.83~· ~. 83t. 5.83-!. ~·.836 '5.836
9% 1~·1 700 700 2.366 4.351 7, 151 7. 1'51 7. 1~·1 7. 1~·1 7, !51
B. INSURANCE !8 24 46 50 126 229 373 388 404 420 437
II-A
1979 1980 1981 1982 1983 1984 198~ 1986 1987 1QB8 I~
TOTAL FIXEO COST <SIOOO>
2X 256 326 sso SS4 1.364 2.306 3.633 3.t.48 3.664 3. t·80 3~6Q7
~7. 256 uo 736 740 1.87:'5 3.259 5.1S3 ~. 198 ~ .• 214 5.230 5.247
n. 256 385 85~ 8:'59 2.~9S 4.018 6.447 6.462 6,478 6.4<>4 6.511
9'1. 256 413 9S4 9S8 2.730 4.SI8 7.762 7.777 7.7<>3 7,809 7.82!
5. PRODUCTION COST (SIOOO>
INFLATED VALUES
A. OPERATION AND MAINT
I. DIESEL 651 803 645 710 70'5 S4:'5 761 S08 855 906 ~9
2. HYDRO - - --7 7 IS 19 20 21 21
B. FUEL AND LUBE OIL 1.69S 1,994 1.994 2.326 I.S8S 2.349 1.161 1.405 1.677 1.975 2.304
TOTAL PRODUCTION COST (SIOOO> 2.346 2,797 2.t.39 3.036 2.600 3.201 1,940 2.232 2.~~2 2.902 3.284
TOTAL ANNUAL COST (SIOOO>
2'l. 2.602 3.123 3.219 3.620 3,964 5.'507 5.573 5.880 6.2H· t:.,S82 t .. 98!
S'l. 2.602 3.157 3.375 3.776 4.475 t·.460 7.123 7.430 7,766 s. 132 8.5C:I
7% 2.t.02 3.182 3.494 3.895 4,895 7.21<> 8 .. 3€:7 £!,694 9.030 9,39C. '?,79'S
9% 2.602 3.210 3.623 4.024 5.330 8.019 9.702 10.009 10.345 10.711 11.110
ENERGY REQUIREMENTS -MWH 20.888 22.336 23.783 25.230 26.677 29,125 29,572 30.978 32.3S5 33.791 35. 198
MILLS/KWH
2'1. 125 140 135 143 149 IS<> 18S 190 192 195 198
57. 125 141 142 ISO 168 222 241 240 240 241 242
7% 125 142 147 154 183 248 284 2SI 279 278 278
97. 125 144 152 159 200 275 328 323 319 317 316
C. PRESENT WORTH
ANNUAL COST ($1000)
2% 2.602 2.919 2.812 2.955 3.024 3,926 3.714 3.662 3.618 3.5SO 3,549
5% 2.602 2,9SO 2.948 3.082 3.414 4.606 4,746 4.627 4.520 4,423 4,337
7% 2.602 2.974 3.052 3.179 3.734 5.147 5.589 5.414 5.256 S, Ill 4,979
9'1. 2.602 3.000 3.164 3.285 4.066 5,717 6.465 6.233 6.021 5.826 5.648
D. ACCUMUL. ANN. COST <SIOOO>
27. 2.602 5,725 S.944 12.564 16.52S 22.03:'5 27.608 33.488 39.704 46.286 53,;>t.7
57. 2.602 5.759 9.134 12.910 17.385 23.S45 30,96S 38.398 46,164 54.296 62.827
7% 2.602 5.784 9.27S 13.173 18.068 25.287 33.674 42,368 51 .3?8 60,794 70.~·Pq
9% 2.602 5.812 9,435 13.4~9 18.789 26.S08 36.510 46,519 56.S64 67.57:'5 78.685
E. ACCUMULATED PRESENT WORTH
ANNUAL COST <SlOOO>
27. 2.602 5.~21 S.333 11.288 14.312 IS.238 21.9~2 25.614 29.232 32.812 36.361
S'l. 2.602 5.552 s.soo 11.:'582 14.996 19.602 24.348 28.975 33.495 37,918 42.255
7% 2.t.02 5.576 8.628 11.807 15.541 2o.t.88 26.277 31.691 36,947 42.0'58 47.037
9% 2.602 5.602 8.766 12.051 16.117 21.834 28.299 34,532 40.5'53 46.379 52.027
(I (", t·, ~ 0 o, ... ;;, 0 ('lilt .(, '" () < -c ·.:. ,, . VI"-.:, .... "' tu N (<'I 1#1 "' 0~· () '" 0 ~·· ('J'_, 0 ,., ~-. t'-' 0(< 0 ... f;j () (?; 0 N wo ()
-<• 0 0 ~ f I
{j)
0
ifJ 0 v .. 0
~·· &; ~· 0 0 ,,
()
¢
,. c, o:•
i " t'-(f;
0
If;-,·i " , .. (f; c.·, ... , .. .(,-(; -() "' w
0
_t .. J '' , •• !
0 0 (I ,., ... If• If• .. ,
w
... -<· \-.-,
"{{J([J 0
(f; (•'/ (''"; <'• (f;
0
-.) !" ..... ~
& r~ r; r; (j
0
~.~·.v·-;.~·, J'
(-I (if. ( j
.j ....
0
u
If.
UJ :z: w
u..
0
::::
1-
{.{.
0
3 ~ ;-:: ··~ ~ ('of1fJ,..... Q u·,
w :I: rt. 3
(L ...
" 5 ({>
.J u _j u
<I t:
4.
8-A
1990 19">1 1992 1993 1994 199'5 I 9<>~. I 997 1098 1999 2000
3. INVESTI'IENT COSTS ($1000)
197'9 DOLLMS
A. EXISTING DIESEL '5.862 '5.862 5.862 ~.862 5.862 5.96:2 5~962 5.862 s .. e62 5,862 ::;.862
B. ADDITIONAL DIESEL
UNIT I I, 47'? I • 4 7<> 1.47<> 1.47" I ,47° 1.479 1.479 1.479 1.479 1,479 1.479
2 ~7 ~7 9"57 957 ~7 957 957 ~7 ~7 ~7 957
3 1.044 t.044 !.044 1· 044 1.044 I, 044 1.044 1.044 1,044 1.044 1.044
4 -870 870 870 870 870 870 870 870
5 ------957 957
6
c. EXISTING HYDRO
D. ADDITIONAL HYDRO
UNIT I 12,040 12.940 12.940 12.940 12t940 12.940 12.<>40 1.2.940 12.940 12 .. 940 12.940
2 19.362 19 .. 362 19.362 !9,36:2 19.362 19,362 19, 3e·2 19. 3<.:2 19.362 19.3:62 19.362
3
E. TRANSMISSION PLANT ADDITIONS
UNIT 1 4,975 4.975 4.975 4,975 4 .. 975 4 .. 975 4.975 4.975 4.975 4.975 4.<>75
2 13.320 13.320 13.320 13.320 13.320 13.,320 13,320 13.320 13 .. 320 13,320 13,320
F. MISCELLANEOUS ADDITIONS
UNIT 1
2
TOTAL IS1000)
1979 DOLLMS '59.939 ::>9.939 59.939 60.809 60.809 60.809 60.809 60.809 60.809 61.766 61.766
INFLATED VALUES 83.373 83.373 83.373 85.192 85.192 85.192 85.192 es. 192 85. 192 87.724 87.724
4. FIXED COST l$1000)
INFLATED VALUES
A. DEBT SE:RVICE
I. EXISTING 238 238 238 238 238 238 238 238 238 239 238
2. ADDITIONS
SUBTOTAL 24 3.100 3.too 3.1oo :J, 173 ::<, 173 3. 173 3.173 3. 173 3.173 3.274 3.274
'57. 4,601 4. <·91 4.691 4.802 4.802 4,9:02 4i802 4.802 4 .. 802 4.957 4.957
77. 5t98t. 5.986 ~·,98~. 6. 12<· 6.126 6.126 6 .. 1.26 6.126 6.126 6 .. 322 6·322
9% 7 .. 335 7.335 7.33!:. 7.507 7.507 ,,~07 7.507 7.507 7.507 7.747 7,747
B. INSURANCE 46~ 484 ~03 ~34 556 578 601 b25 650 696 724
TOTAL FIXED COST (~1000>
:2'l.
~'l.
7'l.
9'l.
5. PRODUCTION COST (~1000)
INFLATED VALLIE~
A. OPERATION AND HAINT
1. DIESEL
2. HYDRO
B. FUEL AND LUBE OIL
TOTAL PRODUCTION COST ($1000>
TOTAL ANNUAL COST ($10~'>
21.
~I.
71.
~I.
ENERGY REQUIREMENTS -HWH
HILLS/KWH
21..
~'l.
7'l.
9':1.
C. PRESENT WORTH
ANNUAL COST ($1000)
2/.
5':1.
7':1.
9'l.
D. ACCUHUL. ANN. COST ($1000>
2%
5'l.
7':1.
9':1.
E. ACCUMULATED PRESENT WORTH
ANNUAL COST ($1000)
21..
5%
7':1.
9':1.
}o::;lO(l
3.803
5,3Q4
6.6ro
8· 0?::
1' 016
:=:~ J:../:.6
3.704
7, ~507
'?. o-o:::-:
10. ?93
11' 742
36.604
205
249
284
321
3.'567
4,322
4.938
~.'57"
60. 774
71· 925
80.982
90.427
39,928
4t .• '577
5},<;175
57, .;.ot.
190!
~ o~ "'""'' '-"'-
~.41
6.70
8.0~
I ,(172
3.034
4. 129
7,0~·1
9,542
1 (), 837
12. 186
37.8~0
210
2~2
28t.
322
3.530
4,237
4.812
~.411
68,72'5
81.467
91,819
102.613
43.458
50.814
56,787
63.017
1"::.9::
3.841
~. 43:2
.;., 727
8.07<
I, 133
24
3.436
4,~93
8.434
10.025
11.320
12.6t.9
39,09'5
216
256
290
324
3.500
4.160
4.~.97
5.257
190?
3· 94~·
~.574
6.898
s. :7'''
I, 19~.
-,~ •..
3.87-:J
5,(109
9,(144
10.677:
11· 007
13.378
4(J, 340
224
26S
297
332
3,507
4> 139
4.6~·~'
~. 188
77.1~9 86.203
91.492 102.16~
103,139 115.136
115.282 128.660
46.9~8
~4.974
61,484
68,274
50.465
59.113
66.137
73.462
)094
3,067
~ .• ~96
6.0 ::0
s. ::::..:ot
1. :!62
26
4.3~0
5.647
0,614
11, ~4 ~:
1:::.567
13."'48
41.585
231
270
302
335
3,48'5
4, 07~·
4.555
~.055
}90~,
3,9BO
!"·.618
6,942
::::, 3:::·.::-<
I ,331
27
4,886
.;., 244
10.23?
11.862
13, 18<·
14.~·67
42.831
239
277
308
340
3.466
4,018
4,467
4,934
!90t
4.01:'
s.641
6,C:•t..5
s. 34t.
I .40~·
28
~·· 458
.;., 891
10,903
12.'532
13. t:5/:.
1~.237
44, on.
247
284
314
346
3.4~2
3,967
4.386
4.824
95,817 106,0~0 116.953
113,408 125,27(1 137,802
127.703 140.889 1'54.74'5
142.608 1~7. 175 172.412
53.950
~.3, 188
70,692
78,517
57, 4!t.
67.206
7~. 159
83.4'51
60.868
7!.173
79.'545
88.27'5
1~97
4.036
5.6t·5
6.980
8.370
I, 481
29
.;., 084
7,504
11.630
I:~, :2:09
14.583
15,964
45,322
257
293
322
352
3,441
3.923
4.31~
4.723
}QQ8
4,061
5,690
7.014
8,395
I .~60
31
6,761
8.352
12.413
14,042
15.366
16,747
46,568
267
302
330
360
3.432
3.883
4.249
4.631
6-A
!99<>
4.208
5.891
7.~.t.
8.681
I, t.47
32
7.502
9.181
t::::, 3E:9
~~.072
16.437
t7.8t..2
47.814
280
315
344
374
3.460
3.895
4,248
4.616
2000
4. 236
~.019
7,,284
8,70"
1.735
33
8.303
10.071
14,307
15,99(1
17.355
18.780
49,060
292
326
3~4
383
3.455
3.862
4,191
4.53t.
12~:.583 140.996 154.385 168.692
1~1.061 165,103 180. 17'5 196,165
169.328 184,694 201.131 218.486
188.376 205.123 222.985 241.765
64.309
75,096
83,860
0 2.998
67.741
78,979
88.109
97.629
7!.201
82,874
92.357
102.245
74, 65t·
86,736
06,548
lOt., 781
"-, I(J ..u 0 c•-c 0 N ll"100-c c N N ('~ C··J N < .. ..v_,.... I C"J.(JC"J-"' 0' -·,..... c 0 0 NNN Cl') C:II(J('l C· ..{J(I)q C-4 (0 Cf'J..() o--. 0 0 Nr<N N OJ--G
f..iJOI(J t4
" o-. V1 I(J 00
0
0 -N ('~ (~
N..-.£J.; -_,(,-
.{) 0 N ..-I'
0'
0' -NN C'-4
•• ,......u
C"JNI{J C
11"1 (!J-('"J ...()
0
0' -N~··· N
C"JOV1 _..
111 (0 I{) 0 ... ,..... c (~ •
"" 0 -NC'~ N
0' ,, ... 0
-{, M ... I' ,,, -.()0'-C"J
0
0' --C'i ('~
NO'O
ffiNN..-« W'"J rJJ c (~
0'
"" --NN
(-j C"J 0 " O'NOO
... ,.._0' -0'
0 -..... -('~
o--. -r• • o-.-oo..()
0 M...U,....o-.
"" ""
> ~ w z w
IJ..
0
:z: .....
~
:J N:-::-.!N " ~-, " ()-. '" w i cc
ll.. :<:
' § "' _J u _J u -<I X:
~
PQI.IER COS1 STUDY ALTER!IATE 8-B
DlLLl!IGHAM/NAJ:NEX/ I 0 Vll.LAG£5 -ELVA & GllANT -liiGH LOAD
1~70 1°80 !98! !982 198? 1<>84 1985 1Q8b 1987 IQ88 }Q8Q
I. LOAD DEMAND
DEMAND -KW 5.(174 ~·· 700 /o-.476 7~ :?'~·~ 8~028 8.804 9.580 10.354 11 ~ 128 II ,QO:? 12.676
FNERGY -MWH :?0.888 25.0 :'4 29~ 7~51 33~'578 37.40t 41.232 4'5.060 48.888 '52.716 '56.544 60.37:?
2. SOURCES -KW
A. EXISTING DIESEL
LOCATION OR UNIT I 2.600 2.600 2.600 2.600 :?.600 2.600 2.600 :?.600 2.600 2.600 2.600
2 4, 145 4.145 4. 14'5 4,145 4, 14'5 4. 145 4. 14'5 4,145 4, 14'5 4.14'5 4. 14'5
3 830 830 830 830 830 830 830 830 830 830 830
4
5
6
7
8
Q
10
II
12
B. ADDITIONAL DIESEL
UNIT I 3.000 3.000 3.000 3.000 3.000 3.000 3.000 3.000 3.000 3.000
2 -3.000 3.000 3.000 3.000 3.000 3.000 3.000 3.000
3 ---------3.000
4
'5
6
c. EXISTING HYDRO
UNIT .
D. ADDITIONAL HYDRO
UNIT I ----I, '500 I, '500 I .'500 I, '500 1.'500 1.500 I .'500
2 ----- -
2.700 2.700 2.700 2.700 2.700
3
TOTAL CAPACITY -KW 7.'57'5 10.'57'5 10.'57'5 13.'575 1'5.07'5 1'5.07'5 17.77'5 17.77'5 17.77'5 17.77'5 20.77'5
LARGEST UNIT 1.830 3.830 3.83(1 3.830 3.83(1 3.830 3.830 3.830 3.830 3.830 3.830
FIRM CAPACITY '5.74'5 6.74'5 6.74'5 9.74'5 11.24'5 11,245 13.94'5 13.94'5 13.94'5 13.94'5 16,94~
SURPLUS OR <DEFICIT) -KW 671 1.04'5 269 2.493 3.217 2.441 4.36'5 3,'591 2.817 2,043 4.26<>
NET HYDRO CAPACITY -~WH ----8.070 8.070 19.770 19.770 19.770 19.770 19.770
DIESEL GENERATION -MWH 20.888 2'5.924 29.7'51 33.'578 29.336 33.163 2'5.290 ~9.118 32.946 36.774 40.602
8-B
1990 1991 1092 }003 J004 19QS 1996 1<>97 1998 199'9 2000
I. LOAD DEI'IAND
DEI'IAND -KW 13.4'!10 14.480 15.510 16.'540 17.570 18.600 19t-628 20.656 21,684 22.712 23,740
ENERGY -I'IWH 64.200 70.282 76.364 82.446 88.'528 94,610 100.6"'3 106.776 112.858 118.941 125.024
2. SOURCES -KW
A. EX I STING DIESEL
LOCATION OR UNIT 1 2.600 2.600 2.600 2.600 2.600 2.600 2.600 2.600 2.600 2.600 2.600
2 4.145 4.145 4,145 4.145 4.145 4' 14'5 4,145 4.145 4.145 4.145 4.145
3 8::>0 830 830 830 830 830 830 830 830 830 830
4
5
6
7
8
9
10
11
12
.13. ADDITIONAL DIESEL
UNIT 1 :;..ooo 3.000 3.000 3.000 3.000 3.000 3.000 3.000 3.000 3.000 3.000
~ 3.000 3,000 3.000 3.000 3.000 3.000 3.000 3.000 3.000 3.000 3.000 ~
3 3.000 3.000 3.000 3.000 3.000 3.000 3.000 3.000 3.000 3.000 3.000
4 --4.000 4.000 4.000 4.000 4.000 4.000 4.000 4.000 4.000
5 ----3.000 3.000 3.000 3.000 3.000 3.000
6 --------3.500 3.500 3.500
c. EXISTING HYDRO
UNIT 1
2
D. ADDITIONAL HYDRO
UNIT 1 1.500 1.5oo 1.500 1· 500 1.500 1.500 1,500 1·500 1 .soo 1.500 1.500
2 2.700 2.700 2.700 2.700 2.700 2.700 2,700 2.700 2.700 2.700 2.700
3
TOTAL CAPACITY -KW 20.775 20.775 24.775 24.775 24.775 27.77"5 27,775 27.775 31' 275 31.275 31.275
LARGEST UNIT 3.830 3.830 7.030 7.030 7.030 7.030 7.030 7.030 7.030 7.030 7.030
FlRI'I CAPACITY 16.945 16.945 17.745 17.745 17.745 20,745 20,745 20,745 24.245 24.245 24.245
SURPLUS OR <DEFICIT) -KW 3.495 2,405 2.235 I .205 175 2.145 1.117 89 2.561 I ,533 505
NET HYDRO CAPqCITY -I'IWH 19.770 19.770 19.770 19.770 19.770 !9.770 19.770 ]9,770 19.770 19.770 19.770
DIESEL GENERATION -MWH 44.430 50.512 56.594 t-2.676 68.758 74.84(1 AO .. 92:.,. 87.006 93.0~c: 99.171 1'15.254
8-8
197<0 1980 198! !98;? 1983 1984 198'5 1986 JQ87 1988 198'>
3. INVESTMENT COSTS ($10<)(1)
1<>79 DOLLARS
A. EXISTING DIESEL 5tSt: . .:' s.s~;.::: 5.8l:.:' ~~,st.: ~., 8-t.::? 5,$62 ~ .. 862 s~sb:? 5.862 5.862 5,862
s. ADDITIONAL DIESEL
UNIT 1 2 .. ~·10 2.61(1 2·610 2.610 2.610 2.610 2,610 2·b10 2 .. 610 2.610
2 2,610 2.610 2.610 :;::.610 2·610 2.610 2-.btO 2.610
"' ----2 .. 010
4
5
6
c. EXISTING HYDRO
D. ADDITIONAL HYDRO
UNIT 1 -12.940 12-.940 12.940 12.940 12.940 12,'940 12.940
2 -· --19,362 19,36~ 19 • .362 19,362 19.:362
3
E. TRANSMISSION PLANT ADDITIONS
UNIT 1 -4.97'5 4,97'5 4,97'5 4,97'5 4.975 4.975 4 .. 975 4.0 75 4,97'5
2 13.320 13,320 13.320 13 .. 320 13.320 13.320
F. MISCELLANEOUS ADDITIONS
UNIT 1
2
TOTAL ($1000)
1979 DOLLARS 5.862 8.472 13.447 16.057 28.997 42.317 61.679 61.679 61.679 61.679 64.289
INFLATED VALUES 5,862 8.681 14.484 17.772 35.377 54,948 84.'535 84.535 84.'535 84.53'5 89.201
4. FIXED COST ($1000)
INFLATED VALUES
A. DEBT SERVICE
1. EXISTING 238 238 238 238 238 238 239 238 238 238 238
2. ADDITIONS
SUBTOTAL 2Y.. -113 345 477 1. 181 1.964 3. 147 3. 147 3.147 3. 147 3.334
~~.. -172 '526 727 1· 786 2.981 4.761 4.761 4.761 4.761 '5.046
7'l. -218 661:;. 920 2.280 3.791 6.07~. 6.076 6.076 6.076 6.431;
9'l. -267 811::· 1. 127 2,793 4.645 7.445 7.445 7. 44~· 7.445 7.887
B. INSURANCE 18 28 51 67 144 242 388 403 419 43t. 478
8-11
1970 1980 1981 198:C 1983 1984 1985 198t-1987 1988 1989
TOTAL FIXED COST !SIOOOl
2% 25t. 379 634 782 1 co563 2.444 3.773 3.788 3.804 3.821 4.050
~7.. 2St. 43~ 815 I ,()32 2, 16S 3.461 5.:387 51402 5.418 5.4:,:15 5,762 n; 25t-484 955 t. 225 2.062 4.;271 6.702 6.717 6.733 6.750 7 'f 1 ~::
97. ~56 533 1.105 1.432 3.175 5,125 8.071 8.086 e. 102 e. llo 8.603
5. PRODUCT! ON COST (S1000l
INFLATED VALUES
A. OPERATION AND MAINT
I • DIESEL 651 830 925 I .032 804 907 861 "137 1.083 1. 171 1. 264
2. HYDRO ----7 7 18 19 20 21 21
B. FUEL AND LUBE OIL 1.695 2.314 2,494 3.097 2,976 3.701 2.991 3·651 4.380 5,182 6.064
TOTAL PRODUCTION COST ($1000) 2.346 3. 144 3-.419 4,129 3.787 4.615 3.870 4.607 5.483 6.374 7.34"
TOTAL ANNUAL COST ($1000)
2'l. 2.602 3,523 4.053 4.911 5.350 7.059 7.643 8,395 9,287 10.195 11' 30Q
57. 2.60.2 3,5S2 4,234 s. 161 5.955 8.076 Q,,257 10.009 10.901 11.809 13.1 11
7X 2 .. 002 3.t.zs 4.374 5.354 6.449 e. esc. 10.572 11. 3::?4 12 .. :216 13. 124 14.501
9% 2.602 3.677 4.524 5.561 6-962 9.740 11,941 12,693 13.585 14.493 15.952
ENERGY REQUIREMENTS -MWH 20.688 25,924 29.751 33.578 37.406 41 .233 45.060 48.888 52.716 56,544 60.37::
MILLS/KWH
2'l. 125 136 136 146 14~: 171 170 172 176 ISO 189
S'l. 125 138 142 154 159 196 205 205 207 209 217
77. 125 140 147 !59 172 216 2~5 232 232 232 240
97. 125 142 152 166 186 23c· 265 260 2SS 256 264
c. PRESENT WORTH
ANNUAL COST ($10001
2"-' 2.602 3.293 3,540 4.009 4.081 5,033 5.09:;l 5.228 5.405 5.545 5.7~
57. 2.602 3.348 3.698 4.213 4.543 5,758 6.168 ~·.233 6,344 6.423 6. ~.65
77. 2,602 3.391 3.820 4.370 4.920 6.336 7.045 7.052 7. 110 7.!39 7.372
97. 2-602 3.436 3.951 4,539 5.311 6.944 7.957 7.905 7.907 7.683 8.109
o. ACCUMUL. ANN. COST ($1000)
2'l. 2.602 6.125 10.178 15.089 20.439 27.498 35.141 43.53C. 52.823 63,(118 74.417
5% 2.602 6.184 10.418 15.579 21.534 29.610 38.8~.7 4s.su. 59.777 71, 56C. 84.697
7'l. 2.602 6.:230 10.604 1S,959 22,407 31.293 41 .ee.s 53.189 65.405 78.~29 93.030
97. 2.602 6.279 10.803 16.364 23.326 33.066 45.007 57.700 71.285 85.778 101.730
E. ACCUMLILATED PRESENT WORTH
ANNLIAL COST ($1000)
2'l. 2.602 5.895 9,.435 13.444 !7.525 22,558 27.651 32.879 38.284 43.829 49.624
~% 2.6(12 5.950 9.648 13.861 18.404 24.162 3(1.330 3~ .• 5e·3 42.907 49.330 55,Q9S
7"1. 2.602 '5.993 9.813 14.183 19.103 25.439 32.484 39.536 46.646 53.785 61,157
97. 2.602 6.038 9.989 14.52€: 19.839 26,783 34.740 42~b4S ~·0,552 59.43~ ~.t.' '544
8-B
198(1 lo-::1 1"'8::' 198:< 192.4 1<>85 1 <>f:<· 1987 1988 1989 .. ACCllM PRE~· WORTH Ql' ENERC•Y
MlLl.S/I<WH
::r. 1 ")~<:"_ '"')e--. -_,_ ?71 4'>(· ~.OQ 7~· 834 94! t. (143 l .t41 l. 237
51. ~~~ :'54 37S 5(•4 ~,:;~ 7,:.:, -:'J02 1 ,(l3() 1 .! '50 1 '264 1 ~ '374
Tl. ~ ::-: ::::.'~·t 884 ~·! 4 (:.4~. 70•:::. '>5<;. 1, I ()(• 1 ~ 23'5 l. 361 l, 483
0% 1::'~ ::~.E; 3ql c;-._::"7 t-o"' C•"?""? 1 '(1!4 1, !7e. 1 .3:?<.. !. 4<..5 1, ~CX'
8-1!
1990 1<>91 !992 1'"93 1994 199~ !996 1997 t<>98 199'9 2000
3. INVEST!'IENT COSTS ($10<>01
1979 DOLLARS
A. EXISTING DIESEL '5·962 '5.$62 '5.!:<~.2 5 .. Sb2 '5.8<!;.;2 5 .. 86~ 5,SC-2 5,.'~C.2 '5.862 5 .. sc,2 5,862
8. ADDITIONAL DIESEL
LIN IT 1 z~oto 2·610 2.610 2.610 2 .. 610 2.610 2.610 2.610 2.610 2.610 2.610
2 2, <!.·10 2.610 2.61(> 2.6!0 2·610 2·610 2.c.1o 2.610 z,blO 2.610 2.610
3 ~.c. to 2·610 2 .. 61(1 2.610 2 .. 610 .2 .. 610 2'·610 2·610 2,610 2. 610 2'1:610
4 -3.480 :;:, 480 :<' 48(> 3.480 3.480 3.480 3.480 3.480 3.480
'5 ----2.610 :,610 2.610 2.610 2 .. 610 2.610
6 ---3.04'5 3.04'5
c. EXISTING HYDRO
[1. ADD lT I ONAL HYDRO
LINIT I 12,940 12.940 12,940 12,040 1:",94(1 12,940 12,Q4(1 12.940 12,940 12~940 12.940
~. 19.362 19 .. 362 19 .. ::::c.: }9',862 1 <>, 3c.~ 19.362 19.362 tt:~ .. 362 19.3<!:.2 19.362 19.362
3
E. TRANSMISSION PLANT ADDITIONS
I..INIT 1 4.975 4 .. 975 4.975 4,<>75 4,97';; 4.975 4,975 4.975 4.97:5 4,97'5 4.975
2 13 .. 320 13"320 13.320 13.320 13~320 13.320 13.320 13 .. 320 13 .. 320 13 .. 320 13.320
F. MISCELLANEOUS ADDITIONS
UNiT 1
2
TOTAL ($1000)
1979 DOLLARS 64 .. 299 64.299 67.769 67.769 67.769 70.379 70.379 70.379 73.424 73.424 70.379
INFLATED VALUES 89.201 89,201 96. 199 96.199 9<!,., 199 102.103 102.103 102. 103 109,8'51 109.8'51 101.471
4. FIXED COST ($1(1()0)
INFLATED VALUES
A. DEBT SERVICE
1. EKISTING 238 238 238 238 238 238 238 23€: 238 238 238
2. ADDITIONS
SUBTOTAL 2% 3. 3:<4 3. 3:<4 3.614 ~:. 614 3.614 3.8'50 3~8~0 3.8'50 4.160 4, 1~·0 3~825
5% s. 04t. s.o4t.. ~., 473 5,473 '=·· 47~: ~·.834 ~ .. 834 5,834 6.307 6.307 ~.795
nc 6.436 6.436 6,976 ~ .• 976 6. 97{. 7.432 7.432 7.432 8.030 8.030 7.383
9% 7.887 7.887 8.549 $,549 8.54~ 9,108 9,!08 9, 10Et 9.841 9.841 9.048
B. INSURANCE 498 517 580 604 628 /:..9~: 721 749 839 ~77 838
8-Jl
I <><>(• I Q9! 19<>2 1 Q9:;~ 19<>4 1995 1996 1'>97 1998 199'> 2QOO
TOTAL FIXED COST (51000)
2/. 4.070 4.08° 4.432 4 ~ 4~.(:. 4.480 4.781 4.80<> 4.837 5,237 5.270 4,901
S'X 5,78.:' ':·.801 t_-,.2"01 t-.31'5 bt33<i b. 76'0. C-,79:: 6.821 7.384 7.417 b.87l
7Y. 7 .. 1/Z 7,10! 7,794 7.818 7.S42 8.363 8.391 8,4j<> 9,107 "'· 140 8.45<>
97: 8 .. 622 8~64: 9,367 0.:501 ()' 41-:· 10,03° to,oc.7 10. 09':· 10,<>18 10,951 1 0'1 124
5. PRODUCTION COST ($1000)
INFLATED VALLIE:$
A. OPERATION AND MAINT
1. DIESEL 1' 36.:::> 1.497 I, 720 1 '874 :: .. 039 ::.306 2.4°4 2.6"''1 2·906 3. 131 3.372
2. HYDRO 22 23 24 25 2~. 27 2E: 29 31 32 33
B. FUEL AND LUBE OIL 7.034 8.476 10,066 1!.819 13.744 15.856 18.173 20,711 23.491 26 .. 527 2'9.842
TOTAL PRODUCTION COST ('61000) 8.419 9,996. 11.810 13.718 15.80<> 18,189 20. 6Q~, ::3.434 26 .. 428 29.690 33.247
TOTAL ANNUAL COST <S1000l
2'% 12 .. 489" 14.085 16.242 18.174 20.289 22.<:170 25 .. 504 28 .. 271 31.665 34.960 38. 148
5% 14.201 15.7'>7 18 .. 101 20.033 22 .. 148 24?954 27.488 30,25'5 33}812 37' 107 40. 118
7% ]~It 591 17.187 19,604 21 .. 53b 23.t.Sl 26,55:· 29 .. 086 31.853 35~535 38 .. 830 41.706
9% 17.042 18.638 21, 177 23, 10<:J 2~ ... 2::4 28.22::; 30.76':.: 33,529 37,84b 40.641 43. 37l
ENERGY REQUIREMENTS -I'IWH 64.~00 70.282 76.364 82.446 88.52E: 94,61(> 100.693 106.776 112,858 118.941 125.024
I'IILLS/KWH
2'l.. !95 200 213 220 229 243 2S~ 265 281 294 305
5'1. 221 225 237 248 2'50 264 273 283 300 312 321
n: 243 245 257 261 267 281 289 298 315 326 334
9'Y. 26'5 265 277 280 285 298 306 314 331 342 347
c. PRESENT WORTH
ANNUAL COST ($1000)
27. 5,933 6,. 2~54 6.740 7.048 7.354 7.781 8.074 B.364 8.7'56 9.034 9~213
5% 6.747 7.014 7.511 7.769 8,027 8,4'53 s, 702 ~h 9'51 9.349 9.589 9.689
n:: 7.407 7.631 e, 135 8,352 s,S72 8.994 9.20Et 9.424 91826 10.034 10.073
9'Y. 8.097 8,275 8.788 8.962 9.142 9.562 9.738 9.920 10.326 10.502 10.47!·
D. ACCUMUL. ANN. COST 1'61000)
21.. 86.906 100.991 117.233 135.407 15~.696 178.666 204. 170 232.441 264, 106 299,066 337.214
5% 9E).898 114.695 132.796 152~829 174,977 199.931 227,419 2~7.674 291,486 328.593 368.711
7% 108.621 125.808 145~412 1t·6· 943 190.599 217.151 246.237 278,.090 313.625 352,455 394.!61
9% 118.772 137.410 158.587 18!.696 206.920 235,.148 265.910 2'1)9,43'4 336.785 377.426 420.797
E. ACCUMULATED PRESENT WORTH
ANNUAL COST ($!000l
2% '55.557 61.811 68.'551 75.599 8.2,953 90.734 98.808 107.172 115,928 124.962 134.175
5% 62.742 69.756 77.21;.7 85.03(;. 93.063 101.516· 110.218 119.16.9 128.518 138.107 147.796
7% 68.564 76.195 84.330 92.682 101 .. 254 110.248 119.456 128.880 138.706 148.740 158.813
9'Y. 74.641 82.916 91.704 100.666 109.808 119.370 129. 108 139.028 149.354 159,956 170.331
8-8
1990 I 9'"Y I 1992 1993 1994 I~ 1996 1997 1998 1999 2000
F. ACCUI'I PRES WORTH OF ENERGY
1'11LLS/KWH
2,.. 1.330 1.419 1.507 1.~92 1.67~ 1 ,7~7 1.837 1.91~ 1.993 :2,0t,0 2.143
57. 1. 479 1.~79 l.t.77 1.771 1.862 1.9'51 2,037 2.121 2.:204 2,28~ 2,3t.3
77. 1,508 1.707 1.814 1.915 2.012 2.107 2.198 :2.28t. 2,373 2,4S7 2. ~:;>8
97. 1,72'5 1.843 1.958 2.067 2.170 2.271 2,368 2.461 2 .. 5~3 2.641 2,7~
POI.iE'< COST STUDY
INTERT!ED SY~fEM (15 CCfiMUN!T!ES) -TAZIMINA-LOW LOAD Alternate 9-A
t':J7Q !Of:3Q 1"81 1Q8~ 1"'83 1984 1-:)85 1"86 1?87 1"'88 J989
I. LOAD DEMAND
DEMAND -t<W '5.074 '5 .. 320 '5.'566 '5.8!2 6.058 6.304 6.9!0 7,! 78 7.446 7,714 7,982
ENERGY -MWH 20 .. 888 :23~856 :5,344 :::6.833 28. 322· 29.81! 31.300 32.748 34,1"'6 35.644 37.09:::
2-SOURCES -I<W
A. EXISTING DIESS:L
LOCATION OR UNIT 1 2~600 :: .. son :.600 :::.f:-,(:0 2.600 2.60() :.600 2.600 2.600 2-600 2.600
2 4, 145 4.!45 4-!45 4,145 4.145 4.145 4-14'5 4. 145 4,145 4-14'5 4,14'5
.3 830 330 830 8':<0 :330 830 8?0 8.30 830 :330 830
4
'5
6
7
:3
9
10
11
12
B. ADDITIONAL DIESEL
UNIT 1 2,.200 : .. 200 2~:2'00 2,:::!00 2<t200 2,200 2,::oo 2~200 ~~200 2.200
2
3
4
5
6
c. niSTING HYDRO
IJNIT 1
2
0. ADDITIONAL HYDRO
UNIT I ---1 ''· 000 18.000 !8.000 !8.000 IB.OOO
2
3
TOTAL CAPACITY n; ;."57'5 ¢~775 9,775 "'· 77'5 9, 77'5 ·o, 77'5 27.775 27.775 2?.775 27,77"5 ;;.7.7~.::,
LAROEST L•NIT 1.8'30 !-830 I ,:'l"JO l '830 1. 830 I 830 t9.5:o 19.520 1°-'S::CO 1 q. '5'2(1 t>::~~s~o
F! RM CAPAC tTY 5~74"5 7,<>45 7.04~ 7,Q4"5 7,<>4'5 7,'>45 :3. :'55 8.:'5'5 8:.255 ;.?:, .:;~.a:; '·2'5'5
SURPLUS OR ( DEF !CIT l -~1.; 671 . 1~..::'5 :: • ._;.t7Q 2. t 33 1.837 I .64! 1.34S t.07"7 80"' 541 ::7 3
NET HY[!Rtl CAPACITY -MWH ---76.1)80 76·080 76 .. 080 71, ~ t)8() .,,.,. i)8f'l
f!IE·3E:l GENERATtON -MWH ::0-88:3 .:: J. ·'·"· :-::. ;:44 26.-SJ'J ~:3., J2: ::·>, J3!1
9A
.1990 1991 1992 1993 1994 199'5 1996 1997 1<>9$ 1"'99 2000
1. LOAD DEMAND
OE!'IANO -KW 8·250 8.496 8.742 8.988 Q,234 9,480 9 .. 1'32 9,984 10.236 10.488 10.740
ENERGY -MloiH 38.541 39.824 41.! 17 42,405 43.693 44.892 46.270 47.'558 48.847 so. 13'5 '51.424
2. SOURCES -KW
A. EXISTING DIESEL
LOCATION OR UNIT 1 z.ooo 2.600 2·600 2.600 2.600 2.600 2.600 2.600 2.600 2.600 2.600
2 4.145 4.145 4, 14'5 4,145 4"'14!5 4.14'5 4.!4'5 4. 14'5 4, 14'5 4.14'5 4. 14'5
3 830 830 830 330 830 830 830 830 830 830 830
4
'5
6
7
8
9
10
11
12
B. ADDITIONAL DIESEL
LIN!T 1 2.:!00 :z. ;wo· 2.200 z,zoo 2~200 2,200 2.200 2 .. 200 :2?200 2.,:oo z.:oo
2 !.300 1.300 1·300 1.300 1.300 t. 300 1·300 1.300 I, 300 t. 300 1.300
3 ---1 >000 I .000 t.ooo 1.ooo 1.ooo 1 .ooo 1.ooo 1 ,ooo
4 ---------1 •• 1oo t. 100
'5
6
c. EXISTING HYDRO
IJNH 1
2
D. ADDITIONAL HYDRO
IJNIT 1 1a.ooo ta.ooo 18,000 ts.ooo lA,OOO 19.000 17:3., 1)00 18.000 19.000 18·000 18.000
2
3
TOTAL CAPACITY -KW 29.075 29.07'5 ~q.07S 30.07'5 30.07'5 30,075 30. 07'3 30.07'5 30.07'5 31 • I 7'5 31.17'5
LARGEST UNIT 19.'520 19.520 19·520 19.'520 19,520 1"'.'520 t<::> .. 520 1Q,'510 t-:)~5:20 19~~20 19,'520
FIRI'I CAPACITY 9.~5!\ 9,:l'S!\ 9, 5'55 10.55'5 10.'55'5 IQ, '555 !O."l'5'5 10.'55'5 10.5'55 11 ~ 65~ 11·6'5'5
Sl.IRPLUS OR < OEF I CIT J -!<W !.305 1 .0~9 $13 1. '567 1 '321 t. 07'5 !323 '571 319 1, 167 "'1'5
NET HYDRO CAPACITY -MWH 76,080 76.080 76.080 76.080 76 1"'1<!\0 76.080 7.L,OBO 76., OSt) 7,<,.080 71..-. .. 08() 76.080
DIESEL GENERATION -MWH
9-A
1">79 !980 1981 1">82 !98:" 1984 1"'8'5 1986 !987 1988 198"'
..:>. INVESTMENT cOSTS ($!000)
!979 DOLLARS
A. EXISTING DIESEL 5.86: 5.862 5.862 5~862 5.862 5.862 5.862 5.862 5.862 5.862 5?862
E<. ADDITIONAL DIESEL
UNIT 1 t. 914 I, 914 ), 914 I,<> !4 1. 914 1. 014 1. 914 1. 914 1· 914 1. 914
2
3
4
5
6
c. EXISTING HYDRQ
D. ADDITIONAL HYDRQ
UNIT 1 --50.820 50.820 50.820 50.820 50.820 -----
3
E.' TRANSMISSION PLANT ADDITIONS
liN IT I --4t975 4,975 4.975 4.975 4.975 4.975 4.975 4.975 4.975
2
F. MISCELLANEOLIS ADDITIONS
LINIT 1
2
TOTAL <S1000l
1979 DOLLARS 5.862 7.776 12.751 12.751 12.751 12.751 63.571 63.571 63.571 63.571 63.571
INFLATED VALUES 5.862 7.929 13.732 13.732 13.732 13.732 91.390 91.390 91.390 91.390 91.390
4. FIXED COST ($1000)
INFLATED VALUES
A. DEBT SERVICE
l-' EXISTING 238 238 238 238 238 238 238 238 238 238 238
2. ADDITIONS
SLIBTOTAL 21( ' ., -83 315 315 315 315 3.421 3.421 3.421 3.421 3.421
5"1. -126 480 480 480 480 5.153 5. 153 5.153 s, 1~-3 '5.153
77. -160 608 608 608 608 ~ .. 606 6.606 6.606 6.606 6.606
9"1. -196 745 745 745 745 8.094 8.094 8.094 8.094 8.094
B. INSURANCE 18 26 48 52 56 61 4!9 436 453 471 490
~~~
1979 191:10 1981 198~ 1983 1984 1985 1986 1987 1988 1989
TOTAL FIXED COST <S1000l
2'Y. ~6 347 601 605 609 614 4.078 4.095 4 .t 12 4.130 4.149
5% 256 390 766 770 774 779 5.810 '5.8~7 '5.1:144 5.862 5.881
n: 256 4~4 894 898 902 907 7.263 7.280 7.297 7.315 7.334
9% 256 460 1-031 1.0~ 1.039 1.044 8.751 8.768 8.78'5 8.803 8.822
5. PRODUCTION COST <S1000l
INFLATED VALUES
A. OPERATION AND MAINT
1. DIESEL 651 815 658 723 79'5 932 ~1 687 71'5 743 773
2. HYDRO ---- - -
90 95 101 105 111
B. FUEL AND LUBE OIL 1.69'5 2.130 2.126 2.474 2.873 3.327
-..\-'-'' TOTAL PRODUCTION COST <S1000l 2.346 2~94S 2.784 3.197 3.668 4y259 751 782 816 848 884
'~ ' . TOTAL ANNUAL COST <S1000l
2% 2 .. 602 3.292 3.385 3.802 4.277 4.873 4.829 4.877 4.928 4.978 '5.033
~~i.. 2,602 3.33'5 3.550 3.967 4.442 '5.038 6.'561 6.609 6.660 6.710 6.765
7% 2.602 3.369 3.678 4.09'5 4.570 5.166 8.014 8.062 e. 113 8.163 8.~18
9% 2.602 3.405 3.81'5 4.232 4.707 5.303 9.502 9.550 9.601 9.651 9,706
ENERGY REQUIREMENTS -MWH 20.888 23.856 25.344 26.833 28.322 29.811 31.300 32.748 34.196 ~.644 37,092
MILLS/KWH
2% 125 138 134 142 1'51 163 154 149 144 140 136
5% 125 140 140 148 157 169 210 202 195 188 182
7% 125 141 14'5 153 161 173 2'56 246 237 229 222
9% 12'5 143 151 158 166 178 304 292 281 271 262
c. PRESENT WORTH
ANNUAL COST <S1000)
2% 2.602 3.077 2.957 3.104 3.263 3.474 3.218 3.037 2.868 2.708 2.559
5% 2.602 3.117 3.101 3.238 3.389 3.592 4.372 4.116 3.876 3. 650 3.439
7% 2.602 3.149 3.213 3.343 3.486 3.683 5.340 5.021 4.722 4.440 4.178
9% 2.602 3.182 3.332 3.455 3.591 3.781 6.332 5.947 5.588 5.250 4.934
D. ACCUMUL. ANN. COST <S1000l
2% 2.602 5.894 9,279 13.081 17.358 22.231 27.060 31.937 36.865 41.843 46.876
5% 2.602 5.937 9,487 13.4'54 17.896 22.934 29.495 36. 104 42.764 49.474 56 .. 239
7% 2.602 5.971 9.649 13.744 18.314 23.480 31.494 39.556 47.669 '55.832 64.050
97. 2.602 6.007 9,822 14.0'54 18.761 24.064 33.566 43.116 52.717 62.368 72.074
E. ACCUMULATED PRESENT WORTH
ANNUAL COST <S1000l
2% 2.602 5.679 8.636 11.740 15.003 18.477 21.69'5 24.732 27.600 30.308 32.867
5% 2.602 5.719 8.820 12.058 15.447 19.039 23.411 27.527 31.403 35.0'53 38.492
7% 2.602 5.751 8.964 12.307 1'5.793 19.476 24.816 29.837 34.559 38.999 43.177
9% 2.602 '5.784 9.t 16 12.571 16. 162 19.943 26.275 32.222 37.810 43.060 47.994
9-A
!97Q 1980 1"81 t<>s:; J<>83 1984 1<>85 1986 !<>87 1988 1989
F • ACCUM PRES WORTH OF ENERGY
MILLS/KWH
2'l.. 1:25 254 371 487 602 718 821 914 qc;.s 1.074 1. 143
57. 1 :!~· 25b 378 49Q 61<> 730 879 1.005 1, I 18 1. 220 1' 313
7Y, 12~ ~~7 384 500 63:? 7'55 921:· 1.079 I, 217 1, 342 1.455
"7. 12'5 2~0 39! '520 647 774 977 I, !59 1 '323 I, 470 1.603
~A
'~ ~ '""::
1990 1991 1992 1993 1994 109'5 1996 1997 1<>98 1999 2000
3. INVES~NT COSTS <•1000)
1979 DOLLARS
A. EXISTING DIESEL ~>.862 '5.862 ~,BOZ '5.862 '!!:1.862 '5·862 '5.862 '5.862 '5.862 5~802 s,So2
B. ADDITIONAL DIESEL
UNIT 1 1.914 1. 914 1.914 1. 914 1, 914 1.914 1·914 1o914 1, 914 1, 914 1.914
2 1. 131 1.131 1. 131 1.131 1.131 1,131 1. 131 1.131 1, 131 1, 131 1. 131
3 ---870 870 870 870 870 870 870 870
4 --------9'57 9'57
5
b
C. EXISTING HYDRO
D. ADDITIONAL HYDRO
UNIT 1 '50.820 50,820 :;10.820 50.820 50.820 '50.820 50.820 50.8::!0 50.820 '50.820 '50.820
2
3
E. TRANS"ISSION PLANT ADDITIONS
UNIT 1 4.97'5 4.975 4.97:5 4.975 4.97'5 4.97:5 4.975 4.97'5 4.975 4.97'5 4.975
2
F. "ISCELLANEOUS ADDITIONS
UNIT 1
2
TOTAL ($1000)
1979 DOLLARS 64.702 64.702 64.702 65.'572 6'5.'572 6'5. '572 6'5.'572 6'5.'572 6'5. '572 66.'529 66.'529
INFLATED VALUES 93.493 93.493 93.493 9'5.312 9'5.312 9'5.312 9'5.312 9'5.312 9'5.312 97.844 97.844
4. FIXED COST ($10001
INFLATED VALUES
A. DEBT SERVICE
1. EXISTING 238 238 238 238 238 238 238 238 238 238 238
2. ADDITIONS
SUBTOTAL 2X 3.'505 3.'50'5 3.:50'5 3.'578 3.'578 3.'578 3.'578 3.'578 3.'578 3.679 3.679
5Y. '5.281 '5.281 '5.281 '5.392 '5.392 '5.392 '5.392 5.392 '5.392 '5.547 '5.'547
7X 6.768 6.768 6.768 6.908 6.908 6.908 6.908 6.908 6.908 7.104 7.104
9X 8.293 8.293 8.293 e. 465 8.46'5 8.46'5 8.46'5 9.46'5 a. 46'5 8.70'5 8.70'5
B. INSURANCE ':521 '542 '564 '598 622 647 673 700 728 777 808
9-A
19'90 1"91 !9<>: 1QQ3 !9<>4 I "'"''5 1"96 !997 !998 !9'<><> 2000
TOTAL FIXED COST ($1000)
2% 4.,264 4, ::eo:, 4.307 4.414 4.438 4.463 4.489 4.5!6 4.544 4.694 4,7?5
57. 6.040 6·061 6.083 6,228 6.252 6.277 6.303 6.330 6.3'58 6.562 6.~93
77. 79~27 7.'548 7.'570 7.744 7.768 7.7<>3 7.81" 7.846 7.874 8.11° a.tso
9'1, 0,05:2 <>.073 <;>,Q05 9,301 Q,325 <>.350 <>.376 <>,403 9.431 9.720 9.751
5. PRODUCTION COST ($1000)
INFLATED VALl1ES
A. OPERATION AND MAINT
1. DIESEL 804 836 86" 904 940 979 !.017 !.058 1.100 I, 144 1. 190
2. HYDRO 117 124 131 136 144 152 160 169 176 185 195
B. FUEL AND LUBE OIL
TOTAL PRODUCTION COST ($1000> 921 960 1.ooo 1.040 !. 084 1' l30 I, 177 1. 227 1.276 1.329 1.385
TOTAL ANNUAL COST ($1000)
2i. '5. 185 5.245 '5.307 !:i,454 5~522 !:·,593 '5.666 '5.743 5,820 6.023 6.110
5% 6,961 7.021 7.083 7.268 7.336 7.407 7.480 7.557 7.634 7.891 7.978
7% 8,441?-8.'508 8.570 8.7$4 s,ss2 8~923 8.996 9.073 9.150 9,448 9.53'5
9% 9.973 10.033 10.095 10.341 10.40<> 10-480 10.'5'53 10.630 10.707 11.049 11.!36
ENERGY REQUIREMENTS MWH 38.541 39.824 4!.117 42.405 43.693 44,B92 46.270 47.58$ 48.847 so. 135 51.424
MILLS/KWH
2% 135 132 129 129 126 125 122 121 119 120 119
:57. 181 176 172 171 168 165 162 1:59 156 157 ISS n.: 219 214 208 207 203 199 194 191 187 188 185
9% 259 252 246 244 238 233 228 223 219 220 217
c. PRESENT WORTH
ANNliAL COST <$1000)
27. 2.463 2,329 2,202 2. 115 2.001 1.895 1. 794 1.699 1.609 1, 5'56 1· 476
S% 3.307 3.117 2.,939 2.819 2.659 2.509 2.368 2.236 2, Ill 2.039 1 't 927
77. 4.014 3.771'! 3.556 3.407 3.208 3.023 2.1'!48 2.694 2.!530 2,442 2.303
9% 4,739 4.455 4,189 4.010 3.773 3.!550 3.341 3.145 2.961 2.855 2.68">
[), ACCUMUL. ANN. COST ($1000)
2Y. 52.061 57.306 62.613 68.067 73.589 79,182 94.849 90.591 96.411 102.434 109.544
5Y. 63.200 70.221 77.304 1'!4.572 91,908 99.315 106.795 114.352 121,996 129.977 137.955
77. 72.499 81.006 99.576 <>8.360 107.212 116.135 125. 131 134.204 143.354 152.802 162.337
97. 92.047 92.080 102. 175 112.!516 122.925 133.405 143.958 154.588 165.295 176.344 197.480
E. ACCUMULATED PRESENT WORTH
ANNUAL COST ($1000>
27. 35.330 37,659 39,961 41 '976 43.977 45.872 47.666 49.365 50,974 52.530 54.006
57. 41.799 44.916 47.955 50.674 53.333 55.842 58.210 60.446 62.5'57 64.596 66.523
77. 47.!91 50.969 '54.525 57,932 61. !40 64.163 67.011 69.695 721'225 74.667 76.970
9';: 52,732 57.187 61.376 65.386 69.159 72.709 76.050 79.195 82. 1'56 95.011 87.700
9-A
1990 1991 1992 1993 1994 1995 1996 1997 1998 19<>0 2000
F. ACCUI1 PRES WORTH OF ENERGY
11ILLS/KWH
27. 1.207 1. 266 1.320 1.370 1.416 1.458 1.497 1.533 1.566 1.597 1.626
57. 1,399 1. 477 1.548 1. 614 1. 675 1.731 1. 782 1.829 1.872 1. 913 1.950
77. 1.559 1. 654 1. 740 1.820 1.894 1.961 2.022 2.079 2. 131 2.180 2.2~
97. 1.726 1· 838 1.940 2.035 2.121 2.200 2 .. 272 2.338 2.399 2.456 2.508
PQL.IER COST STUDY
INTERTIED SYSTEM (15 COMMUNITIES) -TAZIMINA -HIGH LOAD Alternate 98
1?79 IOI;lO 1Q81 198':: 1"83 !984 1?8'5 1<::;86 I087 1988 1989
I. LOAD DEMAND
DEMAND -~1.1 '5.074 5. 70f! 6.476 7.252 8.028 8.804 10.080 10.886 11.692 12~498 13.304
ENERGY -ML.IH 20.888 27.621 31.'596 3:5.'572 39.547 43.522 47.498 5!.473 5'5.448 '59,424 63.399
2. SOURCES -1<'1.1
A. EXISTING DIESEL
LOCATION OR UNIT I 2.bOO 2.600 2~600 2.600 2.600 2.600 2.600 2.600 2,600 2.600 2,600
2 4. 14'5 4. 14'5 4, 14'5 4. 14'5 4. 145 4, 14'5 4. 14'5 4. 14'5 4.145 4.145 4, 14'5
3 330 830 :33(l :3:30 830 830 830 830 830 830 830
4
5
6
7
8
9
10'
II
12
B. ADDITIONAL DIESEL
LIN IT I -3.400 3.400 3.400 3.400 3.400 3.400 3.400 3.400 3.400 3.400
2 - -
-3,"200 3.200 3.200 3,200 3 .. 200 3.200 3.200
3 -- - - - -- -3.000 3.000 3.000
4
5
6
c. EXISTING HYDRO
LIN IT I
2
0. ADDITIONAL HYDRO
UNIT I -U3, 000 t8.(1r)0 t:3 .. 000 18-000 1s.oon
2
3
TOTAL CAPACITY -KL.I 7.575 10,975 10.97'5 10.975 14. 17'5 14.175 32.17'5 32. 17'5 35. 175 35. 17'5 35.175
LARGEST UNIT 1.830 I ,830 1.830 1.8?0 1.830 1.830 19-'520 t0.'5.20 1".520 1~.5:'0 20.020
FIRM CAPACITY 5.74'5 9, 14'5 9, 14'5 9,145 12.345 12,345 L'.b55 1 ,:, .~"55 15.65'5 15.6'55 15. 1'55
SURPLUS QR <DEFICIT> -KL.I 671 3.445 2.669 1,893 4.317 3.541 z~~75 1' 76? 3.,963 3.157 I. 8'51
NET HYDRO CAPACITY -MWH --76.080 76.080 76.080 76.080 7.~. 080
DIESEL GEN~RATION -~L.IH 20.888 ·27.621 Jl.'59.<, 3'5.-=i7: )9,547 4.3. 522
98
19?0 1 'X11 1992 199"3 !994 1~ 1'X16 1997 1991:! 1999 2000
1 • LOAD OEI'IAND
DEI'IAND -I<W 14.110 1!5.238 16.376 11.~14 18·6~2 19.790 20.924 22.0'38 23. 192 24· 326 2~,460
ENERGY -1'1WH 67.37~ 74,049 80.723 $7.398 <>4,072 100.747 107.421 114.096 120.771 127.446 134. 121
2. SOURCES -KW
A. EKISTINO DIESEL
LOCATION Oft UNIT 1 2.600 2.600 2.600 2.600 2.600 2.600 2.600 2.600 2.600 2.600 2.600
2 4.145 4.14~ 4.145 4.145 4.14~ 4.145 4.14'3 4.145 4.145 4.14'5 4.!4'3.
3 830 830 830 830 830 830 830 830 830 830 830
4
5
6
7
a
9
10
11
12
a. ADDITIONAL DIESEL
UNIT 1 3.400 3.400 3.400 "3.400 3.400 3.400 3.400 3.4()0 3.400 3.400 3.400
2 3.200 3.200 3.200 3.200 3.200 :).200 3.200 3.200 3.200 3.200 3,200
3 3.000 3.000 3,0()0 3.000 3.000 3.000 3.000 3.000 3.000 3.000 3.000
4 2.200 2.200 2.200 2.200 2.200 2.200 2.200 2.200 2.200 2.200 2.200
5
6
C~ EXISTING HYDRO
l.INIT I
2
D. ADDITIONAL HYDRO
LINIT I 18.000 ta.ooo ta.ooo ta.ooo 18,000 1e.ooo 18.000 18.000 18.000 18.ooo 18.000
2 --18.000 ta.ooo 18.000 te.ooo 1a.ooo 1e.ooo 18.000 !8.000 18.000
3
TOTAL CAPACITY -KW 37.375 37.375 '55.37'5 5'5.37'5 :5'5.37'5 ss. ·ps '55. 37'5 '5'5.375 '55.:37'5 '55.375 55. 37'5·
LARGEST LIN IT 20.020 20,020 II, ~20 II, 520 II .520 11,520 11 '520 12, ()20 12,020 12.020 12.020
FIRM CAPACITY 17.3'55 17·3'55 43.85'5 43.855 43.855 4'3,85~ 43. :35'5 43.3'55 43. :35'5 43.3'55 43.355
~JRPLUS OR !DEFICIT> -I<W 3.245 2tl17 27.479 26.341 25.:;!03 24.06'5 22,931 21~297 :;:o. 163 19.029 17.89'5
NET HYDRO CAPACITY -MWH 76.080 76.080 107.360 107.360 107.360 107.360 107.:360 107.360 107.360 107.360 107.360
DIESEL GENEKATION -MWH -----61 6.736 t3.411 20.086 2t .• 76·,
98
t~!~ tq80 [08\ 1 0:~-:? 1 '~81 t 9:<>4 1°8S !986 !"'B7 1999 1989
3a INVESTMENT cOSTS <fo!OO(l
!'>7"> OfJLLARS
A. EX !STING DIESEL <;, -:., 8&2 5~862 5.862 '5.862 '5 ,.").:,2 5.862 '5·'162 '5,.862 5.862 '5·862
Et. ADDITIONAL DIESEL
UNIT 1 2.Q'5:3 :;,">'58 :?,'058 :.'4"5::t 2,'?5:3 :;,-::;58 2 .. 958 2.,?'58 :."58 ::.~SG
::: -::,784 .2~784 ;;:.784 ::.784 :,784 2.734 :::.784
::: .. :,to 2.610 '2·610
4
'5
t.
c. EXISTING HYDRO
D. ADDITIONAL HYDRO
UNIT I ---50~8:0 ~0,820 '50. :320 50,820 '50.820
2
3
E. TRANSH!SSION PLANT ADDITIONS
UNIT 1 --4,Q7'5 4.,?75 4,975 4.975 4,97'5 4,<>75 4,97'5 4.975 4."7'5
:: ---
F. HIS~ELLANEOUS ADDITIONS
UNIT 1
2
TOTAL ( St()(Hl)
!97" DOLLARS 5~B~: 8,820 13.7"'5 13.7'>'5 16.579 16.57"' 67.3°() . .:,7. 3'~9 70,009 70.009 70.009
INFLATED VALI.IES 5~862 '>,(>57 14.860 !4.861) t·~· 648 18.648 0 6 .. 3t""6 ·~c., :;(t6 100,62:0 lCH), 6ZO IOO,b:::o
4. FIXED C'QST (SI000)
INFLATED VALUES
A. DEBT <;ERV!CE
1. EXISTING 238 ~38 238 ::::38 233 238 ~?~3 238 ;;:3,3 2:38
... ADDITIONS
SUBTOTAL :i' .. 128 360 360 512 512 3.618 3.618 3?7~1 3.7"'1 3,.7CJt
'5'1. -I "'5 '549 '34Q 780 7'3<1 '5.4'33 '5,4'53 ~.716 '5.7!6 ~.716
7'1. ';247 6q5 69'5 '""3 0 88 6 ~ Q~36 .~._";')$6 ...., . 31 Q 7, 31 Q 7 ~ :3t·:)
·::.·~ 30? 351 851 1.::"0'-' 1. ::oq 8·'55:? ."5*38 . •'),~ ... 6 '3, '>~6 ~' ·::)~6
B. INSURANCE 18 :2"' ~~ '56 "'6 441 .l"i9 4-:><1 ~.~~ C)4(1
91
1979 198<) 1981 tQS2 1'>83 1?'34 1"'8'5 1Q81.> . 19$7 1988 1989
TOTAL FIXED CO'ST ($!000)
2~ 2'56 39'5 1.>'50 6'54 826 832 4 .. 297 4.31'5 4.'528 4.'549 4,'569
'5"/.. 2:16 462 83-;l 843 1,094 t.too 6.132 6· 1 '50 6.4'53 (: .. 473 6.494
n: 256 '514 985 989 1.302 1.308 7,66'5 7.683 8.0'56 8.071:> 8.097
9')( 256 '569 1, 141 1.14'5 1, '523 1, '529 9.237 9.2'5'5 9.703 9.723 Q,744
'5. PRODUCTION COST ($1000)
INFLATED VALUES
A. OPERATION AND MAINT
1. DIESEL 651 842 0 40 1.0'50 898 1, 010 '599 623 71'5 743 773
2. HYDRO ---104 113 121 131 13Q
B. FUEL AND LUBE OIL 1. 6'>'5 2,460 2.650 ·3~ ';;Bt 4,012 4.8'58
TOTAL PRODUCTION COST ($1000! 2.346 3. 3l18 3.'590 4.331 4.910 '5.868 703 736 836 874 912
TOTAL ANNliAL COST <S1000l
2% 2.602 3.703 4.240 4,98'5 '5.736 6.700 '5.000 '5.0'51 '5.364 ~.422 '5.481
'SY. 2.602 3.770 4,429 '5.174 6.004 6.968 6.83'5 6.886 7,289 7.347 7.406
7Y. 2.602 3.922 4.'57'5 '5.320 6.212 7.176 9.368 8.419 8.892 8.9'50 -Q,I)09
9Y. 2.602 3.877 4.731 '5.476 6.433 7.397 9.940 9.991 10.'539 10.'597 10.6:56
ENERGY REQUIREMENTS -~ 2o.asa 27.621 31, '596 3'5.'572 39.'547 43.'522 47.498 '51. 4,73 '5'5.448 '59.424 63.399
!'I ILLS/KWH
:x 1·2'5 1':34 134 140 14'5 1'54 10'5 98 97 91 86
'5% 12'5 136 140 14'5 152 160 144 134 131 124 117
7% 12'5 138 14'5 1'50 1'57 16'5 176 164 160 1'51 142
9% 125 140 I 'SO 1'54 163 170 209 t<>4 190 178 168
c. PRESENT WORTH
ANNUAL COST ($1(11)(11
::x ~16()~ 3.461 1.703 4.069 4.';376 4.777 3,332 3. !46 3,122 2~·:::-49 2.786
5'4 2t602 J.'523 3.868 4,224 4.580 4.968 4.554 4.288 4"242 3.·~96 3.765
7% 2t602 3.'572 3,996 4,343 4.739 '5. 116 '5.'576 s.:::43 5. 17'5 4-869 4.'580
9'>: 2,e.o:: 3 .. 623 4. 132 4.470 4.<>o8 ~"::!74 ~-623 6,222 6. 134 s. 764 5.417
D. ACClii'IUL. ANN. C'OS'r <stOOO>
2X ~~602 6.30'5 10.'54'5 1'5.'530 21,266 ::7.966 .n.966 38.017 43.391 48.903 '54.284
5?: 2.602 6.372 10.801 1'5,97'5 21 t~7Q 28.947 3'5.782 42.668 49,9'57 '57.304 64.710
n: 2,6()2 6.424 t0.79Q 16.319 22,531 29.707 38.075 46.4Q4 :5:5.386 64.336 73.34'5
"'"t. 2.602 6.479 11.210 16.686 23>1 19 30.'516 40.4'56 '50.447 60,986 n..s::n ~z.:'3q
E. AU:I.II'ILILATEO PRESENT WORTH
ANNllll>W C'QS T ($11100)
~7.. :2',b02 6~0h3 9.766 !3. 83'5 18.211 2::!~..:)9$ :6.320 ::¢.466 '3~.'5€'8 3'5.'537 38.323
!o't. :,b02 6.1 ;:c; ·~. Q<03 14-217 18.797 23.70.5 ::3,317 31' l:::-07 36.849 40.S4~ 44-610
n; ~.60:2 6.174 10.170 14.'513 19~:252 24.368 ~0,044 J'5, 187 40~ 36: 4S.::Jo 4Q~8:10
"'% 2.6('1;::: 6.:::::'5 10.357 !4.827 19,7'35 2'5.00"" 31.632 37-8'54 4'~l ·:;)88 4Q.7S2 '5'5.!6°
98
1'>79 1 0'81) 1"81 1<>82 1°83 1""84 1 ':;185 1 •';1:36 1"87 1988 1989
F. ACC!JM p,;·ES ;..iORTI-' QF ENER(iY
MILLS/KWH
:!'%. 1~ 250 367 481 5°2 702 772 833 88° 938
5% 125 252 '374 4'~2 61):3 722 81'3 901 977 1.044 1 '
7"/. 12'5 254 381 503 623 741 858 060 1.053 t. 135 1.207
9"/. 12115 ::56 387 '513 637 7'58 8C>7 1 '018 !. 129 1 .. 226 1 • '31 1
911
1~ 1991 1992 1993 1994 199'5 1996 !'9'97 t<>9g 1999 ~1)00
:J. INVESTMENT COSTS !•10001
1979 DOLLARS
A. EXISTING DIESEL 5.862 ~,.862 tS,.862 5.862 ~t862 '3.962 ~.962 '5.962 '5.962 5.862 ~.,862
B. ADDITIONAL DIESEL
UNIT 1 2;9'58 2.<:>'58 2.9'59 2,9'58 2.9'59 2.9'59 2.~8 2.~~8 2.9'59 2.~9 2,9'59
2 2.784 2.784 2 .. 784 2.794 2.784 2.7!34 2.794 2.784 2.784 2.794 2.784
3 2.610 2.610 :z. 610 2.610 2.610 2,610 2.610 2.610 2.610 2;610 2.610 ... 1.914 1·914 I, 914 1,914 1, 914 1, 914 1.914 1, 914 1.914 1.914 1. 914
5 . --~.,929 '5,82Q ~~B:zq '3.829 5.829 5.829 5.829 '5.829 '5.829
6
C. EXISTING HVDRO
D. ADDITIONAL HVDRO
UNIT 1 50,920 '50.820 50.820 '50.820 '50.820 '50.920 50.820 ~0 .. 820 '50.820 50.820 50.820
2 --4'5.774 4'5,774 45.774 4'5.774 4'5.774 4'5.774 4'5.774 4'5.774 4'5.774
3
E. TRANS~ISSION PLANT ADDITIONS
IJI!CrT 1 4.97., 4.975 . 4.97'5 4 .• 97'5 4.97'5 4.97'5 4.97'5 4,975 4,975 4.975 4.97'5
2
F. MISCELLANEOUS ADDITIONS
UNIT 1
2
TOTAL !'11000)
1979 DOLLARS 71.923 71,92'3 123.'526 123.,~26 123.'526 123·, 526 123, ~2.6 123.'526 123.'526 123.'526. 123.526
INFLATED VALUES 104.179 104.178 207.94'5 207,94'5 207,94'5 207.94'5 207.94'5 207,94'5 207.94'5 207,94'5 207.945
4. FIXED COST <'11000>
INFLATED VALUES
A. OE9T SERVICE
1. EXISTING 238 238 238 238 2.38 238 23S 238 238 23S 238
2. ADDITIONS
SU9TOTAL 2X 3.933 3.933 a.os4 8.084 8.084 8.084 8.084 ,,,084 8.084 9.094 8.094
!5'1. '5.933 '5.933 12.187 12.187 12, 187 12. 187 1:' 187 12. 187 1:2,187 12.187 12. 187
7'1. 7.'594 7,594 1'5.609 1'5.608 15.608 15·608 1'5.608 1~.61)8 1'5.608 1'5.608 1'5.608
9X 9.303 9,~03 19.122 19,.12::2 19, 122 19. 122 19, 122 t9l 1:2~ 1q" 122 19. 122 tQ,t2:
B. INSURANCE '581 604 1 .2~4 1 '305 I· 357 1 , 41 1 1.468 1.526 1.";87 1.651 1.717
98
19'<0 !991 ! 9'>'2 199'3 t·~Q4 !'>9:5 1996 1"'97 1998 1999 2000
TOTAL FIXED COST ($!000)
:2Y.. 4.7'52 4.775 9.576 9~627 9,679 Q,733 9,7<>0 <>.:348 9.·~09 9.973 10.039
5% 6.7'52 6.77'5 !3.679 !3.730 !3,782 13.836 13.1393 !3. !4.012 !4.076 !4.142
7{. 8.4!3 8.436 !7' 100 17.!51 17.:!03 !7, 2'57 !7.314 17. 17.433 17.497 17.56:3
"'!. tO. 122 to. 145 20.614 20.665 20.717 20,771 20.828 .20.886 :20.,947 21.011 21 '077
'5. PRODUCTION COST lS1000l
INFLATED VALUES
A. OPERATJON AND MAINT
l. OlESEL 81)4 836 9'50 Q88 1.027 1 ' 1 '59 1' 20'5 I, 366 1' '53~ 1.716 1 '"'08 .., HYDRO 149 1b:? 177 1/:)2 209 ::?26 ::?4'5 2'54 :::!65 275 .C86
B. FUEL AND LLIBE OIL 14 1.602 3.385 '5.371 7,'588
TOTAL PRODUCTION COST ($10<)0) 9'53 Q~8 1' 127 I, 180 t. 236 1 '385 1.464 3.,222 5,18~ 7.:362 9.782
TOTAL ANNUAL COST (S\000)
21. '5.70'5 '5' 773 10.703 10.807 10.915 11.118 1 1 ';2'54 13.070 15.094 t7 •. :n:s 1°.821
'5% 7.70'5 7.773 14.806 14,910 1'5.018 15.221 15.3'57 !7. 173 ! 9, !97 Zl, 438 23,Q24
rr. 9.366 9.434 18.227 18.33! !8.439 18.642 18.778 20.594 22.618 24.859 27.34'5
9% ! 1 '075 11.143 21.741 21,845 21,9'53 22,156 22,292 24. 108 26.132 28.373 3o.s::.<>
ENERGY REQUIREMENTS -MWH 67.37'5 74.049 80.723 .87.399 94,072 too, 747 107.421 114.096 120.771 127-446 134.121
MlLLSIKWH
27. 8'5 79 133 124 116 110 10'5 115 125 136 148
57. 114 10'5 183 171 160 1'51 143 151 ' 159 168 178
7!. 139 127 226 210 !96 18'5 17'5 ISO 187 195 204
..;t~t. 164 !50 269 21150 233 220 208 211 216 223 230
c .. PRESENT WORTH
ANNUAL COST <S!OOOJ
2'1. 2.710 2.~63 4.441 4. !91 3,956 3.766 3-563 3.867 4.174 4.48!) 4,787
'5% 3.61,.1 3.4'51 6.!44 "5 .. 782 '5,443 5.1'56 4,862 5.081 5,308 5.'540 5.778
7"t. 4-4'50 4.189 7;'564 7,10"' 6-683 6.31'5 '5,945 6.093 6.2'54 "" 424 6.604
"'7. 5,262 4,'>48 9 .. Q22 i3~ 472 7,057 7.'505 7.0'57 7, 133 7-.22b 7 ~ T32 7.4'53
D. ACCLIMLIL, ANN. C'OST I $1000)
2Y. '59,989 .;.s. 762 76,465 87,272 ·~a. 187 109,30'5 120 .. ~59 133.,<,29 148.723 166.0'58 185.879
57. 72.41'5 80. 188 "4 ... 94 109,904 124,<:>22 140,143 155.500 172.673 19!.870 213.308 2'37~::232
n: 82.711 <>2.145 110.372 128. 703 147.142 165.784 184.562 205. 1'56 227.774 2~:2.633 279.978
0"1, 93,314 104,457 126.!98 148.043 169tQOQ 1 <>2, 152 2!4.444 238~'5S2 264.684 293,057 323t 0 16
E. ACCUMULATED PRESENT WORTH
ANNUAL COST ($!0()1))
!:'%. 41.033 43.5'>6 48.037 '52t22$ '56·1''14 59,q50 63.'513 67.380 71.'554 76.034 :3<),:321
'5% 48.271 '51. 7'22 '57.866 ,<,3.648 60. t)91 74,247 7<>. 10"' 84. !90 89.499 95.038 100.811!>
7"1. c;4,~60 '58.44"' 6b.OI3 73. t:~ 7o,::w"i 86. 120 ':;t;2'~f)65 '>8.!58 104.412 110,836 117.440
~"!.. 60.431 6'5.379 74,401 82.873 <:>o~s:to ¢8~ 3:5~ 10'5. '3"'2 1 t:.::. ~::s 11'.~. 751 1'27, t)83 !J4,536
98
1990 1991 1992 1993 19'94 19'95 1'996 1997 1998 19'9'9 2000
F. ACC~ PRES WORTH OF ENERGY
1'1ILLSfl(,!oiH
2't 1.022 1.057 1. 112 1.160 1.202 1.239 1. 272 1.306 1.341 1. 376 1. 412
'5't 1.157 1.204 1.290 1. 346 1.404 1. 455 1.500 1. 54'5 1. '589 1.-!>32 1. 67'5
7X 1.273 1-329 1.423 1. 504 1.575 1.638 1.693 !.746 t. 7'98 \.848 1.897
97. !.399 1.456 1.568 !.665 1. 749 1.824 !.890 !.952 2.012 2.070 2.126
PDt.<ER COST 3TUOY
INTERTIEO SYST~~ (15 COMMUNITIES) -ELVA AHO TAZIMINA · LOW LOAD Alternate 10-A
197'4 1 ~t'() t':>.g l t ·~::::::: 1 "'"'::: t<"1 84 t·::-,::::5 1 '?::~& 1 '?:37 1 "'3'3 1~8"1
1. LOAD DEMAND
DEMAND -n4 5,074 5.6?5 ~., 8'-710 1,, !4'5 h.400 !;., 6":,'5 ~.9tl) 7,178 7. 44co 7,714 7~")82
ENERGY MWH .2:0.888 23.856 2'5. 344 :::.9.833 23.322 2.;,, 81 I 31. 3(10 ·~2, 748 ?4. 196 2!5. 644 37.0<>:
~ SOURCES -!<W
'1. EX I STING 0 I ESEL
LOCATION OR l.lNIT 1 2./:.t)O :;.600 2~6041 ::. ~.t)O 2 ~ t.oo ::.bOO 2· ~.oo :2~600 2.600 2,600 2.600
:: 4' 14'5 4. 145 4. !4'5 4, 14'5 4, 14c, 4. 14':· 4.145 4, 145 4. 145 4.14'5 4.!4'5
3 8~0 :330 :?'30 8:30 :3":-!:0 :3?(l ;?30 8.30 830 '330 830
4
5
6
7
:3
Q
10
I 1
12
8. ADDITIONAL DIESEL
li'IIT 1 -2,200 2.200 2,200 2,200 2.200 2,200 2.200 2,:oo ~l::oo 2.200
2 ----1.100 1. 100 1, 1 01) 1, 100 1, 100 !. 100
3
4
5
6
c .. EXISTING HYDRO
I)N!T 1
2
D. ADDITIONAL HYDRO
UNIT 1 1 '500 1 '':·00 1 ~ «'500 t t 500 1. 500 1.500 1-'500
2 18~ (H)O 1:3, OOQ 18.000 1:3,000 18.000
3
TOTAL CAPACITY -!<W 7,57'5 9~775 q. 77'5 ·?, 775 11, ~75 L::. 375 '"· 37'5 30~375 10,375 30.375 30.375
LARGEST UNIT 1, 8'?0 1.830 1.:330 I. :330 2.,3:30 ;::, 330 P.s:::o 1'7,520 1¢.520 19,520 :.:o.o:o
F!RI'I CAPACITY '5.74'5 7,"4'5 7,04~ 7."'45 8.94'5 10.045 10~355 10.855 10~855 10,85"5 l('l, 35"5
SURPLUS OR ( OEF IC I Tl leW 671 27310 2.055 1.soo 2.,S45 3,390 3,·~45 3.677. '3. 4(FJ 3. 141 .2~373
J'lET HYDRO CAPAC TTY -Ht.JH ----:~. 0?'0 ~3" 070 :0,4., 1'50 :34. !'50 :~4. 1~0 :34.t5n '":4 1~·'-3
OIE'3EL GF.:NERATI•)N -MI>IH ::o.s:::f9 2'3.85t~ .:5.344 26.:333 ,:o,. ::52 .::tt74l
lOA
1990 1991 1992 1993 1994 19<>'5 1996 1997 1998 1999 2000
1. LOAD OEI'!AND
OEMND -KW a.::so 8.496 a.742 8.988 9,234 <>.480 9.,732 9,<il84 10,236 10.488 10.740
ENERGY -I'!WH 38.541 39.324 41.117 42.40!S 43.693 44,892 46.270 47.'5SS 48.847 '50.13!5 '51.424
2. SOURCES -KW
A. EXISTING DIESEL
LOCATION OR UNIT 1 2.600 2.600 2.600 2·600 2.600 2,600 2.600 2.,600 2.600 2.600 2.,6.00
2 4.t45 4.145 4.145 4.145 4.t4S 4.14S 4. 14'5 4.145 4,145 4.145 4.145
3 830 830 830 930 830 830 830 830 830 830 830
4
5
6
7
8
9
10
11
12
B. ADDITIONAL DIESEL
UNIT 1 2,200 2,200 2.200 2t200 2,200 :2 .. 200 2~200 2 .. 200 2,200 2 .. 200 2,::oo
2 t.too 1. too 1. 100 1.100 1.100 1.100 1. 100 1· 100 1.100 1' 100 1. tOO
3 1·300 t.300 1.300 t. 300 t' 300 I, 300 1.300 1.300 1.300 1. 300 1.300
4 ---1.ooo t .ooo t .ooo 1.ooo t.ooo 1.ooo 1.000 1 .ooo
5 ---------1.100 1' 100
6
C. EXISTING HYDRO
UNIT 1
2
D. ADDITIONAL HYDRO
UNIT 1 1 ''500 1.soo 1.soo 1.500 I ,500 ! .soo 1.500 1.soo 1.soo I ,soo 1.soo
2 18.000 18.000 18.000 18.000 18.000 !8.000 18.000 18.000 18.000 18.000 18.000
3
TOTAL CAPACITY -KW 31.67'5 31.675 31.675 32·675 3~ ... 67'5 3:!,67'5 32.67'5 32.675 32.<>7'5 33.775 33.775
LARCEST IJNIT 20~020 :20,020 20.020 20~020 ::o~520 20 .. ~20 20¥520 2! .020 21.020 21.020 21 .. 020
FIRI'! CAPAC !TV 11.65'5 11.655 1!.655 12.655 ! :. ! 5'3 12. 15!5 12.1'5'5 1 I , 6'55 11. 65'5 12 .. 755 12.7'55
SJJRPLUS OR (0EFICITl -I<W '3.40'5 '3.1!59 2.913 3.oe7 :;.Q2t 2.675 .2.4'23 1. 671 1' 419 2 .. 267 2.01"5
NET HYDRO CAPACITY -I'!WH 84.150 84.150 84. 1'50 84. 150 84.150 R4, 150 84. 1~0 84.150 84.150 8'!.150 84. 1 so
DIESEl. i>ENF.:RATION -I"'WH
10-A.
1070 1 OE-:('1 1981 198::' 1983 )984 19~:5 1986 1987 1988 1989
?. I NVESTHENT COST~. <S100(1)
1 <>7''> DOLLARS
A. EXISTINC· DIESEL ~ .. :::~ ::_· ':·· 86~ ":·-~:6: -: •• 86:' 5.86:' 5. st.:· 5,8f.:..2: 5.86-2 5.86::' s.et-~ 5.862
B. ADDITIONAL DIESEL
UNIT 1 1• 014 1. 014 1 '"14 1. 014 l '914 l '9!4 I, 9!4 1.914 I ,914 1.914
::' -?~7 957 957 957 9 57 957
'?
4
_,
6
c. EXISTING HYDRO
D. ADDITIONAL HYDRO
UNIT I 1:2.0 40 12.94(1 12.940 1:2,940 12,940 12,940 1:2.940
-, - -
3 50.820 50,820 50,8:?0 50.820 ~·0.82(1
E. TRANSMISSION PLANT ADDITIONS
UNIT I 4,975 4, CJ7~· 4,CI75 4.975 4. 97":· 1),975 4,075 4. C'J7'5 4,975
::'
F. HISCELLANEOU3 ADDITIONS
UNIT I
2
TOTAL ($11)1)1))
I 979 DOLLAR~: 5.8&2 7.776 12.751 12,751 25.691 26. 64~: 77.468 77.468 77.468 77.468 77.468
INFLATED VALUES 5,862 7.929 13.732 13.732 81.337 32. 74:;: 110.401 110.401 110.401 110,401 110.401
4. FIXED COST ($1000)
INFLATED VALUES
A. DEBT SERVICE
I. EXISTING 238 238 2:<8 238 238 238 238 238 238 ~"JoC• 238
2. ADDITIONS
SUBTOTAL 21.. -83 ::I '5 315 1.01"' 1.07'5 4,181 4.181 4,181 4,181 4.181
5% 12t-4f:::(l 480 1,539 1.62'5 6,298 e .. 2Q8 6.29<: 6,:?98 6.298
7% It-O 60::: 6(1~: 1.96:0: 2.077 ~:. 075 8.075 8.075 :::,075 8.075
9% 19t. 74'5 74'5 2.411 :-.544 ?.£:93 9.893 9.8~)3 9,E:9:: 9,893
19. INSURANCE 18 26 48 ~--...~ 128 144 506 526 547 56Q 592
W-A
19700 1980 1981 1982 1993 1984 1985 )98t· 1Q87 1~$ lOS'>
TOTAL FIXED COST ($1000>
2/. 2'56 847 601 605 1.~ 1.4!57 4.925 4.945 4.96t· 4.9Et8 5, Oil
!5l(. Z56 3<:)() 766 770 },905 2.007 7.042 7.%2 7.083 7.1('1'5 7.12€'
7"1. 256 424 894 SQ8 2 .. 334 2.459 80:319 8:.83Q 8.860 s .. ss2 s. 9('1'5
9':(. 2~6 460 1 • 031 •• 03~ :;>.777 2.926 10.637 10.657 10.678 10.700 10.728
5. PRODUCTION COST ($1000)
INI"LATED VALUES
A. OPERATION AND KAINT
1. DIESEL 651 815 658 723 720 851 661 687 715 743 778
2. HYDRO --7 7 90 95 101 105 1 11
F. FUEL AND LUBE OIL 1.695 2.130 2.126 :;:.474 2 .. 055 Z.427
TOTAL PRODlCTION COST ($1000) z,346 2 .. 945 2,.784 3.197 2.782 8.285 751 782 Sl6 848 884
TOTAL ANNUAL COST ($10001
2'%. 2.602 3.292 3~385 3.8(12 4.167 4.742 5.676 5.7':::.7 5.782 5?836 ~;~ f195
57. 2-.602 3 .. 335 3.550 3,91;..7 4.687 ~., :292 7 .. 79::-{ 7.844 7.89"' 7,953 8.012
7'1. 2 .. 602 3,3C,9 3./:..78 4.095 '5.116 5.744 9,'570 ·=-t~ 6:21 ">,67t. <:1,730 9.789
97. 2 .. 602 3.40'5 3.815 4 .. 232 5,5S9 6.211 11·3~}8 11.4:C" 11. 494 11.548 11 • 607
ENERGY REQUIREMENTS MWH 20.888 23.856 25.344 2C ... 833 .28 .. 322 29.811 31,300 32~748 34. 1 <>t. 35.644 37,092
MILLS/KWH
2Y. 125 138 134 142 147 159 181 17~· 169 164 159
57. 125 140 140 148 165 178 249 240 231 223 216
77. 125 141 145 153 181 193 306 294 293 273 264
97. 125 143 151 158 196 208 364 349 336 324 313
c. PRESENT WORTH
ANNUAL COST ($1000)
2'1. 2.602 3.077 2.957 3.104 3.179 3.381 3.782 3.!566 3,365 3.174 2.997
5'1. 2.602 3.117 3. 101 3.238 3.576 3.773 s, 193 4.885 4.597 4,326 4,073
77. 2.602 3.149 3.213 3.34~: 3,903 4.09~· 6.377 5.991 5.632 5.292 4,976
9".1. 2~602 3,182 3.332 3.4'55 4 .. 241 4.428 7.588 7, 124 6.690 6.281 5.900
[), ACCUMUL. ANN. COST ($1000)
2X 2.602 5.994 9.279 13.081 17.248 21.990 27. 6~·~· 33,393 39.175 45.011 50.906
57.. 2.602 5.937 9,487 13.4~·4 18. 141 23.433 31~226 39.070 46.969 54.922 62,934
7% 2.602 5.971 9.64<) 13.744 18. 8~.o 24.604 34. 174 43 .. 79'5 53,471 63.201 72.990
9'1. 2.602 6.007 9.822 14.054 19,613 25,824 37.212 48.651 60.14"'· 7!.693 S3, 30(1
E. ACCUMULATED PRESENT WORTH
ANNIJAL COST ($1000)
2'Z 2.602 5.679 9,636 11.740 14.919 18.300 22.082 2'5.648 29.013 32.187 35.184
5% 2.602 5.719 8.820 12.058 J5,634 19.407 24.600 29.485 34,082 38.408 42.481
7% 2 .. 602 ~,751 8,964 12.307 H: .. 210 20't30S 2b,6S2 32.673 3B't305 43.597 48.573
9% 2.602 5.784 9. 116 12.571 16.812 21.240 28.828 35.952 42 .. 642 48.923 54.823
c
(/J
()
o r~ \(< c (' ~ ( ~ <<' if• """M cr ....J
(,..l (fJ o,
(i"J -0:.·....;
tl; (f. 0 v
( < ( l 1.1·
-i(i (•>-
l"->f'.f'.W
;-~· ~ ~ ;'!
('.c, I(J I'-V
10-A
1990 1991 1992 1<>"''::' 1<><>4 199'5 1"'"'6 1997 J<>9S 19'X> 2000
3. INVESTI"'ENT COSTS !S1000l
1979 DOl.LARS
A. EXISTING DIESEL 5.SC·2 5.962 5,862 '5.$62 5.8~2 :;. t%2' 5, Sl·2 5.862 5.962' s.a62 5.Sb2
B. ADDITIONAL DIESEL
LIN IT 1 1.914 1-914 1. 914 J, 914 1. 914 1. 914 1.914 1.914 1.914 I· 914 1.914
::? 957 957 957 957 957 957 957 957 957 957 957
3 t. 131 1. 131 1.131 1· 131 1. 131 1. 131 1· 131 1. 131 1, 131 1, 131 1. 131
4 ---870 970 870 870 870 870 870 870
5 --------957 957
6
C. EXISTING HYDRO
o. ADDITIONAL HYDRO
UNIT 1 12.940 t=.940 12t940 12.940 12.940 12,<:>4() 12t940 12.940 12.0 40 12,940 12.940
2 ---------
3 so.szo 50.92'0 !·0 .. 820 -so.ezo 50.(;20 50.820 50.820 50~820 ~·O.S20 50.320 50.820
E. TRANSMISSION PLANT ADDITIONS
UNIT 1 4.975 4.975 4,975 4,975 4.97'5 4,975 4."'75 4,<>75 4.975 4.975 4.975
2
F. MISCELLANEOUS ADDITIONS
UNITt
2
TOTAL <•1000)
1979 DOLLARS 76.599 79.599 78.599 79.469 79.469 79,4~.9 79.469 79.469 79,469 80.426 80.426
INFLATED VALUES 1!2. 504 112.504 112.504 114,323 114.323 114.323 114.323 114.323 114.323 116· 955 116.955
4. FIXED COST !S1000l
INFLATED VALUES
A. DEBT SERVICE
1. EXISTING 23E: 238 238 238 238 23(: 238 239 238 238 238
2. ADDITIONS
SLIBTOTAL 2'-' 4.265 4.26'5 4.2l·S 4.338 4.838 4,338 4.338 4.339 4~339 4.439 4.439
57. 6.426 6.426 ~.,426 6.~37 6.5-37 0,537 6.537 6 .. 537 6,5~7 6.692 6.692
77. 9.237 8.237 8 .. 237 8.377 9.377 8.377 l:h377 8.377 8.377 8.573 8.573
97. 10.092 10.092 10.092 10.264 10.264 10.264 10·264 1C.264 10.264 10.504 10.504
B. INSURANCE 627 653 679 717 74~. 776 807 839 973 928 96!5
TOTAL FIXED COST <~1000)
:::%
~·f..
Tl.
9'7.
5. PRODUCT 1 ON COST a 1 000 l
INFLATED VALUES
A. OPERATION AND MAINT
!. Dl ESEL z. HYDRO
B. FUEL AND LUBE OIL
TOTAL. PRODUCTION COST <$10001
TOTAL ANNUAL COST <~1000)
::r.
57.
7'l.
9'l.
ENERGY REQUIREMENT~: -MWH
MILLS/KWH
Z'Z
S%
n:
9'l.
C. PRESENT WORTH
ANNUAL COST ($10001
Z'X
5%
7'7.
9%
D. ACCUMUL. ANN. COST ($10001
2Z
5%
7%
9%
E. ACCUMULATED PRESENT WORTH
ANNIJAL COST ( U 000 J
2%
5%
7%
9%
lQQ(l
5, 130
7,Z?I
9, 10::C
10.'?'~7
804
117
921
1: .. 051
8,?12
10~023
11,878
38,541
157
213
260
308
2~ 875
3,901
4~762
5~ 643
'5&. 9'57
71' 14~
83,013
95,178
38.059
46.,382
53. 33~·
6(1,4~6
)9·~1
51 15~,
7,317
9.12:::
10, 9~::;:
83~.
124
960
6.111:·
8,";:77
1010t::8
11, 943
39,8Z4
154
208
253
300
2, 71t.
3.,6-75
4.479
5.303
63,073
79,423
93.101
107,121
40.775
50,057
57.,814
6:::;.769
19°'2
~·.lB.:::
7.342>
o, 154
11. OCr~·
8t:O
1:::1
1 'OO(l
6,1$2
8.343
I o, I ':·4
12.000
41,! 17
15(>
203
247
292
2,.565
3.462
4.214
4,9$3
69,255
87.766
103.255
119.!30
43.340
53,519
62, 02E:
70,752
t<.to:;
5,2?:::..:
7,40:::
tO. 3::::
11,:10
9(>4
13<'
I ,040
6.333
t:~ s~::?
10.:<72
12t759
4:.?,40~·
149
201
245
289
2.456
3.309
4,022
4.754
75~588
96,298
II~:, 627
131,389
45.791:-
56.828
~.(., 0!·0
75~ 50~.
)094
5.32~
7,5.:2'1
9, 3<·1
11, ?4c'
0'40
144
1.084
6.406
E:, 60"i
10,.445
12.33::?
43,693
147
197
239
282
2.322
3. 119
3t7S6
4.470
81.994
104.9('):3
124.072
143.721
48.118
59,947
69,836
79, 97~.
}OCJ5
5.35?
7.551
0 ·3~1
11.?78
07E:
1 ~-. -·~
1. 130
6.482
s. f.81
10,521
12,408
44,.8~2
144
193
234
276.
2, 196
2, 941
3.564
4,2(13
88,476
113,Sf:l4
134,593
156.129
50.314
62.888
73,400
84,179
1 <>Ot.
5. 38:<
7.~·82
o .. 42~
11 '3(>'4
1.017
160
1, 177
6.560
S.75°
10. 5~·0
12.486
4t;.,270
142
189
229
270
2.077
::,773
:-<, 355
3,953
95,036
122.343
145,192
168.615
52.391
t.s.M.1
71;., 755
88 .. 132
1°-:::>7
5.415
7.614
<>,454
11' 841
1.058
1~9
1 f ~27
c-.642
8,841
10tb81
12,568
47,588
140
181:.
224
264
I, 965
2.616
8-,160
3.718
101,t.78
131, 184
155,873
181. 183
54.356
68.277
79,91:::;
91.850
!9¢8
:;'\,449
7, 64f•
9,488
11, 37~·
I, 100
176
1' 276
6,725
$,924
10.764
12~b5l
48.847
138
183
220
25Q
1,8M>
2.41:·8
2,97(;.
3.498
108.403
140. 108
1~i., 1:37
193.:::34
56.216
70.745
82.891
95.348
10-A
I OQ<>
5.605
7,85€:
9,730
11, ~.7o
1. 144
185
I ,329
6.934
9.187
11.068
12,~09
:50.135
138
183
221
259
1. 792
2,374
2 .. se.o
::;:, ~!5()
115o337
149.295
177,70'5
2oe .• 833
sa,ooa
73.119
85.751
98.707
2000
5.~42
7.895
9.776
11 '707
I .J90
195
1.395
7,027
~ .. :.'?80
11.161
13.092
51' 424
137
180
217
2SS
I ,697
2,241
2,696
3,162
122.364
158.575
188, 86e.
219 .. 92~·
59,705
75t360
88.447
101,969
10-A
1990 1991 1<>92 19'>:;l 1994 I~ t99t. 1997 1998 1 <><><> 2000
F. ACCt~ PRES WORTH OF ENERGY
P11LLS/KI.IH
Z't 1.2~ I. 3'5:;l I • 41 '!'i 1.473 1.526 1.575 1.620 I, 661 1.699 1. 73'5 J, 768
~~ 1.533 t.e.~ t.7o<> 1 '797 t.~s 1.923 1.9S3 2.03S 2.009 2· 131> 2,179
7'l. 1· 743 1.6~5 1.957 2.0~2 2.139 2.::zta 2.290 2 .. 356 2.417 2.474 2.52b
9'l. l ,955 2 .. 09$ 2,2()9 2.321 2-.423 2.516 2.601 2.£.79 2.751 z.sts ::z.sso
POWER COST STUDY
lNTERTlEO SYSTEM (15 COMMUNITIES) -ELVA ANO TAZIM!NA HIGH LOAO A ltema te lOB
1'>79 I '?~~~-l 1 ·~81 1 0'3~ 1 "'33 1'?84 198"5 1·~e~, t9<F 19t::-3 1'<89
I. LOAD DEMAND
DEMAND -n.; "5.074 6,050 -::r,,<, 7~66:' $.468 9,274 to.oeo 10.886 11 '692 !2,4"'8 1:.3,304
ENERGY MI.IH .::?0.888 :'7 ~ .,(_..,2 1 }1 '596 35.'572 39.547 43,52'.: 47.498 51.473 5"5.448 5".424 63.39Q
~ SOURCES no~
A. EX !STING DIESEL
LOCAT l IJN OR lIN fT 1 2.600 :~'/:,(H) :.:' /;.()!) • ,f::,!)t) ·600 ::~.:-.nn ~ • ~-(H) .::.; ; 1:•.1)0 .::.;, ( .... oo :::.~.no 2:.600
2 4, I <l. 14'5 4, t45 4.\45 4.145 4. 14'C· 4, 14'5 4' 14'5 4. 145 4, 14'5 4' 14'5
-c, -~ :'0 :?.'3(1 a-:~c) 8.30 830 .g·::.n '?3() :330 'J-:30 830
4
5
1-
7
R
9
10
1 1
12
B. ADDITIONAL DIESEL
UNIT 1 3,400 3,400 3.400 3.400 3,400 3.400 3,400 3.400 3.400 3.400
2 --::?,ooo 2.000 2.000 2. 0<)0 2.000 2,000 2~000
3 -----3.000 :3~000
4
5
6
c. EXISTING HYDRO
UNIT l
'"
D. ADDITIONAL HYDRO
UNIT I 1 ~ '500 1 ~ "5t)f'l 1. ~()() ! . ~;(It) l. 5()(\ 1 'c::-,(_)('1 l .soo
:::: -1 '3. nr)l) 1:3,r100 t::;-,oon I :3 • nt:':l) 1 '3~ Ot"10
3
TOTAL' •:APAC ITY -"1.1 7,-::;'') tr). 97"5 1•),',75 1 ~). •::>7-:=; 14.475 14.475 3::::.475 '32,.475 3~.47"5 3'5.47'5 J5.47'5
LARGEST UNIT 1 '8"30 1. :3 3<) t.:~30 t. 8'?0 2t3'30 2.330 t<>."5.20 1"'·'520 1 <';), ·:y:;o 1<;)·'5:20 ·;:n. 0..2(l
FIRM CAPACITY '5.74'5 ·>, 140• ·>, 145 ·:;>, 14'5 !2.145 12,145 1 z~ 0"'5'5 12· •:-J55 1.2, -:'~1)5 ! w:;. <'55 1'3.4'55
SURPLUS OR CDE:FICHI -I<W 671 3.09'5 2 • ..::8<~ 1' 4::::3 3-677 2,871 2· :375 :::.06° 1' :::63 3.457 :.::. 151
NET H~'DRO CAPAC! ry -MWH -:3, 07(: 3. t)'"~'i) ~4. t ':.{) '3~. !50 '34. !50 !j~. !50 '34 1 t-:•"~
DIESEL C•ENERAT !I:'N -MWH 20~ .3t~8 ;: I, 1:-21 3!.55'6 35.57:::: 31.471 ?!'5· 4~·2
108
19~(1 1991 1992 19~ t9<>4 199~ !996 1997 199$ 1999 2000
I. L.;•A[) DEMAN[)
OE:I"!AND -~W 14.110 15.2:)8 16.371::. 17.514 'l~h652 !9,7?0 20.924 22·0~$ 23.!92 24.326 25.460
(NE:t:<<:W -MWH 67.37!5 74.049 so. 723 $7. 3<>8 94,072 100.747 107.421 t 14. 1)96 120.771 127.446 134.,121
:!. ";(!IJRr:'ES -I'W
~-E~ I'HINQ DIESEL
I.OOHION OR UNIT I z.ooo 2,. )_"(H) ;:!,6t)0 ·~, f;.t)Q ;: ~ (-.f)!) ;:t ~ ... ('H"l 2.6(\Q 2.<1:-no 2~ 6Qt) 2.600 2tb00
: 4. 14'5 4.14!5 4. 14~ 4. 14'5 4. 14'5 4. 14'5 4t 14~ 4.14'!1 4. 14'5 4.14'5 4.t4'5
1 830 $'30 930 830 :330 S30 830 :330 930 830 :3)()
4
'5 ,_,
1
3
9
to
11
12
9. ADDITIONAL DIESEL
I_INI T l 3.400 1.400 3. 40•) 3.4()0 3.4(10 3·400 3.400 3.400 3.400 '),4(10 3.400
--;:,ooo 2.~000 2.000 =·000 :.ooo ;:,(lOt) ::?,000 ~. ()t)O ;:,f)f)O ~.ooo ~.001")
~ 1.ooo '3" '.,"\()() ·).000 3.000 3 ,.l)fH) 3.000 3.000 ·],1)00 3.noo '), (>00 '"O(l()
4 -2-.:0f} 2.200 2.200 ~.2('1t) 2.200 2.201) 2· :'Ot) :.::oo 2.200 : • .:oo s
6
I:'., EX l"3TIN!J HYIJRO
I'N(T I
=
D. .::\[1[) tT II)NAL HY[lRO
I)NIT I I, 500 1 '~()t) 1.50Q 1.'500 l ~ '500 1 ;5('1(1 I , '500 1 • ":,()(\ I , '500 I , '500 1. 50()
= 18.000 13.1)0(1 te.ooo IS. 0<)0 1 ::;: ~ ('H)t) 13 .. 000 t :; I Ot)(l 18 ~ t.,'h)O !:":!. 1)00 Jl~' 000 18. (H)(l
3 ---18.000 18, (H)O !8. 0l)0 18.000 1 8: ~ ()(H) 1:3,<)0n 18.000 18.1)01)
f(lT.O.L CAf'!Oir.ITY -I·W J5.47~ 37 •• :~7~ 37.~7'5 '5'5.67'5 ~'5.67'5 "5'5~67~ 5'5~~75 0:::"5 ~ l-, 7c:; 5-:o. 1:-7~ -:.-; • .~;.7~ '55.675
L :.r;·•'E·:.r •ml r ~o.o:o :o. l);,;f) :-o. c):o I I , '5.:0 lt.a;,,:('l 11. -;:o 11~'5.:'0 1:. o::r) 1:. !''l,:'O 12. (1~('1 1::;.n~o
r 1 R., ,-iOIP.:~•: r rv tS.4'5'l 17,~..-.~.a; 17 •. ','5~ 44. 1'5~ 44, 1C:.5 .!4, 1'5'5 44.1~-=-4"), 1::-5'5 4 .;:.o:.~ 4 3.6':.5 43.65~
~I ·~PLtl'; OR IOEFIC!Tl -I W t.34"i ~.417 1. 27<> 2'o.64! :5,~03 :;::4. %'5 -~3. :'31 21.-:,<~7 .:-~~~41:-5 t'4~':t~"' 13, I "'5
><Ff H'I[<R(o I~APAr. !TY -MloiH 84' 1~0 "14. I 'SO 84. I '50 1 \ ~. 4~{0 115.430 11'5.4'30 11:5.430 11:5.4~<) ll '5. 4 Jl) 1 P5. 4·:'!0 II '5, 4 'rl
0! ESEL GEMO:R> T1 014 -MWH ---------':J, J41 1:;::.016 18,1:.<>1
lOB
1 •:;>7Q t~SO 1"81 1 0:3~ 1 ·7;1:?'3 1'984 1Q8") 1'>86 1':<87 t·=>·~B 1'089
3~ [NVE3TMFNT ~OSTS I $1 r'H)())
197<> DOLL;::.R-o.
A. EX !STING DIESEL 5.862 '5.86:2 '5.862 51862 5.862 C:St862 5~86~ 5.86~ 5~:362 5,862 5-862
B. ADDITIONAL DIEc.EL
IJN!T 1 ::.9':\8 2,-::,-:;8 ,2.Q58 2,'9'58 2.95B 2,958 2.~58 2 ~ 95:3 2,'?SS 2.9~8
:: l '740 1, 740 1 '740 1 '7 40 1 '740 1 '740 1, 740
",:! :::.610 2·610
4
c:
s
<::. EXI·~T!NG HYDRO
D. ADDITIONAL HYDRO
IJNIT l -1::::: ~ '-14!) 1 ,-::>41) !2-0 40 12 .. •::,4() 12-.'::>40 12? •;:,40 t-' ::;'l.olr)
::: -5r). :3;:::1) '50~8~(1 5i). 8:::':0 cso.s:::o '50~8~t)
3
E. TRANSMISSION PLANT ADDITIONS
tJNI i 1 --4,<;175 4,·n5 4,975 4.97'5 4,975 4,975 4,975 4~ •?75 "· ·?75
::>
F. MISCELLANEOUS ADDITIONS
UNtT 1
2
Tr')T~L 1 $1000
t·:;)"'l''"",; DOLLAR·::. -:; ~ :?,/:.::. 3. s:o 131 7'~5 13.7<>5 .:::3. 47'5 ~>.47') 1'9, 2'?C) "1•-:)1 ,29'5 '7Q,;:q-:; :?t ~ •'?05 81..-<>r)5
! ~JFLATED 'J"'LUES '),36: <:)7 ('\~] 14-860 14.:360 3-l •. 3"3'.: ?4. :332 1 1 .4°0 tt:.aqo 11~.4'"'0 116,·~76 ue,.976
4. FIXED (tJST t t:l O(H) l
INFLATED VAL'.'E'3
.:.. I:'•EBT 3ERVICE
I. EX ['3TIN(; :JR :c·::::3 ~:~"8 23S 238 2.?8 ~~~
.:..,JO 238 :238 2];3 .:3s
-. ADDITIONS
'31.:BTOTAL 2'%. -1:28 360 360 1' 159 1' ['59 4,165 4.265 4.265 4,444 4.444
~"'. 1 '4~, ~4Q 54"' I, 753 1' 753 6~4::6 6.426 <:,,426 6~7'00 6.700
7'' 247 6.;-;~ 6°5 2.237 .237 :3!235 :3,235 3): 35 :3.581 2~581
Q~~ :o:: :3'51 8'51 2.741 2,741 10.0'>0 10~ <)<:::>O 10 .. 1)·.)0 t(L5!'5 1:).';15
B. INSURANCE [:3 :·:; '52 '5.~ 142 1 '5·4 '516 '5 ~·<':> r:."58 .st.'~ ..... ;:7
!ST4L ~t~ED COST tS100Q~
::?'l.
":./~
rr.
~·t.
5. F>ROOUr::'TI O~J COST ( t; J 000 l
INFLATED VALUES
A. OPERATION AND MAINT
1. DIESEL
Z. HYDRO
B. FUEL A"'O LUBE •)! L
TOTAL PRODUCTION COST <'1100"
TOTAL ANNUAL •~OST ('11000)
.::z.
5'l..
n:.
·~:t.
ENERGY REQ!J!REMENTS -l't!.IH
l't!LLS/n.JH
:::~
5"1.
7''
~~~
C. PRESENT wORTH
ANNUAL COST <'IIO<)Ol
2%
':'~
~··
,:.~~.
0 .. A('('I)MUL .. .ltJN.,. COST (til()(;(')
'5 ~~ _,.,
.. ~·-:
•::. ACCt'I"ULATED f'·RE''E'H WC•RTH
aNNC~L ~0·?T ;~I 1
"'"') ~:
7'"~
,.':.
1"!:J"!~
~'56
2'5~
2'5"
.::-:::.::.
651
1' 69'5
2.341:>
~ .sn-:!
, .~o:::
~60:
'60.2
:20,:388
125
L?5
l ·o~ --· 1.:::5
~. 6l1~
;c, 602
:;,6(1;?
~-61)~
• 1~1):2
• 61):!
'/:>112
. 602
--. /c-' ~~.;.:.: . -~ ~··.::
:.':. -S(l::::
~·<.'"
J080
?'?':,
41,,2
514
56Q
':4:;:
~.466
.308
3, 7r13
3-77(!
3,822
3.877
27.62t
134
136
1 '8
14(l
3.4"1
', c;:;:-,
"· -:.7::
:t.623
,;. I ~:0'5
6.372
6~424
6,47~
::~ •)f:, 3
';., 1.2~
..... 174
1981
-~."5()
83~
98CS
I, 141
·~4(}
2. /~"Sf)
"J,S:,01)
4 .. :240
4~42">
4.'57'5
4.731
31, '596
134
140
145
1'50
3,7()3
3.868
y. <:!•':/!;,
4. 132
10.'545
10~801
10.QOQ
11·210
·::. ......... <L.,
) • <)•J?
1 r). 170
! li. -~=·...,.
1>78:?
~">':·4
343
=>::.3''4
. 145
1,tl50
3.281
4. 311
4-.-=>85
':,, 174
'5. :320
'5-.476
35.572
140
145
150
1'54
4~o.s~
4, 224
4, 343
4. 47(l
15. '53(1
1'3.<>75
16.819
16.6S6
t ~. :~3'5
~ 4 • .:: I 7
14.'::13
14 ,.::7
1"83
.5·-:::<>
' 1JC•
.617
• 121
8'24 .,
?: • 1 '44
4.0::::5
5, '=·~-4
"· 158
I;., 64~
7' 146
39,547
141
1'56
!6S
181
4.;;:4'5
4~6-:)8
"5.0(;.7
'5.4'5::?
-:!.1. !)';)4
.:::::. 133
~2.~61
23.:332
1S.n8Q
18,015
1~.~80
~0.27°
I '7<34
I • '5'5!
:.14'5
:~6.::9
• 133
·::>·.::-·~
7
3. ?51,:.
4.8":'12
6.443
7.037
7t5~1
3.0.25
43.5~~
148
162
173
I'~"
4.'594
c:;. () 17
.,. ' =~·'-" 2
"'"""' '5~"'7
::.-:>. 170
~.: •. 48:::
?!.8'57
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10 • .344
c:',<:')".;)
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7n3
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7.88
·::)~ 60
11.547
47.4':;,8
1~0
166
:;r)4
;':4:3
7.:31 3
-::. ·.::::~3
,4'58
7.,.?4
3J.:~~
)7.05J
41). 174
43.404
2~.487
~0 !:~5
~!.41~1)
)J.6~5
1'~<:'?6
-:;, <)39
7.~00
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1 '). 864
1.:·2'3
11 3
736
:..77~
7,Q36
0,74~
11.60()
51.473
1 I '2
154
139
2~5
),5">6
4,Q42
.:,. t)6':}
7,224
1'2 .•)34
44. ~8?
4Q.Q1~
5S.004
-:'0. i1'3'3
~<4. 1 ·::7
?.7. 4f:-':3
4r""t. ·:>-: -:-
I"'B7
'5. •)61
'71 ~ 0'31
!t), .386
71"
121
!~'?'A
5-897
:3 .. 0"58
I')~ :3t.7
11.7'22
'55.44:3'
106
145
178
:::: 1 1
3~43~
4~6-::)0
11).743
~ .. :~:::'
44.">'31
O:S~.047
':'"~ 786
'::-6, 726
'515
• :31 ~
4 '· ::1.~
.!1.7. 74 t
l •>'38
.:::. :s-::.
7.'541
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tl • .356
743
131
:?"74
6· 15?
8.415
t0.2q~
t~.:·Jo
s·:;,. 4:2'4
104
142
173
206
'),3'50
4.,.577
5.600
6·65'2
~t.o~n
61.461
70,08:
7$ .. ·::)~6
~~-86~
a 7. J·'4
4:~-~t.::
c4. J~3
108
1"'89
'5,3<)0
7.56'5
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o3, 477
10.'3'58
t:.~o";)::
63.3?~
Q:=:t
1'34
163
1'~4.
3,162
4.30"
5.265
6,;::49
57, 311
6~.93'4
'30,440
">1.248
4:'1, n:;7
.1 ............ )~
S4, <)"77
.. >4::
or:f("'"l •) OJ ~ ,......._(, ((• 0 c -,., <t t:r· 0 <til' .lj ()-"''"'" 0 f'J_I •) 0 (.j '" 0.'
0
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0 .. 0 ,.._ ~ r. -f<
("
0
ll'·<t w " " r··· c 0:•
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~
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tr•" "' (j
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" <t " ...(•!", Q) Q)
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'"
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"
lOB
1990 1<><>1 1-:)q:;: 1 :?""1 [<>94 1"'"''5 1'::)'06 1997 1-:)QB 1999 :r:liQ
1. INVESTMENT COSTS ftll000l
P79 DOLLARS
A. EXISTING D!E3EL '5.362 '5.1362 '5.862 "5,;362 ~.:362 ~ .. 362 ~ .. :3o.2 '5' :362 5.862 5.:3b~ "5~362
B. ADDITIONAL DIESEL
IJN!T 1 z,q~e 2.<1!58 2.9'58 2.9'58 2,9':\8 2.9'58 2?~"58 2,'?58 2,9'58 z,qc;a 2.~S8
2 1.740 1. 740 1,740 1.740 1 '740 1' 740 1 '740 1. 740 1, 740 1. 740 1 740
1 2.610 2,610 2.610 2~610 2.610 2,610 2.610 2.610 2.610 2.610 ::.610
4 -t. <>14 1. 0 14 1."'14 1 ·"'14 1,914 1.914 1·"'14 1.914 1, 914 1. 914
'5
6
r:. EX !STING HYDRO
ro. AODITIONAL HVORO
UNIT 1 12.94<) 12.<>40 12.<:>40 1'2, ·~40 12."'40 12,940 !:::.·?40 12. •:)4t) 12.940 1.::.?40 1 _:, ·:J4r)
·~ 150~820 ~0 ... 82r) so~B2o '50.820 50 .. 8:20 -:.0.820 ':·0·8::0 5n,:320 -::;ols::o 51'~. :320 50. :3~0
3 --4'5.774 4'5.774 4'5.774 4'5.774 4'5.774 4'5,774 4'5.774 4'5.774
E. TRANSMISSION ~LANT ADDITIONS
I,.INIT 1 4,<>7'5 4.97'5 4,975 4,97'5 4,Q7"5 4,975 4.~7'5 4.'?7'5 4,·ns 4,07'5 4,975
:?
F. MISCELLANEOUS ADDITIONS
UNIT 1
:::
TOTAL < s I 00•)}
P79 DOLLARS 31,90'5 ~~3tS19 83.~t·~ 1 :2Q. '5·~·~ 1~"4.5':)? 129.593 1:::9,"593 1:29,59'3 t:Q,'5Q3 12"'-59'3 1.:.':-Q, ~·:)3
INFLATEO VALUES 116,976 I :•), 677 120.677 216. 4<)5 21/:.40'5 ::t6.40'5 216-405 :216.405 !6.405 216.405 .::16,40'5
4. F IXEO COST < s 1 •)00 l
INFLATED VAL LIES
A. DEBT 'SERVICE
1. EXl'HING :38 ~:38 238 238 ::38 ~:::8 ::3:3 :2J;:;:~ :2'38 23:3 238
~ AODITIONS
·:OIJBTOTAL 2% 4.444 4.,"59Z 4~5Q;.': o3, 421 • .s::l :.::.~ 421 .>,4:::! c3, 421 8,4~1 3' 4:21 :3.421
«" J'• 6.700 6. ~26 6,?:26 ! ,.2, 6:..~~ 12.686 1·:~ 68:~ 1:. ~.::-:3:;. L.2'1 .f:..:~6 l2,636 t,2, 6:31-... 1.2' 686
7'1. 8.581 8.867 :3d367 16· 2·>0 16. ::6l"~ 1 /;, ~ :60 t6. :.~o 1 A~ 2C."\) 16 • .:?<:.0 16· 2C.O 16.260
'::)~ 10.'515 10.865 10,::365 1 <:>, q-::;4 tO~·;;J-24 1'~~ 0~4 t.-.:> ~ ·.:)::4 19, 024 i':J. ·;)24 t•:'l,<>~4 I'"• 0 24
e. INSURANC'~ 6'5:2 7(;1) 728 1. ·;';:? \. 4 t ! • A.~-:) 1, 5::~ t .'588 1 , I. 71? ! . -;-;::. 7
T•)r~L FIXEP -~~sr $l
'"}·~
'5. P»OOIJCTION COST 1$tOnOl
INFLATED VALt.IES
A. OPERATION AND MAINT
1. DIE:El
;:::. HYDRC•
B. FUEL AND LU8E ~IL
TOTAL PRODUCTI'JN COST r~1
TOTAL ~NN!JAL COST tstnon
24
'5%
7%
Q%
ENERGY REQUIREMENTS -MWH
MILLS/kWH
2~~
'):~
7'"~
·:-;·;.
C. PRESENT WQ~TH
ANNUAL (OST <•l~OOl
~·~
'='' ~~
~··
.:)"~
D. C.I~(I_IMIJL~ ANN. COST t ~1
5~~
o·~
~·-( '":MULATE:D F'h.'E'::.E"J T ••• n:~;;;;,. L.t
2.~~t4i_1AL ( f'i·~. T ,. f.!··
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1 t). 4~11
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67 • .:?75
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127
15'5
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:,·:J:-37
4. tl':.O
4 .. ",')~
C).87t
1"3, C)QB
78.482
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11)J' 60~
\-l ,,
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'C
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..... , =":'64
"1, }1)5
: 1, .·::n)3
i1 .. :;2
4~:-3
.5~8
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1 • 80:3
1 801
74.()49
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120
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t7'?
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•)'::-:,
4 ~ 7•"';) ·;-
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t •J":'
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t:::,S~'?
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to. <:>t.:.o
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83
112
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743
4. '54'~
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7~. '11
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11.2· >27
t.=·:) 3/:.5
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=» • .lol(\
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l':J.2
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15.41:-:
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87 .. 398
1::8
177
1:3
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4, ~4.:
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7. '8::
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'?!.::. i)r:l:::
1 1-3:5
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21.'574
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10, 3"5:2
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:~.-;)6
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4,451
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1 > 45()
11 , 1-:J/:..
1 '5' ·~(11
1·~.47"'
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1"_)~7
1 '247
14.51
1:3.
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1 . :;-:; J
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11.764
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1~".)·::.,>::;.:
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14.
1:::5 ~
-::1' 14
1. :::~"5
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1 3. s-:·:)
17. '5'>4
1· tf:-8
24~8:?2
~4 .. 072 1007747 107,421 114,006 120.771
120
1&6
204
24:::
4,tl!J8
., • ·0 44
~. ~j¢
::.. ::.):.7
~0 .315
1~7.207
150,300
174.875
7' ~ '1:>"3•)
">•7Jc;
114
1'57
1Q2
228
3· •:::>()0
"';.?.4'5
~-·'55":-;
7. :"Q(-:-
1 1"• •. 3:'3
14 ?. 175
t7{1~t.S1
1'77,?.".:J1
·:-1. ('127
"'!/:, • .t.::-:;
;;>•:), .:~"
108
148
181
~1'5
3. 6,34
"'5,0')4
A. 1S'5
7.3.2'5
1 ::.: • .U.4
1 "5•.:t. (Y7.~.
1:3-:>. ·=-"'36
2.21 :)._30
.',.t. 711
103
140
17::
;::<)4
3.481
..;,742'
5.sou
~. -3:84
: c4. ::::·c,
t 7'5 • I <)'5
:>)..::0' .::-·?•"';)
:::.;~ .. ::·:)"'?'
' 1-:)_2
110
146
17'5
:2('.~-
3. 6:31.=.
4' :3JS5
'5. :::;c:-::
1: •• '":!r• ,..:.,
147,'5'57
10~,69~
230.4c)7
.:::~·~-1~9
""! t l :_37':j
}1, 45·:::. ':?6. ::r)i •)1, ()i-.6
J~. 415 ! ·: 1. -! 5 1 () 7' •• :t.:3
~' <:::.! ":'::
-::t/7'
14-lA~
! !? ' ;: 1 !:;
21 • :::::;u)
t. '57(')
.::!::?,
?. :"14
'3. ;)7:
15.44~
J?,714
23·288
~.~2
lOB.
::::•}t)(l
10. 44-~.
14. 711
18, ;:·:::~
.21 ''-=14•::)
1. 7"5'4
JOO
'5~301
7,?60
t?.ao6
:''2· 071
:'5 •. ':-.45
::·?. 30·~
t.::7.446 1?4.\21
121
!55
\81
::'11
?. ·:~v_:
'5·0"'4
':··
•JI:··~
1::. ?. 1"'1!)6
··t.:c. 41
.'2'53· -~·4-:.
.:::·~6.081
-cs. :j70
::>::~.' l ·":-('l
! \ 0 • o):O• C
13:3
165
t"l
:::t·>
4.300
5.330
;,. 1'~4
7 ~ •)7'4
: :jt). :31 2
234.484
.::·#' 340
3'.25, ]':)I)
• 1 7i)
1 • ~<'};')
~ 1 •:}'
:.~.:t.~·.44 !•l:.-Lli''i t::--:<).7,::_.'7\ 11-s •.. -l'::J 1.:: 5!'5 t~~~.a:_,f'l lJ"l',~,.:::-··_,
Hll
!990 t<><>t 19Q2 19<>3 1">'>4 lQQt; 1 Q·~;;, 1.-:;)~7 1">"'8 1Q'4Q :ooo
F. ACCUM PRES WOPTH OF ENERGY
MILLS/I<WH
27. 1·0'58 !.097 1. 131 t. 181 1~2~4 1. 263 1 t 297 1' 327 1. 3'57 1. 388 t.420
'57. 19223 1.276 t.322 t •. 3"Ql !. 4'51 lt '504 1 y ~~1 1.'5?~ 1.'>32 1 ~ ~7Z t.7t:::
77. t. 363 !.428 1.484 1 ~ ~6~ t. 643 t. 7(18 1. 7t,S 1.81!;, t ~ 81.:.4 1. ') 1 1 I, :>'57
97. t. !50S 1 .~92 !.649 I, 7'50 t,:;ng t ,91'5 !,983 2.043 z. !00 ::. 1 '5~ 2.208
•" ~~ .
APPENDIX D
ENVIRONMENTAL IMPACT/LAND STATUS
Dillingham -Appendix D
APA013/J
APPENDIX D-1
STATE OF ALASKA
DEPARTMENT OF FISH AND GAME
LETTER OF JANUARY 25, 1980
D-1
(I i\', Cl .. j-.ir;) ,, .J, ,,.J
J . \ I . : ___ ~
'. , ' L .... -<
• f \ . / '.
i •.
DI:P~RT MI:NT Ot' t'ISH t\ ND G~ ME
January 25, 1980
Robert W. Retherford Associates
P. 0. Box 6410
Anchorage, Alaska 99502
Attention Dora L. Gropp, P.E.
Gentlemen:
' UJ RASI'BEIIRY RIIAII I A/JCHIIRASE.. '
tj '···
Re: Assessment of Fish and Wildlife Impacts of Hydroelectric Development-
Lake Elva, Grant Lake, and Lake Tazimina
Per your request, presented here are comments regarding possible fish
and/or wildlife impacts resulting from hydroelectric development of the
Lake Elva, Grant Lake, and Lake Tazimina sites. You understand, of
course, that these assessments are superficial in nature. To adequately
address probable impacts requires considerably more effort in the way of
review of project plans and also site specific field studies. Please
bear that in mind when using this information.
Elva Lake
Elva Lake provides habitat for char and Arctic grayling but is not
utilized by anadromous fish, however, sockeye salmon spawn in Elva
Creek, the lake's outlet stream. The upper limit of spawning is at the
impassable falls located approximately one-fourth {1/4) mile upstream of
Lake Nerka. Sockeye spawning also occurs in Lake Nerka in the area
surrounding outflow of Elva Creek and elsewhere. The annual average
escapement of sockeye salmon in Elva Creek is about 350 fish.
We assume that with construction of the dam on Elva Creek, inundation
and subsequent loss of some terrestrial habitat will occur. The information
provided does not indicate the extent of flooding so it is hard to
predict the consequences with respect to the displacement of wildlife.
With respect to fisheries resources, we expect that detrimental impacts
will occur if the thermal regime or flows in this system were significantly
altered. Likewise, supersaturation of discharge water with gases,
especially nitrogen, are known to have grave results in fish. Grayling
and char spawning habitat in Elva Creek would be inundated. The location
of the penstock discharge at a Lake Nerka beach spawning area could
exclude that area from use by fish.
Retherford -2 -January 25, 1980
Grant Lake
Grant Lake is similar to Lake Elva in that it has a resident population
of char and Arctic grayling. Likewise, impassable falls prevent anadromous
fish from reaching the lake. The majority of salmon spawning takes
place below the discharge point of the proposed penstock. ·Records since
1959 indicate that Grant River has an average annual sockeye escapement
of about 19,000 fish, with a record high of 67,000 fish.
Concerns with this project are identical to the Elva Lake proposal.
Water quality, quantity, inundation of terrestrial habitat and location
of penstock discharges in important spawning areas represent the potential
impacts.
Tazimi na Lakes
Tazimina Lakes ~reutilized for grayling, char, and Dolly Varden. The
Tazimina River 1s utilized for spawning by sockeye salmon, rainbow
trout, and Arctic grayling. Average annual sockeye escapement is about
160,000 fish.
Raising lake levels would inundate resident fish spawning areas in the
river which connects Tazimina Lakes. In addition, this river is a
popular angling area. Terrestrial habitat would also be lost with
subsequent displacement of animal populations.
As with the other projects, water quality, quantity, penstock discharge
points, etc., could all detrimentally impact the fisheries resources of
the area.
Perhaps one aspect of all the proposals that is of as much concern as
the generating facilities, is that of transmission lines and access
roads.
Public use of these roads will vastly alter fish and game utilization
patterns in these areas. Many of these areas are currently supporting
as much hunting and fishing pressure as they can maintain. Ready road
access might contribute to serious decline in the quality and/or quantity
of area resources. Areas that are particularly important are the Wood
River, Tikchik Lakes, Kvichak River, and Iliamna Lake regions. These
areas are very productive fisheries resources and also provide a high
quality sport fishery. With that in mind, consideration should be given
to constructing these facilities and transmission lines without access
roads or devise means of limiting access.
Some mention has been made of underwater transmission lines. If considered,
a survey should be made to learn whether their placement will disturb
spawning areas or migrational corridors.
In addition, roads and/or powerlines may affect the movements and
distribution of caribou. Disturbances of this nature could be quite
significant to area residents who rely on these animals as a food source.
Retherford -~-January 25, 1980
Most of the impacts that have been mentioned so far can be considered to
be long term. Some short term impacts, primarily construction related,
might be temporary erosion and stream siltation, reduction in air quality
from dust and exhaust fumes, animals displaced from construction area by
disturbances caused to equipment, etc.
As mentioned previously, the identification of these impacts at this
time are speculative. To precisely identify fish and wildlife impacts
would require additional studies and specific design information.
Once again, please be reminded that the Fish and Wildlife Coordination
Act requires you to consult with the U.S. Fish and Wildlife Service and
the ADF&G with the view that prevention of loss of fish and wildlife
resources and mitigation of losses shall be treated with equal consideration
as are other phases of the project.
We would appreciate receiving copies of the feasibility report when it
becomes available and also wish to be apprised of further developments
with respect to these projects including all public meetings.
Thank you.
Sincerely,
Ronald 0. Skj cz::~ _
..__ .......... , Bruce M. Barrett
Projects Review Coordinator
Habitat Protection Section
Dillingham -Appendix D
APA013/J
APPENDIX D-2
STATE OF ALASKA
DEPARTMENT OF FISH AND GAME
LETTER OF MARCH 4, 1980
D-2
0 1LH
DEPARTMENT OF NATURAL RESOURCES
DIVISION OF PARKS
March 4, 1980
File No.: 1130-13
Subject: Lake Elva, Grant Lake Proposals
Dora L. Gropp, P.E.
Project Engineer
R. W. Rutherford Associates
P. 0. Box 6410
Anchorage AK 99502
Dear Sir/Madam:
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OND, GOVERNOR
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619Warehouse Dr, $uite 210
A-hcnorage, Alaska 99501
Ct ., :'"":' -/ . ("'" i
We have reviewed the subject proposals and would like to offer the following
comments:
STATE HISTORIC PRESERVATION OFFICER
Past archaeological experience indicates these lakes to have a high probability
of containing significant cultural resources. Therefore, per AS 41.35.070 &
36 CFR 800, preconstruction archaeological surveys are recommended.
;t/~/4#~
William S. Hanable
State Historic Preservation Officer
STATE PARK PLANNING
The Lake Elva hydropower project is designated a compatible use in the Wood-
Tikchik Park's enabling legislation. We are, however, concerned about trans-
mission lines and associated infastructure related to the project. A master
plan or management plan for the park has not yet been developed by the park's
advisory management council due to a lack of funding. The existence of such
a plan would help to determine the location and design of structures and facil-
ities related to the project. It is our hope that such a plan can be prepared
prior to detailed planning for the Lake Elva project. The advisory management
council for the park was established in the enabling legislation for Wood-
Tikchik. The early involvement of the Division of Parks & the council in a
project of such magnitude would appear to be both appropriate and consistent
with legislative intent. The Grant Lake project is not mentioned in the park's
enabling legislation and would thus constitute an incompatible use of the park
under current law. However, 11 AAC 18.010 provides for the issuance of incom-
patible use permits by the Director of Parks.
Ha1ch 4, 1980
Dora L. Gropp, P.E.
Page 2
LWGF
No comment
CD/nw
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650
600
550
500
450
400
156° 154"
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156" 154"
LOCATION MAP
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POWERHOUSE /
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300
8 9 10
152°
FORE BAY
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NOTE:
Dashed contours enlarged from Lake Clark (A-3),
Lake Clark (A-4), Iliamna (D-4), and Iliamna (D-5)
Quadrangles
Figures within lakes are bottom elevations
TAZIMINA RIVER LAKE
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RESERVOIR
DAM
LOWER TAZIMINA LAKE
RESERVOIR SITES
SCALE. 241XXJ OR 1 INC H~ 21XXJ FEET
0
CONTOUR IWERVAL ON LAND 20 FEET AND 50 FI:F-1
CONTOUR I NII:.HVAL ON t.!IVE~ SURfACE ANO UNDERWATER 5 FffT AND 20 FEfT
DATUM IS MEAN SEll LEVEL
NORMAL M~X w.s. 675,... '
LOWER TAZIMINA LAKE
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13 14 15 16 1717
350 DISTAN CE IN MILES FROM RIVER MOUT H
18 19 L 12
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20 21 22
PROFILE
VERliCAL SCALE INCH= 100 FEET
HORIZONTAL SCALE 1 INCH= 4000 FEET
ROBERT W. RETHERFORD ASSOCIATES
ANCHORAGE. ALASKA
APPROVAL RECOMMENDED BY: SUBMITTED BY:
DESIGN BY:~C.!:!_H ~S ~----
DRAWN BY: ..tJl!IMI.lBL. ____ _ DL GRODP
ENGINEER PROJECT ENGINEER
CHECKED BY: ~C~H~----1
SUPERVISED BY: DATE: JAN 1980
NATURAL W.S. 655/'--.._
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+
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26 27
350
24 25
300
23
NO DATE REVISION BY
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LOWER TAZIMINA LAKE DAMSITE
lOCO 0
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"''~IMINA RIVER
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SCALE I 9600 OR INCH -BOO FEET
CO N TO UR I NTERVAL ON LA ND 10 FEET
DATUM IS MEAN SEA LE.,.EL
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UPPER TAZIMINA
LAKE WS 71'5 ------
-----1 700
fi50
--1--600
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28 29 30
ALASKA POWER
AUTHORITY
ANCHORAGE ,ALASKA
-
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31 32
400
33
550
500
450
34 MILES
TAZIMINA HYDROELECTRIC PROJECT
2 X 9 MW FIRST STAGE
PLAN AND
1"1 ROBERT W . RETHERFORD
DRA!ING FILE' 9 7 03-4
PROFILE
ASSOC. SHEET
OF
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